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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, 2014
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.)
1250 W. Washington Street, Suite 300
Tempe, Arizona
(Address of principal executive offices)
 
85281
(Zip Code)
(Registrant’s telephone number including area code)
(602) 302-5450
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 30, 2014 (the last business day of the registrant’s most recently completed second fiscal quarter) was $1,515,661,445.
As of February 26, 2015, Northern Tier Energy LP had 92,832,210 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, 2014
TABLE OF CONTENTS
 
 
 
Page
 
PART I
 
 
 
 
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
 
 
 
 
PART II
 
 
 
 
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
 
 
 
 
PART III
 
 
 
 
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
 
 
 
 
PART IV
 
 
 
 
Item 15.
 


i


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
Certain statements included throughout this Annual Report on Form 10-K in particular under the sections entitled Item 1. Business, Item 3. Legal Proceedings and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations relating to matters that are not historical fact are forward-looking statements that represent management's beliefs and assumptions based on currently available information. These forward-looking statements relate to matters such as our industry, business strategy, future options, our expectations for margins and crack spreads, the discount between West Texas Intermediate ("WTI") crude oil and Brent crude oil, pricing and availability of crude oil in the Bakken Shale and Canada, distributions, capital projects including the timing, costs and impacts thereof, liquidity and capital resources and other financial and operational information. Forward-looking statements also include those regarding the timing and completion of certain operational improvements at our refinery, growth of our retail segment, timing and cost of future maintenance turnarounds, future contributions related to pension and postretirement obligations, our ability to manage our inventory price exposure through commodity hedging instruments, the impact on our business of future state and federal regulatory requirements, environmental loss contingency accruals, projected remediation costs or requirements and the expected outcome of legal proceedings in which we are involved. We have used the words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could”, "assume", "budget", "intend", "may", "potential", "predict", "will", "future" and similar terms and phrases to identify forward-looking statements, which are generally not historical in nature.
These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. In addition, our expectations may or may not be realized, and could be based upon judgments and assumptions that prove to be incorrect. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
the overall demand for hydrocarbon products, fuels and other refined products;
our ability to produce products and fuels that meet our customers’ unique and precise specifications;
the impact of fluctuations and rapid or prolonged increases or decreases in crude oil, refined products, fuel and utility services prices, renewable fuel credits and crack spreads, including the impact of these factors on our liquidity or financial performance;
changes in the spread between WTI crude oil and Western Canadian Select crude oil;
changes in the spread between WTI crude oil and Brent crude oil;
changes in the Group 3 6:3:2:1 crack spread;
fluctuations in refinery capacity;
accidents or other unscheduled shutdowns or disruptions affecting our refinery, machinery, or equipment, or those of our suppliers or customers;
changes in the cost or availability of transportation for feedstocks and refined products;
availability and costs of renewable fuels for blending and RINs to meet Renewable Fuel Standards ("RFS");
the results of our hedging and other risk management activities;
our ability to comply with covenants contained in our debt instruments;
labor relations;
relationships with our partners and franchisees;
successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;
our access to capital in order to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
dependence on one principal supplier for retail merchandise;
maintenance of our credit ratings and ability to receive open credit lines from our suppliers;

ii


the effects of competition;
continued creditworthiness of, and performance by, counterparties;
the impact of current and future laws, rulings and governmental regulations;
shortages or cost increases of power supplies, natural gas, materials or labor;
weather interference with business operations;
seasonal trends in the industries in which we operate;
fluctuations in the debt markets;
rulings, judgments or settlements in litigation, tax or other legal or regulatory matters;
changes in economic conditions, generally, and in the markets we serve, consumer behavior, and travel and tourism trends;
execution of capital projects, cost overruns of such projects and failure to realize the expected benefits from such projects;
the price, availability and acceptance of alternative fuels and alternative fuel vehicles;
operating hazards and natural disasters, casualty losses, acts of terrorism including cyberattacks and other matters beyond our control;
changes in our treatment as a partnership for U.S. federal or state income tax purposes; and
other factors discussed in more detail under Part 1. — Item 1A. Risk Factors of this report are incorporated herein by this reference.
Any one of these factors or a combination of these factors could materially affect our financial condition, results of operations or cash flows, and could influence whether any forward-looking statements ultimately prove to be accurate. You are urged to consider these factors carefully in evaluating any forward-looking statements and are cautioned not to place undue reliance on these forward-looking statements.
Although we believe the forward-looking statements we make in this Annual Report related to our plans, intentions and expectations are reasonable, we can provide no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we currently believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. The forward-looking statements included herein are only as of the date of this Annual Report and we are not required to (and will not) update any information to reflect events or circumstances that may occur after the date of this report, except as required by law.

iii


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;
6:3:2:1 crack spread” refers to the approximate refining margin resulting from processing six barrels of crude oil to produce three barrels of gasoline and two barrels of distillate and one barrel of asphalt;
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” abbreviation for barrels per day;
Catalyst” refers to a substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process;
"COBRA" refers to the Consolidated Omnibus Budget Reconciliation Act, which is a federal law that provides many workers with the right to continue coverage in a group health plan;
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;
PADD II” refers to the Petroleum Administration for Defense District II region of the United States, which covers Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee and Wisconsin;
Refined products” refers to petroleum products, such as gasoline, diesel and jet fuel, which are produced by a refinery;

iv


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.


v


PART I
In this Annual Report on Form 10-K, all references to "Northern Tier," "the Company," "the Partnership," "NTE LP," "we," "us," and "our" refer to Northern Tier Energy LP and its subsidiaries, unless the context otherwise requires or where otherwise indicated.
Item 1. Business.
Overview
We are an independent downstream energy limited partnership with refining, retail and logistics 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, 2014, we had total revenues of $5.6 billion, operating income of $275.3 million, net income of $241.6 million and Adjusted EBITDA of $430.7 million. For the year ended December 31, 2013, we had total revenues of $5.0 billion, operating income of $246.1 million, net income of $231.1 million and Adjusted EBITDA of $370.6 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 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," "the Partnership" or "the Company") to the public. In November 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 a 97,800 barrels per stream day (“bpsd”) 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.
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, 2014, 2013 and 2012, approximately 37%, 50% and 47%, 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 6.4 million bpd from 2013 production of 3.5 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 1.2 million bpd as of December 2014, and is currently 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 85%, 80% and 80% of our total refinery production for the years ended December 31, 2014, 2013 and 2012 was comprised of higher value, light refined products, including gasoline and distillates.
We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities, the Aranco and Cottage Grove pipelines and a Mississippi river dock.

1


Approximately 59%, 70% and 78% of our gasoline and diesel volumes for the years ended December 31, 2014, 2013 and 2012, respectively, were sold via our light products terminal to our company-operated and franchised SuperAmerica branded convenience stores and other resellers. The decline since 2012 is due to us increasing the crude throughput capacity at our refinery and selling the resulting incremental finished products through the Magellan Midstream Partners, LP ("Magellan") pipeline. 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% interests in MPL Investments, Inc. ("MPL Investments") and 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, 2014, our retail segment operated 165 convenience stores under the SuperAmerica brand and also supported 89 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, 2014, 2013 and 2012. We also own and operate Northern Tier Bakery LLC ("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, 2014, there were 139 operating oil refineries in the United States, with the 20 smallest each having a refining capacity of 15,000 bpd or less, and the 10 largest having capacities ranging from 327,000 bpd to 600,250 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 10% between January 1982 and January 2014 from 16.1 million bpd to 17.7 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 27% of total U.S. refined products demand from 2008 to 2013. Within PADD II, refined product production capacity is currently insufficient to meet demand. Refining capacity in the PADD II region has remained flat at approximately 3.8 million bpd between January 1982 and January 2014, while more than 25 refineries in the PADD II region have ceased operations. The refined product volumes that are necessary to satisfy the demand in excess of PADD II production are primarily sourced from domestic refineries located outside of PADD II, specifically from the U.S. Gulf Coast.
Our Refining Business
Our St. Paul Park 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 until acquired by one of our subsidiaries in 2010. Our refinery is a 97,800 bpsd 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 between 2008 and 2011, which entailed $19.9 million of capital expenditures over the project life. Our refining segment's capital expenditures in the years ended December 31, 2014 and 2013 were $35.4 million and $88.7

2


million, respectively. Starting in 2011, we began the upgrade of our wastewater treatment facility. During the years ended December 31, 2014 and 2013, we had capital expenditures of $15.4 million and $13.6 million, respectively, towards the upgrade of our wastewater treatment facility, bringing the total capitalized cost for the wastewater treatment facility upgrade to $30.6 million. In 2013, we had discretionary capital spending of $54.4 million, which included approximately $40 million for a project which resulted in a 9% capacity expansion at our refinery that, along with other discretionary projects, improved our distillate recovery by 2-3%.
We consider our refinery’s location to be strategically advantaged compared to gulf coast refineries. There are five regions in the United States, the PADDs, that have historically experienced varying levels of refining profitability due to regional market conditions. Refiners located in the U.S. Gulf Coast region operate in a highly competitive market due to the fact that this region (“PADD III”) accounts for approximately 39% and 40% of the total number of operable U.S. refineries as of January 2014 and 2013, respectively. 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 $6.43 per barrel, inclusive of refined product and crude oil differentials, relative to the benchmark Group 3 3:2:1 crack spread over the past five years through December 31, 2014 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 Group 3 3:2:1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at PADD II Group 3 prices the benchmark production of gasoline and ultra low sulfur diesel.
Our 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, 2014, our storage assets included 82 hydrocarbon storage tanks with an operating 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 a 97,800 bpsd 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 six hydrotreating units. This redundancy allows us to continue to receive and process crude oil even if any redundant units go 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 years ended December 31, 2014 and 2013, the refinery processed 91,840 bpd and 74,237 bpd of crude oil, respectively, and 1,685 bpd and 1,227 bpd of other feedstocks 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 generally occurs approximately every six years. Our refinery 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 81%, 68% and 80% for the years ended December 31, 2014, 2013 and 2012, respectively.

3


The following table summarizes our refinery’s major process unit capacities as of December 31, 2014. Unit capacities are shown in barrels per stream day. 
Process Unit
 
Capacity
 
% of Crude Oil Capacity
No. 1 Crude Oil Unit
 
39,800

 
41
%
No. 2 Crude Oil Unit
 
58,000

 
59
%
Vacuum Distillation Units (2 units)
 
43,500

 
44
%
Catalytic Reforming Units (2 units)
 
24,500

 
25
%
Fluid Catalytic Cracking Unit
 
28,500

 
29
%
HF Alkylation Unit
 
5,500

 
6
%
C4/C5/C6 Isom Unit
 
10,500

 
11
%
Naphtha Hydrotreaters (3 units)
 
25,000

 
26
%
Kerosene Hydrotreater
 
10,100

 
10
%
Distillate Hydrotreater
 
30,000

 
31
%
Gas Oil Hydrotreater
 
29,500

 
30
%
Hydrogen Plant (MSCF/D)
 
10,000

 

Sulfur Recovery Units (short tons/day) (2 units)
 
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 85%, 80% and 80% of our total refinery production for the years ended December 31, 2014, 2013 and 2012, respectively.
Raw Material Supply
The primary input for our refinery is crude oil, which represented approximately 98% of our total refinery throughput volumes for each of the years ended December 31, 2014, 2013 and 2012. We processed 91,840 bpd, 74,237 bpd and 81,779 bpd of crude oil for the years ended December 31, 2014, 2013 and 2012, respectively.
The following table describes the historical feedstocks for our refinery:
 
 
Year Ended December 31,
 
 
2014
 
%
 
2013
 
%
 
2012
 
%
 
 
(bpd)
Refinery Throughput Crude Oil Feedstocks by Location:
 
 
 
 
 
 
 
 
 
 
 
 
Canadian and Other International
 
34,184

 
37
%
 
37,045

 
50
%
 
38,332

 
47
%
Domestic
 
57,656

 
63
%
 
37,192

 
50
%
 
43,447

 
53
%
Total Crude Oil
 
91,840

 
100
%
 
74,237

 
100
%
 
81,779

 
100
%
Crude Oil Feedstocks by Type:
 
 
 
 
 
 
 
 
 
 
 
 
Light and Intermediate(1)
 
73,999

 
81
%
 
56,310

 
76
%
 
60,326

 
74
%
Heavy(1)
 
17,841

 
19
%
 
17,927

 
24
%
 
21,453

 
26
%
Total Crude Oil
 
91,840

 
100
%
 
74,237

 
100
%
 
81,779

 
100
%
Other Feedstocks/ Blendstocks(2):
 
 
 
 
 
 
 
 
 
 
 
 
Natural Gasoline
 
38

 
2
%
 

 
%
 
145

 
7
%
Butanes
 
798

 
47
%
 
597

 
49
%
 
1,294

 
62
%
Gasoil
 
351

 
21
%
 
114

 
9
%
 
58

 
3
%
Other
 
498

 
30
%
 
516

 
42
%
 
575

 
28
%
Total Other Feedstocks/ Blendstocks
 
1,685

 
100
%
 
1,227

 
100
%
 
2,072

 
100
%
Total Inputs
 
93,525

 
 
 
75,464

 
 
 
83,851

 
 
 
(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

4


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 pipeline system.
Of the crude oil processed at our refinery for the years ended December 31, 2014, 2013 and 2012, approximately 37%, 50% and 47%, 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 2.6 million bpd of crude oil into the United States in 2013, making it the largest crude oil exporter to the United States and representing 33% 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 6.4 million bpd from 2013 production of 3.5 million bpd. Additionally, U.S. demand for western Canadian oil supply is expected to reach 4.7 million bpd by 2020.
Crude production from North Dakota has increased significantly from approximately 98,000 bpd in 2005 to approximately 1.2 million bpd as of December 2014, 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 currently believe production from the Bakken Shale will continue to increase due to continued growth in unconventional production.
Source: EIA; see “North Dakota Field Production of Crude Oil”
Crude Oil Supply
In March 2012, we entered into an amended and restated crude oil supply and logistics agreement (the "Crude Intermediation Agreement") with J.P. Morgan Commodities Canada Corporation (“JPM CCC”), pursuant to which JPM CCC assisted us in the purchase of most of the crude oil requirements of our refinery. Once we identified types of crude oil and pricing terms that met our requirements, we notified JPM CCC, which then provided, 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 passed from JPM CCC to us as the crude oil entered our refinery from the storage tanks located at Cottage Grove. The Cottage Grove storage tanks were leased by JPM CCC from us for the duration of the Crude Oil Intermediation Agreement.
JPM CCC announced its intention to sell the physical portions of its commodities business (which includes JPM CCC) to Mercuria Energy Group Ltd. during the fourth quarter of 2014. In advance of this sale, JPM CCC and the Company mutually agreed to terminate the Crude Intermediation Agreement. We believe that in addition to avoiding the supply fees, we now have

5


further control over and visibility into our crude oil procurement process as a result of terminating this agreement. Going forward, we expect to utilize trade credit with our vendors to fund the purchase of crude oil. We may also utilize letters of credit under our ABL Facility to facilitate crude oil purchases with vendors.
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, 2014, 2013 and 2012, our shipments comprised approximately 26%, 22% 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, our refinery is also capable of receiving crude oil via railcar in the amount of approximately 6,000 bpd.
Below is a map illustrating the pipelines that provide the refinery with access to its crude oil supply:
Other Feedstocks/Blendstocks
Our refinery also purchases ethanol and biofuel, 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, with certain exceptions, for all gasoline powered motor vehicles for 10% ethanol blending in gasoline or the maximum amount of ethanol allowed under federal law for all cars and light duty trucks, whichever is greater. Federal law currently allows a maximum of 10% ethanol for all vehicles other than cars and light trucks manufactured since 2001, which have a 15% ethanol maximum. In addition, on July 1, 2014, a biodiesel mandate was passed by the Minnesota state legislature, requiring with certain exceptions, the blending of diesel with 10% biofuel for the months of April through September and 5% for the months of October through March. If certain preconditions are met, the minimum biofuel content in diesel sold in the state will increase to 20% beginning on May 1, 2018. In 2012, we completed the installation of a new tank at our refinery to store biofuel to enable us to comply with this mandate at a total cost of approximately $3.0 million. We purchase ethanol and biofuel blendstocks pursuant to month-to-month

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agreements with market based pricing provisions and receive those volumes primarily via third-party truck. We purchase butanes and natural gasoline blendstocks from third parties that are delivered to us via rail and/or third party pipeline.
Refined Products—Production, Sales and Transportation
The following table identifies the product yield of our refinery for each of the periods indicated.
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
Refinery product yields (bpd):
 
 
 
 
 
 
Gasoline
 
45,674

 
34,329

 
40,825

Distillate
 
33,910

 
26,074

 
27,113

Asphalt
 
7,567

 
8,321

 
11,434

Other
 
6,687

 
7,158

 
5,158

Total Production
 
93,838

 
75,882

 
84,530

For the years ended December 31, 2014, 2013 and 2012, gasoline accounted for 50%, 49%, and 52% of our total revenue for the refining business for such periods, respectively, and distillates accounted for 39%, 38%, and 35% of our total revenue for the refining business for such periods, respectively.
Approximately 81%, 80% and 78% of our refining segment's gasoline and diesel volumes were sold within the state of Minnesota for the years ended December 31, 2014, 2013 and 2012, respectively, with the remainder primarily being sold within Iowa, Nebraska, Oklahoma, South and North Dakota and Wisconsin. Our refinery supplied a majority 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, 2014, 2013 and 2012, 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 59%, 70% and 78% of our gasoline and diesel volumes for the years ended December 31, 2014, 2013 and 2012, respectively, were sold through this light products terminal to our company-operated and franchised SuperAmerica convenience stores and other resellers throughout our distribution area. The decline since 2012 is due to us increasing the crude throughput capacity at our refinery and selling the resulting incremental refined product through the Magellan pipeline. 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% of our total refinery throughput volumes for each of the years ended December 31, 2014, 2013 and 2012. Prior to October 2014, JPM CCC assisted us in the purchase of most of the crude oil requirements of our refinery and provided 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. Beginning in October 2014, we control the purchase of all of our crude oil requirements along with transportation and other logistical services. 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 a majority of the gasoline and diesel sold in our company-operated convenience stores, as well as a majority of the gasoline and diesel sold in our franchised convenience stores and in independently-owned and operated stores and resellers within our distribution area.
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.

7


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 facility 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. 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 facility turnaround. We completed unit turnarounds in 2014 for our gasoil hydrotreater unit with spending of approximately $8.2 million, our kerosene hydrotreater for $2.8 million and our diesel hydrotreater catalyst change-out for $2.3 million and other smaller turnaround related projects. We are currently planning for a turnaround of our sulfur recovery unit and one of our reformer units and other smaller turnaround projects in 2015, 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 areas 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 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” refined products pipeline, referred to as the Aranco Pipeline, which is leased to Magellan pursuant to an amended and restated agreement dated February 28, 2013. 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 automatic 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 to the refinery.
Our Retail Business
As of December 31, 2014, we have a retail-marketing network of 254 convenience stores located throughout Minnesota, Wisconsin and South Dakota, of which we operate 165 stores and support 89 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. A majority of the fuel gallons sold at our company-operated convenience stores for the years ended December 31, 2014, 2013 and 2012 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, 2014, 133 of the SuperAmerica convenience stores and one support facility remained on the Realty Income lease. Additionally, 30 of our other company-operated properties are leased pursuant to a combination of ground leases and real property leases with third parties and 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, 2014.
Location
 
Company-
Operated
 
Franchised
 
Total
Minnesota
 
158

 
83

 
241

Wisconsin
 
6

 
5

 
11

South Dakota
 
1

 
1

 
2

Total
 
165

 
89

 
254

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 89 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 90% to 100%) of its motor fuel supply, including gasoline and distillate, from us. As of December 31, 2014, 75 of the 89 existing franchise stores were located within our distribution area and, thus, are required to purchase a minimum percentage of their motor fuel supply from us.
Annual sales of refined products through our company-operated convenience stores averaged 311 million gallons over the period 2012 to 2014. The demand for gasoline is seasonal in nature, with higher demand during the summer months. Approximately 27% of the retail segment’s revenues for the year ended December 31, 2014 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,
 
 
2014
 
2013
 
2012
Company-operated
 
 
 
 
 
 
Fuel gallons sold (in millions)
 
306.8

 
313.2

 
312.4

Retail fuel margin ($/gallon)(1)
 
$
0.22

 
$
0.19

 
$
0.18

Merchandise sales ($ in millions)
 
$
349.1

 
$
341.6

 
$
340.4

Merchandise margin (%)(2)
 
25.9
%
 
25.9
%
 
25.4
%
Number of outlets at year end
 
165

 
164

 
166

Franchised Stores
 
 
 
 
 
 
Fuel gallons sold (in millions)(3)
 
73.2

 
54.9

 
46.2

Royalty income (in millions)
 
$
2.8

 
$
2.5

 
$
2.1

Number of outlets at year end
 
89

 
75

 
70

(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.

9


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 a majority 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, 2014, 2013 and 2012, our retail business purchased approximately 74%, 74% and 76%, respectively, of its convenience store 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 254 convenience stores, as of December 31, 2014, located throughout Minnesota, Wisconsin and South Dakota, of which we operate 165 stores and support 89 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, Kwik Trip, Marathon, Freedom Valu Centers, BP, Costco and Sam's Club. 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 on their ability to offer convenience to customers.

10


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 $1.1 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 45 days with a minimum loss of $5 million. Our property damage insurance has a deductible of $5 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 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 be completing installation and will operate additional instrumentation on our flare. In 2013 and 2014, we spent $0.1 million and $0.8 million, respectively, and anticipate spending an additional $0.6 million in 2015 for the flare monitoring. In addition, in order to comply with the NSPS, 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. Finally, the EPA is in the process of adopting revised air quality standards for ground level ozone. Depending on where the new level is set, the refinery, along with other sources in the state of Minnesota, could face significant additional regulation that may require installation of additional control equipment, make permitting new projects more difficult, and may require the production of different gasoline formulations. 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,

11


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.
Since 2012, the EPA has pursued an 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 several refiners and will likely pursue similar consent decrees with additional refiners. From time to time, the EPA has inspected our refinery for compliance with applicable flaring requirements and issued information requests to us related to such requirements. 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 and are subject to frequent changes. For example, in December 2014, the EPA published a proposed rule that would revise the National Ambient Air Quality Standard for ozone between 65 to 70 parts per billion for both the 8-hour primary and secondary standards. Also, in June 2014, the EPA issued a proposed rule seeking to impose additional emission control requirements on storage tanks, flares and coking units at petroleum refineries. The proposal would also require monitoring of air concentrations at the fenceline of refinery facilities to ensure the proposed standards are being met. These proposed rulemakings could impact us by requiring installation of new emission controls on some of our equipment, resulting in longer permitting timelines, and significantly increasing our capital expenditures and operating costs, which could adversely impact our business. 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 compliance period, 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. In December 2014, the EPA published notice that RFS compliance reporting for 2014 would not be required until the agency finalizes the proposed 2014 renewable fuel mandates. Though RFS requires the EPA to finalize renewable fuel mandates by November 30 of the preceding year, the EPA has not yet issued proposed renewable fuel mandates for 2015. We are not certain when 2014 or 2015 renewable fuel mandates will be finalized. Uncertainty surrounding RFS requirements has resulted in increased volatility in RIN prices over the past few years. 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.
On July 1, 2014, a biodiesel mandate was passed by the Minnesota state legislature, which requires, with certain exceptions, that all diesel sold in the state for use in internal combustion engines must contain at least 10% biofuel for the months of April through September and 5% for the months of October through March. Minnesota law also calls for an increase in biofuel content to 20% on May 1, 2018. In 2012, we completed the installation of a new tank at our refinery to store biofuel to enable us to comply with this mandate at a total cost of approximately $3.0 million. Minnesota law also currently requires, with certain 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 10% ethanol for all vehicles other than cars and light trucks manufactured since 2001, which have a 15% ethanol maximum. Fuels produced at our refinery are currently blended with the appropriate amounts of ethanol or biofuel 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 must meet an annual average of 0.62% volume. 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

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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 2014, our refinery’s average benzene content was 0.59%. 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 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 March 2014, the EPA finalized new “Tier 3” motor vehicle emission and fuel standards. The final regulation requires that gasoline contain no more than 10 parts per million of sulfur on an annual average basis by January 1, 2017. To date, compliance with the new standard has not had a material financial impact on our operations, nor has it required any material 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 these standards.
Climate Change
The EPA believes the 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. The EPA has adopted two sets of regulations that restrict the emission of GHGs under existing provisions of 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 the Clean Air Act's preconstruction and operating permit requirements for certain large stationary sources. Under the second set of EPA GHG rules, facilities required to obtain preconstruction permits must comply with “best available control technology” standards, which are established by the applicable permitting authority on a case by case basis. EPA rules also require the reporting of GHG emissions from specified large GHG emission sources in the United States, including refineries, on an annual basis. We have been monitoring GHG emissions from our refinery in accordance with the EPA’s rule. These or other rulemaking regulating the emission of GHGs could adversely affect our operations result in materially increased costs, and restrict or delay our ability to obtain air permits for new or modified sources.
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. Finally, some scientists hbelieve 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.
Hazardous Substances and Wastes
The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state and local laws impose liability without regard to fault or the legality of the original conduct, on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. Such classes of persons include the current and past owners and operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations, such as landfills. Under CERCLA, these “responsible persons” may be subject to joint and several, strict liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, for costs incurred by third parties and for the costs of certain environmental and health studies. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances into the environment. 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.

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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. In July 2014, we entered into a Stipulation Agreement with the MPCA that resolved waste management allegations related to submitting signed manifests to the MPCA and to the storage of hazardous wastes. We had already corrected the items alleged by the MPCA prior to signing the agreement with the MPCA. This agreement is also discussed in more detail below under “Water Discharges.”
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 for underground water contamination of approximately $0.6 million in 2015 and an additional $3.1 million through the year 2037 in connection with continued monitoring and remediation of this contamination at the refinery. This liability is stated at its present value of $2.9 million using a discount rate of 2.55%.
Water Discharges
The Federal Water Pollution Control Act of 1972, 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. Those exceedences were the subject of a 2012 settlement between Marathon and the MPCA. During our period of ownership prior to October 2012, we periodically experienced exceedances of benzene in our wastewater discharges to the lagoons. We reported these occurrences to the MPCA, and have worked with the agency to upgrade the refinery’s wastewater treatment plant to prevent additional benzene exceedances in our wastewater discharges. In June 2014, the MPCA issued a new National Pollutant Discharge Elimination Permit/State Disposal System Permit for the refinery’s upgraded wastewater treatment plant. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014 and, following our review of the test results and additional discussions with the MPCA, we now regard the likelihood of future remediation costs related to the lagoon as probable. At December 31, 2014, we estimate the remediation costs to be approximately $5.8 million subject to further engineering and methodology studies. Some or all of this cost may be recoverable from Marathon under an agreement entered into in connection with our December 2010 acquisition of the St. Paul Park Refinery. However, at December 31, 2014 it is unclear how much of our future costs would be reimbursed by Marathon, and as such, we have not at this time recognized any receivable for this matter. In addition, in July 2014, we entered into a stipulation agreement with the MPCA that resolved the benzene discharge exceedances that occurred during our period of ownership of the St. Paul Park Refinery and agreed to pay the agency approximately less than $0.1 million in penalties.
Environmental Capital and Maintenance Projects
A number of capital projects are planned for continued environmental compliance at our refinery. For example, as described above, we will be spending $0.6 million in 2015 for flare monitoring. Additionally, in 2014, we completed 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 $47.8 million since 2011 towards the completion of these wastewater treatment plant upgrades. Pursuant to the agreements entered into in connection with the Marathon Acquisition, we believed that Marathon was 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. We may seek additional reimbursement from Marathon for

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costs arising from claims that were not resolved by the 2013 settlement agreement. Costs will also be incurred for the remediation and closure of the remaining lagoon discussed above.
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 Instrumentation Systems to enhance its safety program and spent $5.8 million in 2013. Additionally, the refinery spent $1.5 million in 2014 and plans to spend approximately $4.9 million thereafter to upgrade process relief systems and to enhance overall safety. Furthermore, the refinery has budgeted approximately $14.5 million in 2015 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 Cottage Grove tank farm to the refinery and (3) a 12” pipeline connecting the Cottage Grove tank farm to the refinery. 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.
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 four 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 2015, and an additional cost of less than $0.1 million through the end of 2016. It is possible that we may identify more leaks or contamination in the future that could result in fines or civil liability for us, as well as remediation obligations and expenses. States, including Minnesota, have established funds to reimburse some expenses associated with remediating leaks from underground storage tanks, but such state reimbursement funds may not cover all remediation costs.
Other Government Regulation
Our transportation activities are subject to regulation by multiple governmental agencies. 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

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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 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 Cottage Grove tank farm to the refinery 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.

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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, 2014, we employed 2,950 people, including 486 employees associated with the operations of our refining business and 2,399 employees associated with the operations of our retail business. Our future success will depend in part on our ability to attract, retain and motivate qualified personnel. We are party to collective bargaining agreements covering approximately 190 of our 486 employees associated with the operations of our refining business and 22 of our 2,399 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 2017, respectively.
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 filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), 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 crude oil inventory, refined product inventories 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 may 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.
As a result of the termination of the Crude Intermediation Agreement, we rely on third party credit for a majority of our crude oil and other feedstock purchases in order to optimize our liquidity position. 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 ABL Facility or cash on hand, which would have a negative impact on liquidity.
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 a 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.

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Competition from companies having greater financial and other resources than we do could materially and adversely affect our business and results of operations.
Our refining operations compete with domestic refiners and marketers in the PADD II region of the United States, as well as with domestic refiners in other PADD regions and foreign refiners that import products into the United States. In addition, we compete with producers and marketers in other industries that supply alternative forms of energy and fuels to satisfy the requirements of our industrial, commercial and individual customers. Certain of our competitors have larger, more complex refineries, and may be able to realize lower per-barrel costs or higher margins per barrel of throughput. Several of our principal competitors are integrated national or international oil companies that are larger and have substantially greater resources than we do and have access to proprietary sources of controlled crude oil production. Unlike these competitors, we obtain substantially all of our feedstocks from unaffiliated sources. Because of their integrated operations and larger capitalization, these companies may be more flexible in responding to volatile industry or market conditions, such as shortages of crude oil supply and other feedstocks or intense price fluctuations.
Newer or upgraded refineries will often be more efficient than our refinery, which may put us at a competitive disadvantage. While we have taken significant measures to maintain and upgrade units in our refinery by installing new equipment and repairing equipment to improve our operations, these actions involve significant uncertainties, since upgraded equipment may not perform at expected throughput levels, the yield and product quality of new equipment may differ from design specifications and modifications may be needed to correct equipment that does not perform as expected. Any of these risks associated with new equipment, redesigned older equipment or repaired equipment could lead to lower revenues or higher costs or otherwise have an adverse effect on future results of operations and financial condition and our ability to make distributions. Over time, our refinery may become obsolete, or be unable to compete, because of the construction of new, more efficient facilities by our competitors.
Our retail operations compete with numerous convenience stores, gasoline service stations, supermarket chains, drug stores, fast food operations and other retail outlets. Increasingly, national high-volume grocery and dry-goods retailers are entering the gasoline retailing business. Many of these competitors are substantially larger than we are. Because of their diversity, integration of operations and greater resources, these companies may be better able to withstand volatile market conditions or levels of low or no profitability. In addition, these retailers may use promotional pricing or discounts, both at the pump and in the store, to encourage in-store merchandise sales. These activities by our competitors could adversely affect our profit margins. Additionally, our convenience stores could lose market share, relating to both gasoline and merchandise, to these and other retailers, which could adversely affect our business, results of operations and cash flows. Our convenience stores compete in large part based on their ability to offer convenience to customers. Consequently, changes in traffic patterns and the type, number and location of competing stores could result in the loss of customers and reduced sales and profitability at affected stores, and adversely affect our ability to make distributions.
Difficult conditions 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.
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 margins 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

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lower refining margins, if any. Changes in market conditions could have a material adverse effect on our business, financial condition and results of operations and, as a result, our ability to make distributions.
Our operating results are seasonal and generally lower in the first and fourth quarters of the year for our refining business and in the first quarter of the year for our retail business. We depend on favorable weather conditions in the spring and summer months.
Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lead to lower gasoline prices. As a result, the operating results of our refining business for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.
Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our retail fuel and convenience stores. As a result, the operating results of our retail business are generally lower for the first quarter of the year. Weather conditions in our operating area also have a significant effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our retail fuel and convenience stores, such as fast foods, fountain drinks and other beverages, and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Unfavorable weather conditions during these months and a resulting lack of the expected seasonal upswings in traffic and sales could have a material adverse effect on our business, financial condition and results of operations.
As the amount of cash we will be able to distribute with respect to a quarter principally depends on the amount of cash we generate from operations and because we do not intend to reserve or borrow cash to pay distributions in subsequent quarters, distributions with respect to the first and fourth quarters of the year may be significantly lower than with respect to the second and third quarters.
Weather conditions and natural disasters could materially and adversely affect our business and operating results.
The effects of weather conditions and natural disasters can lead to volatility in the costs and availability of energy and raw materials or negatively impact our operations or those of our customers and suppliers, which could have a significant adverse effect on our business and results of operations and, as a result, our ability to make distributions.
Our plans to grow our business may expose us to significant additional risks, compliance costs and liabilities.
We plan to continue to make investments to enhance the operating flexibility of our refineries and to improve our crude oil sourcing advantage through additional investments in our gathering and logistics operations. If we are able to successfully increase the effectiveness of our supporting logistics businesses, including our crude oil gathering operations, we believe we will be able to enhance our crude oil sourcing flexibility and reduce related crude oil purchasing and delivery costs. However, the acquisition of infrastructure assets to expand our gathering operations may expose us to risks in the future that are different than or incremental to the risks we face with respect to our refineries and existing gathering and logistics operations. The storage and transportation of liquid hydrocarbons, including crude oil and refined products, are subject to stringent federal, state, and local laws and regulations governing the discharge of materials into the environment, operational safety and related matters. Compliance with these laws and regulations could adversely affect our operating results, financial condition and cash flows. Moreover, failure to comply with these laws and regulations may result in the assessment of administrative, civil, and criminal penalties, the imposition of investigatory and remedial liabilities, the issuance of injunctions that may restrict or prohibit our operations, or claims of damages to property or persons resulting from our operations.
Any businesses or assets that we may acquire in connection with an expansion of our crude oil gathering operations could expose us to the risk of releasing hazardous materials into the environment. These releases would expose us to potentially substantial expenses, including cleanup and remediation costs, fines and penalties, and third-party claims for personal injury or property damage related to past or future releases. Accordingly, if we do acquire any such businesses or assets, we could also incur additional expenses not covered by insurance which could be material.


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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 of our general partner or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
Our future success depends to a large extent on the services of the executive officers of our general partner and other key employees and on our continuing ability to recruit, train and retain highly qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business could be materially adversely affected. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals.
Our operations could be disrupted if our information systems fail, causing increased expenses and loss of sales.
Our business is highly dependent on financial, accounting and other data processing systems and other communications and information systems, including our enterprise resource planning tools. We process a large number of transactions on a daily basis and rely upon the proper functioning of computer systems. If a key system were to fail or experience unscheduled downtime for any reason, even if only for a short period, our operations and financial results could be affected adversely. Our systems could also be damaged or interrupted by a security breach, fire, flood, power loss, telecommunications failure or similar event. Our formal disaster recovery plan may not prevent delays or other complications that could arise from an information systems failure. Further, our business interruption insurance may not compensate us adequately for losses that may occur.
We may incur significant liability under, or costs and capital expenditures to comply with, environmental, health and safety regulations, which are complex and change frequently.
Our refinery, pipelines and retail operations are subject to stringent and complex federal, state and local laws regulating, among other things, the generation, storage, handling, use and transportation of petroleum, hazardous substances and wastes, the emission and discharge of materials into the environment, 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

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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 adjacent properties or third party storage, treatment or disposal facilities. For example, we have performed remediation of known soil and groundwater contamination beneath certain of our retail locations primarily as a result of leaking underground storage tanks, and we will continue to perform remediation of this known contamination until the appropriate regulatory standards have been achieved. Moreover, 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 will be completing installation and will operate additional instrumentation on our flare. In 2014, we spent $0.8 million and anticipate spending an additional $0.6 million in 2015 for the flare monitoring. In March 2014, the EPA finalized new "Tier 3" motor vehicle emission and fuel standards. The final regulation requires that gasoline contain no more than 10 parts per million of sulfur on an annual average basis by January 1, 2017. To date, compliance with the new standard has not had a material financial impact on our operations, nor has it required any material 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. Also, in June 2014, the EPA issued a proposed rule seeking to impose additional emission control requirements on storage tanks, flares and coking units at petroleum refineries and fenceline emission monitoring requirements. In addition, various states have proposed and/or enacted low carbon fuel standards (“LCFS”) intended to reduce carbon intensity in transportation fuels. In addition, in 2010 the President’s administration issued social cost of carbon (“SCC”) estimates used by the EPA and other federal agencies in regulatory cost-benefit analyses to take into account alleged broad economic consequences associated with changes to emissions of GHGs, which estimates were increased in 2013. While the impacts of LCFS and higher SCC in future regulations is not known at this time, either of these may result in increased costs to our operations. 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. Historical operations have resulted in the release of petroleum hydrocarbons and various substances on or under our refinery site. A prior site owner and operation, 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 by the former owner and MPCA in 2007. Releases of petroleum hydrocarbons have also occurred at several of our convenience stores, and we have performed and will continue to perform remediation of this known contamination until the applicable regulatory standards are met. Costs for such 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 health and safety. 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.

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Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes as well as its not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service were to treat us as a corporation for U.S. federal income tax purposes or we were to become subject to any material additional amount of entity level taxation for state purposes, then our ability to make distributions would be substantially reduced.
Despite the fact that we are a partnership under Delaware law, it is possible in certain circumstances for a publicly traded partnership, like us, to be treated as a corporation rather than a partnership for U.S. federal income tax purposes. Although we do not believe based upon our current (or past) operations that we should be (or should have been) so treated, a change in our business (or a change in current law) could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes for any taxable year for which the statute of limitations remains open, we would pay U.S. federal income tax on our taxable income at the corporate tax rates, currently at a maximum rate of 35%, and would likely pay state income tax at varying rates. Because a tax would be imposed on us as a corporation, our ability to make distributions would be substantially reduced.
The present federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial changes at any time. For example, members of Congress have recently considered substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may be applied retroactively and could impose additional administrative requirements on us or make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will be reconsidered or will ultimately be enacted. Any such changes could negatively impact our ability to make distributions. 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 additional tax on us by any state will reduce the cash available for payments on the notes and on our other debt obligations.
Compliance with and changes in tax laws could adversely affect our performance.
We are subject to extensive tax liabilities, including federal, state and transactional taxes such as excise, sales/use, payroll, franchise, withholding and ad valorem taxes. New tax laws and regulations and changes in existing tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future. Certain of these liabilities are subject to periodic audits by the respective taxing authority, which could increase our tax liabilities. Subsequent changes to our tax liabilities as a result of these audits may also subject us to interest and penalties. Any such changes in our tax liabilities could adversely affect our ability to make distributions to our unitholders.
Our insurance policies may be inadequate or expensive.
Our insurance coverage does not cover all potential losses, costs or liabilities. We could suffer losses for uninsurable or uninsured risks or in amounts in excess of our existing insurance coverage. Our ability to obtain and maintain adequate insurance may be affected by conditions in the insurance market over which we have no control. In addition, if we experience insurable events, our annual premiums could increase further or insurance may not be available at all or if it is available, on restrictive coverage items. The occurrence of an event that is not fully covered by insurance or the loss of insurance coverage could have a material adverse effect on our business, financial condition, and results of operations and, as a result, our ability to make distributions.
Our level of indebtedness may increase and reduce our financial flexibility.
In the future, we may incur significant indebtedness in order to make future acquisitions or to develop our properties. Our level of indebtedness could affect our operations in several ways, including the following:
a significant portion of our cash flows could be used to service our indebtedness;
a high level of debt would increase our vulnerability to general adverse economic and industry conditions;
the covenants contained in the agreements governing our outstanding indebtedness will limit our ability to borrow additional funds, dispose of assets, pay distributions and make certain investments;
a high level of debt may place us at a competitive disadvantage compared to our competitors that are less leveraged, and therefore may be able to take advantage of opportunities that our indebtedness would prevent us from pursuing;
our debt covenants may also affect our flexibility in planning for, and reacting to, changes in the economy and in our industry;

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a high level of debt may make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings; and
a high level of debt may impair our ability to obtain additional financing in the future for working capital, capital expenditures, acquisitions, general corporate or other purposes.
A high level of indebtedness increases the risk that we may default on our debt obligations. Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance. General economic conditions and financial, business and other factors affect our operations and our future performance. Many of these factors are beyond our control. We may not be able to generate sufficient cash flows to pay the interest on our debt, and future working capital, borrowings or equity financing may not be available to pay or refinance such debt. Factors that will affect our ability to raise cash through an offering of our units or a refinancing of our debt include financial market conditions, the value of our assets and our performance at the time we need capital.
In addition, our bank borrowing base is subject to periodic redeterminations. We could be forced to repay a portion of our bank borrowings due to redeterminations of our borrowing base. If we are forced to do so, we may not have sufficient funds to make such repayments. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial condition and, as a result, our ability to make distributions.
Increased costs of capital could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms and cost of capital, increases in interest rates or a reduction in credit rating. Changes in any one or more of these factors could cause our cost of doing business to increase, limit our access to capital, limit our ability to pursue acquisition opportunities, reduce our cash flows and place us at a competitive disadvantage. Recent and continuing disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability impacting our ability to finance our operations.
Additionally, as with other yield-oriented securities, we expect that our unit price will be impacted by the level of our quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price and our ability to issue additional equity to fund our operations or to make acquisitions or to incur debt as well as increasing our interest costs.
We require continued access to capital. In particular, the board of directors of our general partner 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 may 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.

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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 2014, the price for NYMEX WTI crude oil fluctuated between $33.87 and $145.29 per barrel, while the price for U.S. Gulf Coast conventional gasoline fluctuated between $33.52 per barrel and $204.67 per barrel. While an increase or decrease in the price of crude oil may result in a similar increase or decrease in prices for refined products, there may be a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our refining margins therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes.
In addition, the nature of our business requires us to maintain substantial inventories. Because feedstock and refined products are commodities, we have no control over the changing market value of these inventories. Our feedstock and refined product inventories are 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 feedstock and refined product inventories 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. For example, we recorded a non-cash charge of $73.6 million to cost of sales in Q4 2014 in order to record our LIFO inventory at the lower of cost or market.
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;
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 expenses constituted approximately 17.0% and 14.9% and 13.0% of our total direct operating expenses for the years ended December 31, 2014, 2013 and 2012, respectively.
Volatility in refined product prices also affects our borrowing base under our ABL Facility. A decline in prices of our refined products reduces the value of our inventory collateral, which, in turn, may reduce the amount available for us to borrow under our ABL Facility.

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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 to the U.S. Gulf Coast. Between December 1, 2010 and December 31, 2014, the discount at which a barrel of NYMEX WTI traded relative to a barrel of Brent increased from $2.12 to $4.06 and ranged from $0.02 to $26.88 during this period. 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 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, 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 6,000 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

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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. 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.
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 190 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, 22 of our employees associated with the operations of our retail business are covered by a collective bargaining agreement that expires in August 2017. 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 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.

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The EPA has determined that the 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 (“CAA”). The EPA adopted two sets of rules regulating GHG emissions under the CAA, one of which requires a reduction in emissions of GHGs from motor vehicles and the other of which requires preconstruction and operating permits for GHG emissions 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.
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. In December 2014, the EPA published notice that RFS compliance reporting for 2014 would not be required until the agency finalizes the proposed 2014 renewable fuel mandates, which will likely occur sometime in the first half of 2015. Uncertainty surrounding RFS requirements has resulted in increased volatility in RIN prices over the past few years, with the price for ethanol RINs at times ranging from approximately $0.80 to above $1.00. 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.
On July 1, 2014, a biodiesel mandate was passed by the Minnesota state legislature, which requires, with certain exceptions, that all diesel sold in the state for combustion in internal combustion engines must contain at least 10% biofuel for the months of April through September and 5% for the months of October through March. Minnesota law also calls for an increase in biofuel content to 20% on May 1, 2018. In 2012, we completed the installation of a new tank at our refinery to store biofuel to enable us to comply with this mandate at a total cost of approximately $3.0 million. Minnesota law also currently requires, with certain 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

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trucks manufactured since 2007, and on January 21, 2011, 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% for all other vehicles. Fuels produced at our refinery are currently blended with the appropriate amounts of ethanol or biofuel 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.
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.
If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's Renewable Fuels Standard mandates, our business, financial condition and results of operations could be materially adversely affected.
Pursuant to the Energy Independence and Security Act of 2007, the EPA has promulgated the Renewable Fuel Standard, or RFS, which requires refiners to either blend "renewable fuels," such as ethanol, into their petroleum fuels or purchase renewable fuel credits, known as RINs, in lieu of blending. Under the RFS, the volume of renewable fuels refineries like ours are obligated to blend into their finished petroleum products is adjusted annually. We currently purchase RINs for some fuel categories on the open market, as well as waiver credits for cellulosic biofuels from the EPA, in order to comply with the RFS. Existing laws or regulations could change, and the minimum volumes of renewable fuels that must be blended with refined petroleum products may increase. In the future, we may be required to purchase additional RINs on the open market and waiver credits from the EPA in order to comply with the RFS. During 2013, the price of RINs was extremely volatile as the EPA’s proposed renewable fuel volume mandates approached the "blend wall." The blend wall refers to the point at which refiners are required to blend more ethanol into the transportation fuel supply than can be supported by the demand for E10 gasoline (gasoline containing 10 percent ethanol by volume). In November 2013, the EPA published the annual renewable fuel percentage standards for 2014, which acknowledged the blend wall and were generally lower than the volumes for 2013 and lower than statutory mandates. The price of RINs decreased significantly after the 2014 percentage standards were published; however RIN prices remained volatile and increased subsequently in 2014. In May 2014, the EPA lowered the 2013 cellulosic biofuel standard to 0.0005%, and, in June 2014, the EPA extended the compliance demonstration deadline for the 2013 RFS to September 30, 2014. In August 2014, the EPA further extended the compliance demonstration deadline for the 2013 RFS to 30 days following publication of the final 2014 annual renewable fuel percentage standards. In November 2014, the EPA announced that it would not finalize the 2014 annual renewable fuel percentage standards before the end of 2014, thereby extending the compliance deadline for the 2013 RFS as well.
We cannot predict the future prices of RINs or waiver credits, particularly until such time that the 2014 renewable fuel percentage standards are finalized and the 2015 renewable fuel percentage standards are announced. Additionally, the cost of RINs is dependent upon a variety of factors, which include EPA regulations, the availability of RINs for purchase, the price at which RINs can be purchased, transportation fuel production levels, the mix of our petroleum products, as well as the fuel blending performed at our refineries, all of which can vary significantly from quarter to quarter. However, the costs to obtain the necessary number of RINs and waiver credits could likely be material. Additionally, 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 refineries' product pool, potentially resulting in lower earning and materially adversely affecting our ability to make distributions. If sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations and ability to pay distributions to our unitholders could be materially adversely affected.
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

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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 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.

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Our exposure to the risks associated with volatile crude oil prices has increased as a result of our exit from the Crude Intermediation Agreement.
The Crude Intermediation Agreement allowed us to price crude oil processed at the refinery one day after it was received at the plant. This arrangement minimized the amount of in-transit inventory and reduced our exposure to fluctuations in crude oil prices. This agreement was terminated in September 2014 and as a result, our exposure to crude oil pricing risks has increased as the number of days between when we take title to the crude oil and when the crude oil is delivered to the refinery 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 carry on our balance sheet and, therefore, could adversely affect our ability to make distributions.
Our suppliers source a substantial amount of our crude oil from the Bakken Shale of North Dakota and Canada and may experience interruptions of supply from those regions.
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 due to operational or commodity market conditions including prolonged low crude oil prices and related production, among others, 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. Prolonged periods of low crude oil prices could impact production growth of inland crude oil, which could reduce the amount of cost advantaged crude oil available and/or the discount of such crude oil and thereby impact profitability of our refinery. We currently have no commercially viable alternatives for crude oil.
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, 2014, 2013 and 2012, our retail business purchased approximately 74%, 74% and 76%, 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 ABL 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.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.

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Credit and debit card data loss, litigation and/or liability could significantly harm our reputation and adversely impact our business.
In connection with credit and debit card sales at our retail stores, we transmit confidential credit and debit card information securely over public networks. Third parties may have the technology or know-how to breach the security of this customer information, and our security measures may not effectively prohibit others from obtaining improper access to this information. If a person is able to circumvent our security measures, he or she could destroy or steal valuable information or disrupt our operations. Any security breach could expose us to risks of data loss, litigation and liability and could seriously disrupt our operations and any resulting negative publicity could significantly harm our reputation.
Our failure or inability to enforce our current and future trademarks and trade names could adversely affect our efforts to establish brand equity and expand our retail franchising business.
Our ability to successfully expand our retail franchising business will depend on our ability to establish brand equity through the use of our current and future trademarks, service marks, trade dress and other proprietary intellectual property, including our name and logos. Some or all of these intellectual property rights may not be enforceable, even if registered, against any prior users of similar intellectual property or our competitors who seek to use similar intellectual property in areas where we operate or intend to conduct operations. If we fail to enforce any of our intellectual property rights, then we may be unable to capitalize on our efforts to establish brand equity.
We could encounter claims from prior users of similar intellectual property in areas where we operate or intend to conduct operations, which could result in additional expenditures and divert our management’s time and attention from our operations. Conversely, competing businesses, including any of our former retail store franchisees, could infringe on our intellectual property, which would necessarily require us to defend our intellectual property possibly at a significant cost to us.
Our retail business is vulnerable to changes in consumer preferences, economic conditions and other trends and factors that could harm our business, results of operations, financial condition or cash flows.
Our retail business is affected by consumer preferences, national, regional and local economic conditions, demographic trends and consumer confidence in the economy. Factors such as traffic patterns, weather conditions, local demographics and the number and locations of competing retail service stations and convenience stores also affect the performance of our retail stores. In addition, we cannot ensure that our retail customers will continue to frequent our retail stores or that we will be able to find new retail store franchisees or encourage our existing retail store franchisees to grow their franchised business or renew their franchise rights. Adverse changes in any of these trends or factors could reduce our retail customer traffic or sales, or impose limits on our pricing, which could adversely affect our business, results of operations, financial condition or cash flows and, as a result, our ability to make distributions.
We face the risk of litigation in connection with our retail operations.
We are from time to time the subject of complaints or litigation from our consumers alleging illness, injury or other health or operational concerns. Adverse publicity resulting from these allegations may materially adversely affect us and our brand, regardless of whether the allegations are valid or whether we are liable. In addition, employee claims against us based on, among other things, discrimination, harassment or wrongful termination, or labor code violations may divert financial and management resources that would otherwise be used to benefit our future performance. There is also a risk of litigation from our franchisees. We have been subject to a variety of these and other claims from time to time and a significant increase in the number of these claims or the number that are successful could materially adversely affect our business, prospects, financial condition, operating results or cash flows and, as a result, our ability to make distributions.
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

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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:
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 ABL Facility prohibit us from making distributions to unitholders if certain events of default exist. In addition, both the indenture and our ABL 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 1.00 to 1.00 after giving pro forma effect to such distributions. Our ABL 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) 12.5% of the lesser of (x) the $500 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.

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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.”
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

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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.
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:

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Approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or
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.
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 38.4% 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.

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Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.
Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, salary, bonus, incentive compensation and other amounts paid to its employees and executive officers who perform services for us. There are no limits contained in our partnership agreement on the amounts or types of expenses for which our general partner and its affiliates may be reimbursed. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to our unitholders. See “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;

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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.
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, 2015, there were 92,832,210 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, an aggregate of 35,622,500 common units are owned by NT InterHoldCo LLC and the remainder have been awarded to our employees and directors through our Long-Term Incentive Plan. 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:

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the requirement that a majority of the board of directors of our general partner consist of independent directors;
the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and
the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors.
As a result of these exemptions, our general partner’s board of directors 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 and differing interpretations, possibly on a retroactive basis.
The present U.S. 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, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could 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.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.
You will be required to pay taxes on your share of our income even if you do not receive any cash distributions from us.
Because 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

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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.
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 38.4% of the total interests in our capital and profits. Therefore, a transfer by NT InterHoldCo LLC of all or a portion of its interest in us could, in conjunction with the trading of common units held by the public, result in a termination of 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. No technical terminations occurred during the year ended December 31, 2014
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

42


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 each non-U.S. person will be required to file U.S. federal income tax returns and pay tax on its 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.
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

43


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 1250 W. Washington Street, Suite 300, Tempe, AZ 85281.
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.

44


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, 2015, we had issued and outstanding 92,832,210 common units, which were held of record by 54 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, 2014
 
$
27.34

 
$
20.51

 
$
0.49

September 30, 2014
 
$
27.49

 
$
22.25

 
$
1.00

June 30, 2014
 
$
29.60

 
$
24.66

 
$
0.53

March 31, 2014
 
$
27.69

 
$
23.30

 
$
0.77

 
 
 
 
 
 
 
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

(1)
Distributions are shown for the quarter in which they were generated.
Cash Distribution Policy
We generally 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 ABL 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 ABL 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.”

45


Unregistered Sales of Equity Securities
None.

46


Item 6. Selected Financial Data.
Set forth below is our summary historical consolidated financial data for the years ended December 31, 2014, 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 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.
 
Successor
 
 
Predecessor
 
Year Ended December 31,
 
June 23, 2010
(inception date) to
December 31, 2010
 
 
Eleven  Months
Ended
November 30, 2010
 (in millions)
2014
 
2013
 
2012
 
2011
 
Consolidated and combined statements of operations data
 
 
 
 
 
 
 
 
 
 
 
 
Revenue
$
5,556.0

 
$
4,979.2

 
$
4,653.9

 
$
4,280.8

 
$
344.9

 
 
$
3,195.2

Costs, expenses and other:
 
 
 
 
 
 
 
 
 
 
 
 
Cost of sales (a)
4,835.9

 
4,284.2

 
3,586.6

 
3,515.4

 
307.5

 
 
2,697.9

Direct operating expenses
288.8

 
262.4

 
254.1

 
257.9

 
21.4

 
 
227.0

Turnaround and related expenses
14.9

 
73.3

 
26.1

 
22.6

 

 
 
9.5

Depreciation and amortization
41.9

 
38.1

 
33.2

 
29.5

 
2.2

 
 
37.3

Selling, general and administrative
87.8

 
85.8

 
88.3

 
88.7

 
6.4

 
 
59.6

Reorganization and related costs
12.9

 
3.1

 
1.4

 
7.4

 
3.6

 
 

Contingent consideration loss (income)

 

 
104.3

 
(55.8
)
 

 
 

Income from equity method investment
(2.2
)
 
(10.0
)
 
(12.3
)
 
(5.7
)
 
(0.1
)
 
 
(5.4
)
Other (income) loss, net
0.7

 
(3.8
)
 
2.9

 
1.2

 
0.2

 
 

Operating income
275.3


246.1


569.3


419.6


3.7



169.3

Gains (losses) from derivative activities (a)

 
16.1

 
(269.7
)
 
(349.2
)
 
(27.1
)
 
 
(40.9
)
Bargain purchase gain

 

 

 

 
51.4

 
 

Interest expense, net
(26.6
)
 
(26.9
)
 
(42.2
)
 
(42.1
)
 
(3.2
)
 
 
(0.3
)
Loss on early extinguishment of debt

 

 
(50.0
)
 

 

 
 

Income before income taxes
248.7


235.3


207.4


28.3


24.8



128.1

Income tax provision
(7.1
)
 
(4.2
)
 
(9.8
)
 

 

 
 
(67.1
)
Net income
$
241.6


$
231.1


$
197.6


$
28.3


$
24.8



$
61.0

Earnings per common diluted unit (b)
$
2.61

 
$
2.51

 
$
1.38

 
 
 
 
 
 
 
Distributions declared per common unit
$
2.71

 
$
3.49

 
$
1.48

 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(a) Realized and unrealized gains and losses on derivatives not related to crack spread hedges have been reclassified from gains (losses) from derivative activities to cost of sales for all periods.
(b) For 2012 the calculation, net income available to common unitholders excludes earnings attributable to the period prior to our IPO date of July 31, 2012.




47


 
Successor
 
 
Predecessor
 
Year Ended December 31,
 
June 23, 2010 (inception date) to December 31, 2010
 
 
Eleven Months Ended November 30, 2010
(in millions)
2014
 
2013
 
2012
 
2011
 
Consolidated and combined statements of cash flow data
 
 
 
 
 
 
 
 
 
 
 
 
Cash provided by (used in):
 
 
 
 
 
 
 
 
 
 
 
 
Operating activities
$
219.6

 
$
229.8

 
$
308.5

 
$
209.3

 
$

 
 
$
145.4

Investing activities
(39.5
)
 
(95.5
)
 
(28.7
)
 
(156.3
)
 
(363.3
)
 
 
(29.3
)
Financing activities
(178.0
)
 
(321.4
)
 
(130.4
)
 
(2.3
)
 
436.1

 
 
(115.4
)
Capital expenditures
(44.8
)
 
(96.6
)
 
(30.9
)
 
(45.9
)
 
(2.5
)
 
 
(29.8
)
 
Successor
 
 
Predecessor
 
December 31,
 
 
November 30,
(in millions)
2014
 
2013
 
2012
 
2011
 
2010
2010
Consolidated and combined balance sheet data
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
$
87.9

 
$
85.8

 
$
272.9

 
$
123.5

 
$
72.8

 
 
$
6.7

Total assets
1,180.4

 
1,117.8

 
1,136.8

 
998.8

 
930.6

 
 
717.8

Capital lease obligations
8.6

 
8.4

 
7.5

 
11.9

 
24.5

 
 

Total long-term debt
354.2

 
275.0

 
275.0

 
290.0

 
290.0

 
 

Total liabilities
776.7

 
716.7

 
653.0

 
686.6

 
645.6

 
 
405.4

Total equity
403.7

 
401.1

 
483.8

 
312.2

 
285.0

 
 
312.4


48


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 logistics 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, 2014, we had total revenues of $5.6 billion, operating income of $275.3 million, net income of $241.6 million and Adjusted EBITDA of $430.7 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 MPL Investments, our convenience stores and related assets (the “Marathon Assets”) from a subsidiary of Marathon Oil Corporation ("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 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. In November, 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 a 97,800 bpsd 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 85%, 80% and 80% of our total refinery production for the years ended December 31, 2014, 2013 and 2012, 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 81%, 68% and 80% for the years ended December 31, 2014, 2013 and 2012, 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 59%, 70% and 78% of our gasoline and diesel volumes for the years ended December 31, 2014, 2013 and 2012, 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. The decline since 2012 is due to increasing the crude throughput capacity at our refinery and us selling the incremental refined product through the Magellan pipeline. 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

49


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 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 85,00090,000 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, 2014, our retail business operated 165 convenience stores under the SuperAmerica brand and also supported 89 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 a majority 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, 2014, 2013 and 2012.
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
Our refining margins were weaker in 2014 compared to 2013. The Group 3 benchmark 3:2:1 crack spread declined from an average of $20.38 in 2013 to an average of $15.87 in 2014. The Group 3 benchmark 3:2:1 crack spread year-to-date in 2015, through February 26, 2015 has averaged $13.55. Our refining margins are impacted by both the price we pay for crude oil and relationship between that price and refined product prices.
Regarding the price we pay for crude oil, we have historically 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 WTI. Our refining margins in recent years have benefited from this price relationship between WTI and Brent crude oil. In addition, our location allows us direct access, via the Minnesota Pipeline, to cost-advantaged crude oil from the Bakken Shale in North Dakota and other Canadian crude oils that may price at substantial discounts to WTI. During 2014 the discount of WTI crude oil to Brent crude oil declined to an average of $5.80 for the year ended December 31, 2014, compared to $10.57 in 2013. The WTI/Brent discount, year-to-date, from January 1, 2015, through February 26, 2015, has averaged $4.88. However, this discount has been volatile recently due to growth of inland crude production and new and proposed crude oil pipeline capacity additions in the Permian Basin and in Cushing, Oklahoma. We expect continued volatility in crude oil pricing differentials and crack spreads given the significant drop in world crude oil prices and expected supply and demand rebalancing in 2015. Please see “Item 1A. Risk Factors-Risks Primarily Related to Our Refining Business.”
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, 2014, 2013 and 2012, approximately 37%, 50% and 47%, 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 East, West, and Gulf Coast sections 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, West, and Gulf Coasts and pipeline transportation to St. Paul Park, MN.
    

50


Refined products prices are set by global markets and are typically priced off Brent; they are also impacted by local supply/demand dynamics. We have enjoyed an overall benefit during the years ended December 31, 2014, 2013 and 2012 from the overall widening of the price differential between our cost of crude oil and the price of the refined 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 WTI is settled, to alternative markets, among others. Despite the historical favorable price difference between WTI and Brent, this spread has narrowed significantly during the fourth quarter of 2014 and may continue to do so in future periods. 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.” 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. While there continues to be a significant global macroeconomic risk that may impact the pace of growth in the United States, we have generally experienced overall product demand growth in our geographic area of operations. Please see “Item 1A. Risk Factors-Risks Primarily Related to Our Refining Business.”
Comparability of Historical Results
The IPO Transactions
Our results of operations for periods subsequent to the closing of our IPO in July 2012 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.
On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering will be amortized as a net reduction to interest expense over the remaining life of the notes. This offering was used to finance a substantial portion of the feedstock inventory previously held by JPM CCC that we purchased from them due to the termination of the Crude Intermediation Agreement, which closed around the same time.
Contingent Consideration Gain Loss
The St. Paul Park Refinery and Retail Marketing Business were formerly owned and operated by subsidiaries of Marathon Oil Corporation (“Marathon Oil”). The Company purchased these businesses from Marathon Oil on December 1, 2010. The acquisition included contingent consideration arrangements under which the Company could have received margin support payments of up to $60 million from Marathon Oil or could have paid Marathon oil 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.

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The Marathon Oil subsidiaries that we made these agreements with were sold to Marathon Petroleum ("MPC") on June 30, 2011.
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. 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. We 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, we 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.
Lower of Cost or Market Adjustment
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 using the LIFO as our 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 sales. For example, given the volatile crude markets in Q4 2014, as of December 31, 2014 current market prices for our feedstock and finished product fuel inventories were less than our LIFO cost. As a result, in Q4 2014 we recorded a lower of cost or market ("LCM") inventory reserve of $73.6 million, which increased cost of sales. This reserve may be reversed in future periods if the market value of our inventory increases.
Derivative Reclassifications
We have used derivative instruments to hedge price risk on both our refined product inventory and our overall refining margin which we refer to as crack spread hedges. In 2014, we changed our presentation of realized and unrealized hedging gains and losses on our refined product inventory. Previously, hedging activity on both refined product inventory and crack spread hedges were included in gains (losses) from derivative activity within the consolidated statement of operations. Starting in 2014, we began recording gains and losses on our refined product inventory hedges in cost of sales within the consolidated statement of operations. We have also adjusted all prior periods to conform to this change in classification.
Income from Equity Method Investment Reclassifications
We maintain a 17% interest in MPL that we account for under the equity method of accounting (see Critical Accounting Policies and Estimates below). In 2014, we changed our presentation by reclassifying income from this investment from other (income) loss, net to a separate line titled income from equity method investment.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our audited financial statements for a discussion of additional accounting policies and estimates made by management.
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, ("FASB"), Accounting Standards Codification ("ASC") 323. We have determined that we have the ability to exercise significant influence on MPL because we are one of two customers of MPL and our Chief Executive Officer is a member of MPL's board of directors. Income from this equity method investment represents our proportionate share of net earnings attributed to common owners generated by MPL.

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The equity method investment is assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. We employ valuation techniques to estimate the fair value of our investment in MPL that require management to make estimates regarding future earnings and distributions from MPL along with discount rates used to adjust those estimates to present value. If our estimate of fair value is less than the carrying amount of the MPL investment, a loss from impairment is indicated. 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.
Our 17% 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 are located in other (income) loss, net.
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 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. Historically, we performed its annual indefinite lived intangible testing as of October 31. During 2014, we changed the date of our annual impairment test to June 30. Based on the testing performed as of June 30, 2014, we noted no indications of impairment.
Inventories    
Crude oil, refined product and other feedstock and blendstock inventories are carried at the lower of cost or market. Cost is determined principally under the LIFO valuation method to reflect a better matching of costs and revenues. Ending inventory costs in excess of market value are written down to the lower of cost or market (LCM) or net realizable market values and charged to cost of sales in the period recorded. In future periods, a new LCM determination will be made based upon market values at that time. Under the LIFO inventory valuation method, this LCM write-down is recorded as a reserve and subject to recovery in future periods to the extent the market values of our inventories increase. We determine market value inventory adjustments by evaluating crude oil, refined products and other inventories on an aggregate basis by LIFO pool.
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 cash balance 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.
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. As of December 31, 2014, our board has authorized us to utilize derivative instruments to hedge price risk associated with our refined product inventory. 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 our statements of operations. These

53


gains or losses are reported within operating activities on the consolidated statement of cash flows. As of December 31, 2014, we have $2.8 million in unrealized net losses related to our outstanding derivatives.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-08, which updated the guidance in ASC Topic 205, “Presentation of Financial Statements”, and ASC Topic 360, “Property, Plant and Equipment.” This ASU raises the threshold for a disposal to qualify as discontinued operations and requires new disclosures for individual material disposal transactions that do not meet the definition of a discontinued operation.  Under the new standard, companies report discontinued operations when they have a disposal that represents a strategic shift that has or will have a major impact on operations or financial results.  This update will be applied prospectively and is effective for annual periods, and interim periods within those years, beginning after December 15, 2014.  Early adoption is permitted provided the disposal was not previously disclosed.  The adoption of this guidance is not expected to have a material impact on our results of operations, cash flows or financial position.
In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition. The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance will be effective for our financial statements in the annual period beginning after December 15, 2016. We are evaluating the effect of adopting this new accounting guidance we do not expect adoption will have a material impact on our results of operations, cash flows or financial position.
In August 2014, the FASB issued ASU No. 2014-15 “Presentation of Financial Statements - Going Concern,” which sets forth new provisions that require management of an entity to evaluate whether there is substantial doubt about the entity's ability to continue as a going concern and to provide related footnote disclosures. This guidance will become effective for annual periods beginning after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted. The changed requirements are intended to reduce diversity in the timing and content of footnote disclosures. We do not expect the adoption of these new provisions to materially affect our financial position, results of operations or cash flows.
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 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

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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 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 facility turnaround. We completed unit turnarounds in 2014 for our gasoil hydrotreater unit with spending of approximately $8.2 million, our kerosene hydrotreater for $2.8 million and our diesel hydrotreater catalyst change-out for $2.3 million and other smaller turnaround related projects. We are currently planning for a turnaround of our sulfur recovery unit and one of our reformer units and other smaller turnaround projects in 2015, 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 using LIFO as our 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 sales. For example, given the volatile crude markets in Q4 2014, as of December 31, 2014 current market prices for our feedstock and finished product fuel inventories were less than our LIFO cost. As a result, in Q4 2014 we recorded a LCM inventory reserve of $73.6 million, which increased cost of sales. This reserve may be reversed in future periods if the market value of our inventory increases. We occasionally experience 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. There were no such liquidations in the years ended December 31, 2014 or 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 assisted us in the purchase of most of the crude oil requirements of our refinery and provided transportation and other logistical services for delivery of the crude oil to our storage tanks in Cottage Grove, Minnesota. We paid JPM CCC the price of the crude oil plus certain agreed fees and expenses. In September 2014, we terminated the crude oil supply and logistics agreement with JPM CCC. We believe that in addition to avoiding the supply fees, we now have further control over and visibility into our crude oil procurement process. Going forward, we expect to utilize existing trade credit with our vendors to fund the purchase of crude oil. We may also utilize letters of credit under our ABL Facility to facilitate crude oil purchases with vendors.
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, 2014 and 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 effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our convenience

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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 less the delivered cost of the fuel (inclusive of applicable 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 90% 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, 2014, 75 of the 89 existing franchise stores are located within our distribution area and, thus, required to purchase a 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 165 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 and retail segments. 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. For purposes of presenting revenue on a consolidated basis, such intersegment transactions are eliminated. Retail revenue primarily includes sales of fuel and merchandise to customers inclusive of related excise taxes and net of any applicable discounts. Also included in retail revenue is royalty income, revenues from car wash operations and SuperMom’s Bakery sales to third parties.
Cost of sales. Refining cost of sales primarily include costs of crude and refinery feedstocks purchased, ethanol and other refined products purchased, 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 sales taxes remitted 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.
Reorganization and related costs. Reorganization and related costs during 2014 represent charges related to the relocation of the Company's corporate offices from Ridgefield, Connecticut to Tempe, Arizona and the reorganization of various positions within the Company, primarily among senior management. For years prior to 2014, reorganization and related costs relate 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 loss. Contingent consideration loss relates to changes in the estimated fair value of our margin support and earn-out arrangements with Marathon.
Income from equity method investment. Income from equity method investment relates to our equity in the net income of our 17% investment in MPL.
Other (income) loss, net. Other (income) loss, net, primarily represents (income) loss from dividends on our cost method investment in MPL Investments, sales of property plant and equipment and foreign exchange translation differences.
Gains (losses) from derivative activities. Gains (losses) from derivative activities 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.
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 ABL Facility and the amortization of deferred financing costs and premiums or discounts.
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
 
 
For the year ended December 31,
(in millions)
 
2014
 
2013
 
2012
Revenue
 
$
5,556.0

 
$
4,979.2

 
$
4,653.9

Costs, expenses and other:
 
 
 
 
 
 
Cost of sales
 
4,835.9

 
4,284.2

 
3,586.6

Direct operating expenses
 
288.8

 
262.4

 
254.1

Turnaround and related expenses
 
14.9

 
73.3

 
26.1

Depreciation and amortization
 
41.9

 
38.1

 
33.2

Selling, general and administrative
 
87.8

 
85.8

 
88.3

Reorganization and related costs
 
12.9

 
3.1

 
1.4

Contingent consideration loss
 

 

 
104.3

Income from equity method investment
 
(2.2
)
 
(10.0
)
 
(12.3
)
Other (income) loss, net
 
0.7

 
(3.8
)
 
2.9

Operating income
 
275.3

 
246.1

 
569.3

Gains (losses) from derivative activities
 

 
16.1

 
(269.7
)
Interest expense, net
 
(26.6
)
 
(26.9
)
 
(42.2
)
Loss on early extinguishment of debt
 

 

 
(50.0
)
Income before income taxes
 
248.7

 
235.3

 
207.4

Income tax provision
 
(7.1
)
 
(4.2
)
 
(9.8
)
Net income
 
$
241.6

 
$
231.1

 
$
197.6

Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Revenue. Revenue for the year ended December 31, 2014 was $5,556.0 million compared to $4,979.2 million for the year ended December 31, 2013, an increase of 11.6%. Refining segment revenue increased 12.4% and retail segment revenue decreased 4.7% compared to the year ended December 31, 2013. Refining revenue included a $152.7 million increase in crude oil revenues in the year ended December 31, 2014. These crude oil revenues relate to the sale of crude barrels with the objective of optimizing our crude slate in a given period. Additionally, the Refining segment had a 16.4% increase in sales volumes of refined products versus the year ended December 31, 2013. The higher refined product volumes are primarily attributable to the capacity expansion we completed in May 2013 and less unplanned maintenance at our St. Paul Park Refinery in the year ended December 31, 2014. The impact of higher volumes on the refining revenue were partially offset by lower average selling prices of gas and diesel. Retail revenue decreased primarily due to lower market prices per gallon for fuel sales during the year ended December 31, 2014. Excise taxes included in revenue totaled $396.4 million and $316.4 million for the years ended December 31, 2014 and 2013, respectively.
Cost of sales. Cost of sales totaled $4,835.9 million for the year ended December 31, 2014 compared to $4,284.2 million for the year ended December 31, 2013, an increase of 12.9%, primarily due to a 16.4% increase in sales volumes of refined products during the year ended December 31, 2014, an increase of $152.7 million related to crude oil sales and a non-cash lower of cost or market reserve of $73.6 million recorded in the fourth quarter of 2014 as a result of falling feedstocks and finished product prices. These increases were partially offset by lower average crude costs. Excise taxes included in cost of sales were $396.4 million and $316.4 million for the years ended December 31, 2014 and 2013, respectively.
Direct operating expenses. Direct operating expenses totaled $288.8 million for the year ended December 31, 2014 compared to $262.4 million for the year ended December 31, 2013, an increase of 10.1%, due primarily to the impact of higher variable costs as a result of our higher throughput as well as higher estimated costs related to our environmental obligations of $8.4 million, both within our refining segment in the year ended December 31, 2014.
Turnaround and related expenses. Turnaround and related expenses totaled $14.9 million for the year ended December 31, 2014 compared to $73.3 million for the year ended December 31, 2013, a decrease of 79.7%. 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 2014 turnaround activity relates primarily to a partial turnaround of our gasoil hydrotreater, our kerosene hydrotreater and our diesel hydrotreater catalyst change-out.
Depreciation and amortization. Depreciation and amortization was $41.9 million for the year ended December 31, 2014 compared to $38.1 million for the year ended December 31, 2013, an increase of 10.0%. This increase was due to

58


increased assets placed in service as a result of our capital expenditures since December 31, 2013, primarily within our refining segment.
Selling, general and administrative expenses. Selling, general and administrative expenses were $87.8 million for the year ended December 31, 2014 compared to $85.8 million for the year ended December 31, 2013. This increase of 2.3% from the prior-year period relates primarily to higher employee benefit costs and higher equity-based compensation expense.
Reorganization and related costs. Reorganization and related costs for the years ended December 31, 2014 and 2013 were $12.9 million and $3.1 million, respectively. The increase was due to costs incurred in connection with the relocation of our corporate office and reorganization of various positions within the Company. The reorganization and related costs in the year ended December 31, 2013 relate primarily to offering costs for the sale of common units by NT Holdings.
Income from equity method investment. Income from equity method investment was $2.2 million for the year ended December 31, 2014 compared to $10.0 million of income for the year ended December 31, 2013. This decrease was driven primarily by a reduction in the equity income of MPL due to non-routine maintenance expense projects on the pipeline.
Other (income) loss, net. Other (income) loss, net was a $0.7 million loss for the year ended December 31, 2014 compared to $3.8 million of income for the year ended December 31, 2013. This decrease is driven primarily by $4.4 million of miscellaneous income that was recognized in the first and third quarters of 2013 related to settlements from indemnification arrangements.
Gains (losses) from derivative activities. For the year ended December 31, 2014, we had no crack spread related derivative activities versus gains from such derivative activities of $16.1 million in the year ended December 31, 2013. We had settlement losses of $25.2 million in the year ended December 31, 2013 offset by a gain of $41.3 million. These derivatives were entered into to partially hedge the crack spreads for our refining business.
Interest expense, net. Interest expense, net was $26.6 million for the year ended December 31, 2014 and $26.9 million for the year ended December 31, 2013. These interest charges relate primarily to our senior secured notes, commitment fees and interest on the ABL facility and the amortization of deferred financing costs. The decrease from the prior year is primarily due to less interest expense related to letter of credit utilization under our ABL Facility, partially offset by higher interest costs on our bonds due to the follow-on offering of $75.0 million in additional principal of our 2020 Secured Notes, which we completed in the third quarter of 2014.
Income tax provision. The income tax provision for the year ended December 31, 2014 was $7.1 million compared to $4.2 million for the year ended December 31, 2013. The increase was due to higher pre-tax income generated by our retail segment.
Net income. Our net income was $241.6 million for the year ended December 31, 2014 compared to $231.1 million for the year ended December 31, 2013. This increase in net income is primarily attributable to an increase in gross margin of $25.1 million, which includes a $73.6 million lower of cost or market inventory adjustment, and a $58.4 million decrease in turnaround and related expenses. These increases in net income were offset by higher direct operating costs of $26.4 million, reorganization and related costs of $9.8 million, a decrease in income from equity method investment of $7.8 million, and a decrease in gains from derivative activities of $16.1 million.
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 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 $4,284.2 million for the year ended December 31, 2013 compared to $3,586.6 million for the year ended December 31, 2012, an increase of 19.5%, 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.

59


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.
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.
Reorganization and related costs. Reorganization and related costs for the years ended December 31, 2013 and 2012 were $3.1 million and $1.4 million, respectively. These 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.
Income from equity method investment. Income from equity method investment was $10.0 million for the year ended December 31, 2013 compared to $12.3 million of income for the year ended December 31, 2012. This decrease was driven by lower equity income from MPL.
Other (income) loss, net. Other (income) loss, net was $3.8 million in net other income for the year ended December 31, 2013 compared to $2.9 million in net other loss 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 during the year ended December 31, 2013.
Gains (losses) from derivative activities. For the year ended December 31, 2013, we had gains from crack spread derivative activities of $16.1 million versus losses from derivative activities of $269.7 million in the year ended December 31, 2012. We had settlement losses of $25.2 million in the year ended December 31, 2013 related to settled contracts compared to $337.7 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 $41.3 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.

60


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 $285.8 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.
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.
 
 
For the year ended December 31, 2014
(in millions)
 
Refining
 
Retail
 
Other/Elim
 
Consolidated
Revenue:
 
 
 
 
 
 
 
 
Sales and other revenue
 
$
4,165.6

 
$
1,390.4

 
$

 
$
5,556.0

Intersegment sales
 
932.1

 

 
(932.1
)
 

Segment revenue
 
$
5,097.7

 
$
1,390.4

 
$
(932.1
)
 
$
5,556.0

Cost of sales:
 
 
 
 
 
 
 
 
Cost of sales
 
$
4,554.7

 
$
281.2

 
$

 
$
4,835.9

Intersegment purchases
 

 
932.1

 
(932.1
)
 

Segment cost of sales
 
$
4,554.7

 
$
1,213.3

 
$
(932.1
)
 
$
4,835.9

 
 
For the 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
 
$
4,008.4

 
$
275.8

 
$

 
$
4,284.2

Intersegment purchases
 

 
1,015.8

 
(1,015.8
)
 

Segment cost of sales
 
$
4,008.4

 
$
1,291.6

 
$
(1,015.8
)
 
$
4,284.2

 
 
For the 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
 
$
3,305.4

 
$
281.2

 
$

 
$
3,586.6

Intersegment purchases
 

 
1,041.1

 
(1,041.1
)
 

Segment cost of sales
 
$
3,305.4

 
$
1,322.3

 
$
(1,041.1
)
 
$
3,586.6


61


Refining Segment
 
 
For the year ended December 31,
(in millions)
 
2014
 
2013
 
2012
Revenue
 
$
5,097.7

 
$
4,536.0

 
$
4,212.6

Costs, expenses and other:
 
 
 
 
 
 
Cost of sales
 
4,554.7

 
4,008.4

 
3,305.4

Direct operating expenses
 
163.0

 
144.1

 
136.3

Turnaround and related expenses
 
14.9

 
73.3

 
26.1

Depreciation and amortization
 
33.7

 
30.4

 
25.2

Selling, general and administrative
 
30.5

 
29.9

 
26.7

Income from equity method investment
 
(2.2
)
 
(10.0
)
 
(12.3
)
Other income, net
 
(0.4
)
 
(3.2
)
 
(0.4
)
Operating income
 
$
303.5

 
$
263.1

 
$
705.6

Key Operating Statistics:
 
 
 
 
 
 
Refining gross product margin (in millions)(3)
 
$
543.0

 
$
527.6

 
$
907.2

Total refinery production (bpd)(1)
 
93,838

 
75,882

 
84,530

Total refinery throughput (bpd)
 
93,525

 
75,464

 
83,851

Refined products sold (bpd)(2)
 
98,016

 
84,231

 
89,162

Per barrel of throughput:
 
 
 
 
 
 
Refining gross product margin(3)
 
$
15.91

 
$
19.15

 
$
29.56

Direct operating expenses(4)
 
$
4.77

 
$
5.23

 
$
4.44

Per barrel of refined products sold:
 
 
 
 
 
 
Refining gross product margin(3)
 
$
15.18

 
$
17.16

 
$
27.80

Direct operating expenses(4)
 
$
4.56

 
$
4.69

 
$
4.18

Refinery product yields (bpd):
 
 
 
 
 
 
Gasoline
 
45,674

 
34,329

 
40,825

Distillate(5)
 
33,910

 
26,074

 
27,113

Asphalt
 
7,567

 
8,321

 
11,434

Other(6)
 
6,687

 
7,158

 
5,158

Total
 
93,838

 
75,882

 
84,530

Refinery throughput (bpd):
 
 
 
 
 
 
Crude oil
 
91,840

 
74,237

 
81,779

Other feedstocks(7)
 
1,685

 
1,227

 
2,072

Total
 
93,525

 
75,464

 
83,851

 
(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.
(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, light cycle oil and kerosene.

62


(6)
Other refinery products include propane, propylene, liquid sulfur 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, 2014 Compared to the Year Ended December 31, 2013
Refining gross product margin. Refining gross product margin for the year ended December 31, 2014 was $543.0 million compared to $527.6 million for the year ended December 31, 2013, an increase of 2.9%, primarily due to higher sales volumes during the year ended December 31, 2014. The higher sales volumes during the year ended December 31, 2014 are related to increased throughput capacity from our crude expansion project completed in the second quarter of 2013 as well as less refinery downtime from the 2013 turnaround and crude expansion project and unplanned maintenance activities. This increase due to volume was partially offset by a decrease in market crack spreads. Refining gross product margin per barrel of throughput was $15.91 for the year ended December 31, 2014 compared to $19.15 for the year ended December 31, 2013, a decrease of $3.24, or 16.9%, which is mostly attributable to lower Group 3 3:2:1 crack spreads in the year ended December 31, 2014. Additionally, during the year ended December 31, 2014, we recognized a loss from a lower of cost or market inventory adjustment due to falling feedstock and refined product prices of $72 million.
Direct operating expenses. Direct operating expenses totaled $163.0 million for the year ended December 31, 2014 compared to $144.1 million for the year ended December 31, 2013, a 13.1% increase. This increase was due primarily to the impact of the crude expansion project we completed in May 2013 which increased refining capacity by 9%, resulting in higher variable operating costs in 2014, specifically an increase in natural gas costs of $8.0 million. Additionally, there was an increase in the estimated costs for environmental compliance at the refinery of $8.4 million, partially offset by lower per barrel labor and benefits costs.
Turnaround and related expenses. Turnaround and related expenses totaled $14.9 million for the year ended December 31, 2014 compared to $73.3 million for the year ended December 31, 2013, a decrease of 79.7%. 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 2014 turnaround activity relates primarily to a partial turnaround of our gasoil hydrotreater, our kerosene hydrotreater and our diesel hydrotreater catalyst change-out.
Depreciation and amortization. Depreciation and amortization was $33.7 million for the year ended December 31, 2014 compared to $30.4 million for the year ended December 31, 2013, an increase of 10.9%. This increase was due to increased assets placed in service as a result of our capital expenditures since December 31, 2013, the most significant of which was our updated wastewater treatment facility.
Selling, general and administrative expenses. Selling, general and administrative expenses were $30.5 million and $29.9 million for the year ended December 31, 2014 and 2013, respectively, an increase of 2.0%. This increase was primarily due to higher risk management costs in the year ended December 31, 2014.
Income from equity method investment. Income from equity method investment was $2.2 million for the year ended December 31, 2014 compared to $10.0 million for the year ended December 31, 2013. This decrease was driven primarily by a reduction in the equity income of MPL in the 2014 period due to non-routine expense projects on the pipeline that were not present in 2013.
Other income, net. Other income, net was $0.4 million for the year ended December 31, 2014 compared to $3.2 million for the year ended December 31, 2013. This decrease is driven primarily by $4.4 million of miscellaneous income that was recognized in the first and third quarters of 2013 related to settlements from indemnification arrangements.
Operating income. Income from operations was $303.5 million for the year ended December 31, 2014 compared to $263.1 million for the year ended December 31, 2013. This increase from the prior-year period of $40.4 million is primarily due to $58.4 million decrease in turnaround costs in 2014, partially offset by higher direct operating costs.

63


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 $527.6 million compared to $907.2 million for the year ended December 31, 2012, a decrease of 41.8%, 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 $19.15 for the year ended December 31, 2013 compared to $29.56 for the year ended December 31, 2012, a decrease of $10.41, or 35.2%, which is mostly attributable to lower Group 3 3:2:1 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.
Income from equity method investment. Income from equity method investment was $10.0 million for the year ended December 31, 2013 compared to $12.3 million for the year ended December 31, 2013. This decrease was driven by lower equity income from the MPL.
Other income, net. Other income, net was $3.2 million for the year ended December 31, 2013 compared to $0.4 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.
Operating income. Income from operations was $263.1 million for the year ended December 31, 2013 compared to $705.6 million for the year ended December 31, 2012. This decrease from the prior-year period of $442.5 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.


64


Retail Segment 
 
 
For the year ended December 31,
(in millions)
 
2014
 
2013
 
2012
Revenue
 
$
1,390.4

 
$
1,459.0

 
$
1,482.4

Costs, expenses and other:
 
 
 
 
 
 
Cost of sales
 
1,213.3

 
1,291.6

 
1,322.3

Direct operating expenses
 
125.7

 
119.2

 
118.8

Depreciation and amortization
 
7.3

 
7.1

 
7.5

Selling, general and administrative
 
21.2

 
25.9

 
25.1

Operating income
 
$
22.9

 
$
15.2

 
$
8.7

Operating data:
 
 
 
 
 
 
Retail gross product margin (1)
 
$
177.1

 
$
167.4

 
$
160.1

Company-operated stores:
 
 
 
 
 
 
Fuel gallons sold (in millions)
 
306.8

 
313.2

 
312.4

Fuel margin per gallon (2)
 
$
0.22

 
$
0.19

 
$
0.18

Merchandise sales (in millions)
 
$
349.1

 
$
341.6

 
$
340.4

Merchandise margin % (3)
 
25.9
%
 
25.9
%
 
25.4
%
Number of stores at period end
 
165

 
164

 
166

Franchisee stores:
 
 
 
 
 
 
Fuel gallons sold (in millions)(4)
 
73.2

 
54.9

 
46.2

Royalty income (in millions)
 
$
2.8

 
$
2.5

 
$
2.1

Number of stores at period end
 
89

 
75

 
70

(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 Performance Measures."
(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 Refinery.
Year Ended December 31, 2014 Compared to the Year Ended December 31, 2013
Retail gross product margin. Retail gross product margin for the year ended December 31, 2014 was $177.1 million compared to $167.4 million for the year ended December 31, 2013, an increase of 5.8%. This increase was primarily due to higher fuel margins at our company-operated stores partially offset by lower fuel volumes. The increase was partially offset due to a $1.4 million lower of cost or market inventory adjustment due to falling fuel prices. For company-operated stores, fuel margin per gallon was $0.22 for the year ended December 31, 2014 compared to $0.19 per gallon for the year ended December 31, 2013. Additionally, fuel gallons sold in our company-operated stores decreased by 2.0% in the year ended

65


December 31, 2014 although total fuel gallons sold, including both company-operated and franchised stores increased 3.2%. Gross margin on our merchandise remained steady year over year.
Direct operating expenses. Direct operating expenses totaled $125.7 million for the year ended December 31, 2014 compared to $119.2 million for the year ended December 31, 2013, an increase of 5.5% from the 2013 period. This increase is primarily due to higher property tax and personnel costs at our stores during the year ended December 31, 2014. This increase was partially offset by lower transaction fees on credit and debit card sales.
Depreciation and amortization. Depreciation and amortization was $7.3 million for the year ended December 31, 2014 compared to $7.1 million for the year ended December 31, 2013, an increase of $0.2 million. This increase was primarily due to increased retail assets placed in service since December 31, 2013.
Selling, general and administrative expenses. Selling, general and administrative expenses were $21.2 million and $25.9 million for the year ended December 31, 2014 and 2013, respectively. The decrease relates primarily to lower personnel and information technology expenses for the year ended December 31, 2014.
Operating income. Operating income was $22.9 million for the year ended December 31, 2014 compared to $15.2 million for the year ended December 31, 2013, an increase of $7.7 million. The increase is primarily attributable to improved gross margin on fuel sales during the year ended December 31, 2014.
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 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.
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 ABL 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 secured notes and the ABL 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 and related expenses, lower of cost or market inventory adjustments, equity-based compensation expense, gains (losses) from crack spread derivative activities, losses from the change in fair value of contingent consideration agreements, losses on extinguishment of debt, reorganization and related costs 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

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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 crack spread derivative activities, which may have a substantial impact on our cash flow;
does not reflect certain other non-cash income and expenses including inventory lower of cost or market adjustments, if applicable; 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:
 
 
For the year ended December 31, 2014
(in millions)
 
Refining  
 
Retail  
 
Other  
 
Total  
Net income (loss)
 
$
303.5

 
$
15.8

 
$
(77.7
)
 
$
241.6

Adjustments:
 
 
 
 
 
 
 
 
Interest expense
 

 

 
26.6

 
26.6

Income tax provision
 

 
7.1

 

 
7.1

Depreciation and amortization
 
33.7

 
7.3

 
0.9

 
41.9

EBITDA subtotal
 
337.2


30.2


(50.2
)

317.2

Lower of cost or market inventory adjustment (a)
 
72.2

 
1.4

 

 
73.6

MPL proportionate depreciation expense
 
2.9

 

 

 
2.9

Turnaround and related expenses
 
14.9

 

 

 
14.9

Equity-based compensation expense
 

 

 
14.0

 
14.0

Reorganization and related costs, exclusive of related equity-based compensation expense
 

 

 
8.1

 
8.1

Adjusted EBITDA
 
$
427.2


$
31.6


$
(28.1
)

$
430.7

 
 
 
 
 
 
 
 
 
(a) includes adjustments from inventory stated at cost on a LIFO basis to lower market values as of December 31, 2014.

67


 
 
For the year ended December 31, 2013
(in millions)
 
Refining  
 
Retail  
 
Other  
 
Total  
Net income (loss)
 
$
263.1

 
$
11.0

 
$
(43.0
)
 
$
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
 
293.5


22.3


(15.5
)

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

Reorganization and related costs
 

 

 
3.1

 
3.1

Gains from derivative activities (b)
 

 

 
(16.1
)
 
(16.1
)
Adjusted EBITDA
 
$
369.7


$
22.3


$
(21.4
)

$
370.6

 
 
 
 
 
 
 
 
 
(b) realized and unrealized gains and losses on derivatives not related to crack spread hedges have been reclassified from gains (losses) from derivative activities to cost of sales which resulted in an increase in 2013 Adjusted EBITDA of $7.4 million.
 
 
For the year ended December 31, 2012
(in millions)
 
Refining
 
Retail
 
Other
 
Total
Net income (loss)
 
$
705.6

 
$
(1.1
)
 
$
(506.9
)
 
$
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
 
730.8


16.2


(464.2
)

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

Reorganization and related costs
 

 

 
1.4

 
1.4

Losses from derivative activities (c)
 

 

 
269.7

 
269.7

Adjusted EBITDA
 
$
759.7


$
16.2


$
(37.9
)

$
738.0

 
 
 
 
 
 
 
 
 
(c) realized and unrealized gains and losses on derivatives not related to our our crack spread hedges have been reclassified from gains (losses) from derivative activities to cost of sales which resulted in a decrease in 2012 Adjusted EBITDA of $1.7 million.
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.

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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.”
 
 
For the year ended December 31,
(in millions)
 
2014
 
2013
 
2012
Refining revenue
 
$
5,097.7

 
$
4,536.0

 
$
4,212.6

Refining cost of sales
 
4,554.7

 
4,008.4

 
3,305.4

Refining gross product margin
 
$
543.0

 
$
527.6

 
$
907.2

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.
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.”
 
For the year ended December 31,
(in millions)
2014
 
2013
 
2012
Retail revenue:
 
 
 
 
 
Fuel revenue
$
1,012.0

 
$
1,089.5

 
$
1,114.5

Merchandise revenue
349.1

 
341.6

 
340.4

Other revenue
47.8

 
46.7

 
45.9

Intercompany eliminations
(18.5
)
 
(18.8
)
 
(18.4
)
Retail revenue
1,390.4

 
1,459.0

 
1,482.4

 
 
 
 
 
 
Retail cost of sales:
 
 
 
 
 
Fuel cost of sales
945.5

 
1,029.3

 
1,058.4

Merchandise cost of sales
258.7

 
253.2

 
254.1

Other cost of sales
27.6

 
27.9

 
28.2

Intercompany eliminations
(18.5
)
 
(18.8
)
 
(18.4
)
Retail cost of sales
1,213.3

 
1,291.6

 
1,322.3

 
 
 
 
 
 
Retail gross product margin:
 
 
 
 
 
Fuel margin
66.5

 
60.2

 
56.1

Merchandise margin
90.4

 
88.4

 
86.3

Other margin
20.2

 
18.8

 
17.7

Intercompany eliminations

 

 

Retail gross product margin
$
177.1

 
$
167.4

 
$
160.1

Liquidity and Capital Resources
Our primary sources of liquidity have traditionally been cash generated from our operating activities and availability under our ABL 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,

69


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 ABL 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.
On September 29, 2014 and November 8, 2012, we completed private placements of $75 million and $275 million, respectively, of the 2020 Secured Notes. For the September 29, 2014 offering, we used the net proceeds and cash on hand to finance the acquisition of feedstock inventory from JPM CCC due to the termination of the Crude Intermediation Agreement which closed around the same time. For the November 8, 2012 offering, we used the net proceeds 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 ABL 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 issuance of debt or equity as deemed appropriate for business purposes.
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 2015 RINs requirement will exceed the amount of RINs we obtain through our normal blending operations by between 20 and 30 million RINs. This shortfall, net of RIN credits on hand as of December 31, 2014, will require us to purchase between 17 and 27 million RINs on the open market in 2015. 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)
 
2014
 
2013
 
2012
Net cash provided by operating activities
 
$
219.6

 
$
229.8

 
$
308.5

Net cash used in investing activities
 
(39.5
)
 
(95.5
)
 
(28.7
)
Net cash used in financing activities
 
(178.0
)
 
(321.4
)
 
(130.4
)
Net increase (decrease) in cash and cash equivalents
 
2.1

 
(187.1
)
 
149.4

Cash and cash equivalents at beginning of period
 
85.8

 
272.9

 
123.5

Cash and cash equivalents at end of period
 
$
87.9

 
$
85.8

 
$
272.9


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Net Cash Provided By Operating Activities. Net cash provided by operating activities for the year ended December 31, 2014 was $219.6 million. The most significant providers of cash were our net income ($241.6 million) adjusted for non-cash items, such as a lower of cost-or-market inventory adjustments ($73.6 million), depreciation and amortization expense ($41.9 million) and equity-based compensation expense ($14.0 million). Additionally, cash was negatively impacted by a net working capital increase of $159.7 million, which primarily relates to our purchase of crude oil inventory in connection with the wind-down of our Crude Intermediation Agreement with JPM CCC.
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 Used In Investing Activities. Net cash used in investing activities for the year ended December 31, 2014 was $39.5 million, relating primarily to capital expenditures of $44.8 million. Capital spending for the year ended December 31, 2014 primarily included the wastewater 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, 2013 was $95.5 million, relating primarily to capital expenditures of $96.6 million. Capital spending for the year ended December 31, 2013 primarily included the capacity expansion project on our larger crude unit and our wastewater 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 Financing Activities. Net cash used in financing activities for the year ended December 31, 2014 of $178.0 million was primarily related to $251.8 million in distributions to unitholders, partially offset by proceeds from a follow-on offering under our 2020 secured notes of approximately $75 million, net of fees.
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 $269 million, net of fees, related to our 2020 Secured Notes. Additionally, in the fourth quarter of 2012, we issued our initial distribution to unitholders of $136.0 million.
Working Capital
Working capital at December 31, 2014 was $204.3 million, consisting of $591.2 million in total current assets and $386.9 million in total current liabilities. The increase in working capital from the prior year was caused primarily by an increase in inventory as a result of the termination of the Crude Intermediation Agreement with JPM CCC which resulted in us acquiring crude oil inventories from JPM CCC, partially offset by a non-cash inventory lower of cost or market valuation inventory adjustment of $73.6 million.
Historically, we maintained a crude oil supply and logistics agreement with JPM CCC pursuant to which JPM CCC assisted us in the purchase of crude oil for our storage tanks at Cottage Grove, Minnesota, which are approximately two miles from our refinery. Upon delivery of the crude oil to us, we paid JPM CCC the price of the crude oil plus certain agreed fees and expenses. Going forward, we expect to utilize existing trade credit with our vendors to fund the purchase of crude oil. We may also utilize letters of credit under our ABL Facility to facilitate crude oil purchases with vendors.
JPMorgan Chase & Co. announced its intention to sell the physical portions of its commodities business (which includes JPM CCC) to Mercuria Energy Group Ltd. during the fourth quarter of 2014. In advance of this sale, JPM CCC and the Company mutually agreed to terminate the Crude Intermediation Agreement. We believe that in addition to avoiding the

71


supply fees, we now have further control over and visibility into our crude oil procurement process as a result of terminating this agreement.
In order to finance the incremental working capital requirement from the termination of the Crude Intermediation Agreement, we issued $75 million of additional senior secured notes under our existing note indenture. We also expanded the capacity of our undrawn ABL facility from $300 million to $500 million in order to provide further flexibility to manage ongoing working capital requirements.
Borrowing availability under the ABL Facility is tied to a borrowing base dependent upon the amount of eligible accounts receivable and inventory. As of December 31, 2014, the borrowing base under the ABL Facility was $308.3 million and availability under the ABL Facility was $296.2 million (which is net of $12.1 million in outstanding letters of credit). The Company had no borrowings under the ABL Facility at December 31, 2014.
Our Distribution Policy
We generally 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 ABL 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.

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The following table details the quarterly distributions paid to common unitholders since our IPO in July 2012 (in millions, except per unit amounts):
Date Declared
 
Date Paid
 
Common Units and equivalents (in millions)
 
Distribution per common unit and equivalent
 
Total Distribution (in millions)
2012 Distributions:
 
 
 
 
 
 
 
 
November 12, 2012
 
November 29, 2012
 
92.0

 
$
1.48

 
$
136.1

Total distributions paid during 2012
 
 
 
 
 
$
1.48

 
$
136.1

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
 
92.7

 
$
0.41

 
$
38.0

May 6, 2014
 
May 30, 2014
 
93.0

 
$
0.77

 
71.6

August 5, 2014
 
August 29, 2014
 
93.0

 
$
0.53

 
49.3

November 4, 2014
 
November 25, 2014
 
93.1

 
$
1.00

 
92.9

Total distributions paid during 2014
 
 
 
 
 
$
2.71

 
$
251.8

2015 Distributions:
 
 
 
 
 
 
 
 
February 6, 2015
 
February 27, 2015
 
93.7

 
$
0.49

 
$
45.6

Total distributions paid during 2015
 
 
 
 
 
$
0.49

 
$
45.6

 
 
 
 
 
 
 
 
 
Total distributions declared since our IPO
 
 
 
$
8.17

 
$
754.9

Notwithstanding our distribution policy, certain provisions of the indenture governing the 2020 Secured Notes and our ABL Facility may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us. See “Description of Our Indebtedness.”

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The following table details our calculation of cash available for distribution for the three months ended December 31, 2014 (in millions):
 
Three Months Ended December 31, 2014
 Net income
$
16.0

Adjustments:
 
Interest expense
7.5

Income tax provision
3.6

Depreciation and amortization
11.1

EBITDA subtotal
38.2

Lower of cost or market inventory adjustments(2)
73.6

MPL proportionate depreciation expense
0.8

Turnaround and related expenses
8.9

Equity-based compensation impacts
1.7

 Adjusted EBITDA(1)
123.2

Cash interest expense
(6.9
)
Current tax provision
(1.0
)
MPL proportionate depreciation expense
(0.8
)
Cash reserve for working capital requirements(3)
(55.2
)
Capital expenditures(4)
(6.2
)
Cash reserve for turnaround and related expenses(5)
(7.5
)
Cash Available for Distribution(6)
$
45.6

(1)
Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in calculating the components of various covenants in the agreements governing our 2020 Secured Notes and ABL Facility. We believe the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. The calculation of Adjusted EBITDA generally eliminates the effects of financings, income taxes and the accounting effects of significant turnaround activities which many of our peers capitalize and therefore exclude from Adjusted EBITDA. Adjusted EBITDA should not be considered as an alternative to operating income or net income as measures of operating performance. In addition, Adjusted EBITDA is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes and depreciation and amortization, adjusted for depreciation from the Minnesota Pipe Line operations, lower of cost or market inventory adjustments, turnaround and related expenses, equity-based compensation expense, gains or losses from crack spread derivative activities and costs related to our reorganization activities. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP. 
(2)
Includes adjustments from inventories stated at cost on a LIFO basis to lower market values as of period end. Quarterly non-cash lower of cost or market inventory adjustments are excluded from Adjusted EBITDA.
(3)
Includes a reserve to manage working capital requirements and provide ongoing liquidity.
(4)
Capital expenditures include maintenance, replacement and regulatory capital projects on an accrual basis.
(5)
Cash reserves are determined by the board of directors of our general partner primarily for the purposes of funding our turnaround and discretionary capital projects. Since spending may be significant in any given quarter, reserves are made over several quarters in order to mitigate the impact on cash available for distribution.
(6)
Cash available for distribution is a non-GAAP performance measure that we believe is important to investors in evaluating our overall cash generation performance. Cash available for distribution should not be considered as an alternative to operating income or net income (loss) as measures of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. We have reconciled cash available for distribution to Adjusted EBITDA and in addition reconciled Adjusted EBITDA to net income. Cash available for distribution has limitations as an analytical tool and

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should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP. Our calculation of cash available for distribution may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter.
Capital Spending
Total capital spend was $44.8 million for the year ended December 31, 2014. Capital spending for the year ended December 31, 2014 primarily included the updated wastewater treatment plant construction (approximately $15.4 million) at our refinery as well as safety related enhancements and facility improvements at the refinery and retail store locations. Capital spending for the year ended December 31, 2013 of $96.6 million was primarily related to the capacity expansion project on one of our crude distillation units, our wastewater treatment plant construction at our refinery as well as safety related enhancements and facility improvements at the refinery and retail store locations. We currently expect to spend approximately $70 million for full year 2015, which includes approximately $35 million in discretionary capital spending including new desalter equipment. The remaining projects primarily relate to safety/security and ongoing replacement spending also referred to as maintenance capital. The board of directors of our general partner may approve cash reserves for discretionary projects in determining cash available for distributions. These reserves would replenish cash used for discretionary projects in prior years and could be utilized for future discretionary projects.
Contractual Obligations and Commitments
We have the following contractual obligations and commitments as of December 31, 2014 (in millions):
 
 
Less than
1 year
 
1-3
years
 
3-5
years
 
More than
5 years
 
Total
Long-term debt(1)
 
$
26.9

 
$
53.8

 
$
53.3

 
$
375.0

 
$
509.0

Lease obligations(2)
 
23.9

 
48.3

 
45.8

 
142.2

 
260.2

Capital expenditures(3)
 
2.9

 

 

 

 
2.9

Environmental remediation costs
 
6.6

 
0.8

 
0.7

 
8.1

 
16.2

(1)
Long-term debt represents (i) the repayment of the $350 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 0.375% on an assumed $500 million undrawn balance under our ABL Facility with a maturity date in September, 2019.
(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, 2014, we have 133 SuperAmerica convenience stores and one support facility remaining under the Realty Income Lease.
Additionally, we utilize letters of credit through our ABL facility to provide collateral to certain suppliers that require it. These instruments require the payment of interest and fees but no liability is recognized for the principal amount of letters of credit outstanding. See Description of our Indebtedness below for more information.
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-based 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-based lending facility. That amendment provided for revolving credit financing through July 17, 2017 in an aggregate principal amount of up to $300 million. On September 29, 2014, we again amended our revolving credit agreement to increase the capacity to an aggregate principal amount of up to $500 million and to extend the maturity to September 29, 2019 (of which $150 million could 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 could be

75


increased up to a maximum aggregate principal amount of $750 million, subject to borrowing base availability and lender approval. Availability under our ABL Facility at any time will be the lesser of (a) the aggregate commitments under our ABL 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 the ABL Facility can be either base rate loans plus a margin ranging from 0.50% to 1.00% or LIBOR loans plus a margin ranging from1.50% to 2.00%, in each case subject to adjustment based upon the average historical excess availability. The ABL Facility also provides for a quarterly commitment fee ranging from 0.25% to 0.375% per annum, subject to adjustment based upon the average utilization ratio, and letter of credit fees ranging from 1.50% to 2.00% per annum payable quarterly, subject to adjustment based upon the average historical excess availability.
Our ABL 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.
Our ABL 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 ABL Facility to be in full force and effect, and change of control. If such an event of default occurs, the lenders under our ABL Facility would be entitled to take various actions, including the acceleration of amounts due under our ABL Facility and all actions permitted to be taken by a secured creditor.
The facility may be used for general corporate purposes, including to fund working capital needs and letter of credit requirements. The Company incurred financing costs associated with the new ABL Facility of $3.0 million which will be amortized to interest expense through the date of maturity.
As of December 31, 2014, the availability under our ABL Facility was $296.2 million. This availability is net of $12.1 million in outstanding letters of credit as of December 31, 2014. We had no borrowings under our ABL Facility at December 31, 2014.
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 $275 million issued in 2012 were registered with the SEC and became publicly traded debt.
On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering will both be amortized as a net reduction to interest expense over the remaining life of the notes. The proceeds from this offering were used to finance a portion of the purchase of crude oil inventories previously held by JPM CCC as a result of our termination of the Crude Intermediation Agreement on September 30, 2014. Effective in January 2015, the $75.0 million issued in 2014 was 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-based ABL 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.

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The 2020 Secured Notes are the Notes Issuers’ general senior secured obligations that are effectively subordinated to the Notes Issuers’ obligations under our ABL 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 ABL 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.
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;

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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, 2014, 2013 and 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy.
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, 2014 of 93,525 bpd, would result in a change of $34.1 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 may also enter into derivative transactions to manage price risks associated with inventory quantities above or below target levels. 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.
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

78


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 $16.7 million and $12.4 million in our gross product margin on gasoline and distillate sales, respectively, based on our average refinery production for the year ended December 31, 2014 of 45,674 bpd and 33,910 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, 2014 and 2013, we had no hedged barrels of future gasoline and diesel production.
We periodically use futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. Under our risk mitigation strategy, we 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. We 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 our consolidated statements of operations. Observable quoted prices for similar assets or liabilities in active markets are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end.
Interest Rate Risk
Borrowings, if any, under our ABL Facility bear interest, at our election, at either an alternative base rate, plus an applicable margin (which ranges between 0.50% and 1.00% pursuant to a grid based on average excess availability) or a LIBOR rate plus an applicable margin (which ranges between 1.50% and 2.00% 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 ABL Facility.”
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.
We are exposed to credit risk in the event of nonperformance by our counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with credit ratings of at least A- by Standard and Poor’s and Baa1 by Moody’s. In the event of default, we would potentially be subject to losses on a derivative instrument’s mark-to-market gains. We do not expect nonperformance of the counterparties involved in our risk mitigation arrangements.

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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
Report of Independent Registered Accounting Firm as of December 31, 2014 and for the year ended December 31, 2014
Report of Independent Registered Accounting Firm on our assessment of the effectiveness over internal controls as of December 31, 2014
Report of Independent Registered Accounting Firm as of December 31, 2013 and for the years ended December 31, 2013 and December 31, 2012
Consolidated Balance Sheets
Consolidated Statements of Operations and Comprehensive Income
Consolidated Statements of Cash Flows
Consolidated Statements of Partners’ Capital and Member’s Interest
Notes to Consolidated Financial Statements

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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, 2014. 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 (2013). Based on its assessment, our management concludes that, as of December 31, 2014, 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, 2014 has been audited by Deloitte & Touche LLP , an independent registered public accounting firm, as stated in their report which appears herein.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the accompanying consolidated balance sheet of Northern Tier Energy LP and subsidiaries (the "Company") as of December 31, 2014, and the related consolidated statements of operations and comprehensive income, partners’ capital and member’s interest, and cash flows for the year then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the financial statements based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Northern Tier Energy LP and subsidiaries at December 31, 2014, and the results of their operations and their cash flows for the year then ended, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company's internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2015 expressed an unqualified opinion on the Company's internal control over financial reporting.


/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 27, 2015


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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

We have audited the internal control over financial reporting of Northern Tier Energy LP and subsidiaries (the "Company") as of December 31, 2014, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company's management is responsible 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 an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's 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. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) 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 (3) 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 the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Company and our report dated February 27, 2015 expressed an unqualified opinion on those financial statements.


/s/ Deloitte & Touche LLP
Minneapolis, Minnesota
February 27, 2015


83


Report of Independent Registered Public Accounting Firm

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

In our opinion, the accompanying consolidated balance sheet as of December 31, 2013 and the related consolidated statements of operations and comprehensive income, of partners’ capital and member’s interest and cash flows for each of two years in the period ended December 31, 2013 present fairly, in all material respects, the financial position of Northern Tier Energy LP and its subsidiaries at December 31, 2013, and the results of their operations and their cash flows for each of the two years in the period ended December 31, 2013, in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.


/s/PricewaterhouseCoopers LLP
Minneapolis, Minnesota

February 27, 2014, except for the effects of the reclassification of derivative activities described in Note 2 to the consolidated financial statements, as to which the date is February 27, 2015.

 



84



NORTHERN TIER ENERGY LP
CONSOLIDATED BALANCE SHEETS
(in millions, except unit data) 
 
December 31, 2014
 
December 31, 2013
ASSETS
 
 
 
CURRENT ASSETS
 
 
 
Cash and cash equivalents
$
87.9

 
$
85.8

Accounts receivable
236.0

 
242.0

Inventories
252.1

 
173.5

Other current assets
15.2

 
23.7

Total current assets
591.2

 
525.0

NON-CURRENT ASSETS
 
 
 
Equity method investment
80.7

 
86.2

Property, plant and equipment, net
445.8

 
446.2

Intangible assets
33.8

 
33.8

Other assets
28.9

 
26.6

Total Assets
$
1,180.4

 
$
1,117.8

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES
 
 
 
Accounts payable
334.3

 
367.0

Accrued liabilities
52.6

 
48.5

Total current liabilities
386.9

 
415.5

NON-CURRENT LIABILITIES
 
 
 
Long-term debt
354.2

 
275.0

Lease financing obligation
8.6

 
8.4

Other liabilities
27.0

 
17.8

Total liabilities
776.7


716.7

Commitments and contingencies

 

EQUITY
 
 
 
Partners' capital (92,712,744 and 92,100,363 units issued and outstanding at December 31, 2014 and 2013, respectively)
406.9

 
403.1

Accumulated other comprehensive loss
(3.2
)
 
(2.0
)
Total equity
403.7

 
401.1

Total Liabilities and Equity
$
1,180.4

 
$
1,117.8

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

85


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,
 
2014
 
2013
 
2012
REVENUE (a)
$
5,556.0

 
$
4,979.2

 
$
4,653.9

COSTS, EXPENSES AND OTHER
 
 
 
 
 
Cost of sales (a)
4,835.9

 
4,284.2

 
3,586.6

Direct operating expenses
288.8

 
262.4

 
254.1

Turnaround and related expenses
14.9

 
73.3

 
26.1

Depreciation and amortization
41.9

 
38.1

 
33.2

Selling, general and administrative
87.8

 
85.8

 
88.3

Reorganization and related costs
12.9

 
3.1

 
1.4

Contingent consideration loss

 

 
104.3

Income from equity method investment
(2.2
)

(10.0
)

(12.3
)
Other (income) loss, net
0.7

 
(3.8
)
 
2.9

OPERATING INCOME
275.3


246.1


569.3

Gains (losses) from derivative activities

 
16.1

 
(269.7
)
Interest expense, net
(26.6
)
 
(26.9
)
 
(42.2
)
Loss on early extinguishment of debt

 

 
(50.0
)
INCOME BEFORE INCOME TAXES
248.7

 
235.3

 
207.4

Income tax provision
(7.1
)
 
(4.2
)
 
(9.8
)
NET INCOME
241.6

 
231.1

 
197.6

Other comprehensive (loss) income, net of tax
(1.2
)
 
0.5

 
(2.1
)
COMPREHENSIVE INCOME
$
240.4

 
$
231.6

 
$
195.5

EARNINGS PER UNIT INFORMATION:
 
 
 
 
 
Net Income
$
241.6

 
$
231.1

 
$
197.6

Net Income prior to initial public offering on July 31, 2012

 

 
(70.7
)
Net Income available to common unitholders
$
241.6

 
$
231.1

 
$
126.9

 
 
 
 
 
 
Weighted average number of units outstanding:
 
 
 
 
 
Basic
92,222,793

 
91,915,335

 
91,915,000

Diluted
92,260,045

 
91,915,335

 
91,915,000

Earnings per unit:
 
 
 
 
 
Basic
$
2.61

 
$
2.51

 
$
1.38

Diluted
$
2.61

 
$
2.51

 
$
1.38

SUPPLEMENTAL INFORMATION:
 
 
 
 
 
(a) Excise taxes included in revenue and cost of sales
$
396.4

 
$
316.4

 
$
300.1

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

86


NORTHERN TIER ENERGY LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
 
For the year ended December 31,
Increase (decrease) in cash
2014
 
2013
 
2012
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
 
 
Net income
$
241.6

 
$
231.1

 
$
197.6

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization
41.9

 
38.1

 
33.2

Non-cash interest expense
2.8

 
2.4

 
7.5

Equity-based compensation expense
14.0

 
7.1

 
0.9

Loss on extinguishment of debt

 

 
50.0

Deferred income taxes
2.6

 
0.9

 
9.8

Contingent consideration loss

 

 
104.3

Loss (gain) from the change in fair value of outstanding derivatives
2.8

 
(41.6
)
 
(68.0
)
Loss from lower of cost or market inventory adjustment
73.6

 

 

Changes in assets and liabilities, net:
 
 
 
 
 
Accounts receivable
6.0

 
(112.7
)
 
(47.7
)
Inventories
(152.3
)
 
(11.1
)
 
(8.3
)
Other current assets
9.8

 
8.3

 
5.6

Accounts payable and accrued liabilities
(28.5
)
 
110.3

 
29.9

Other, net
5.3

 
(3.0
)
 
(6.3
)
Net cash provided by operating activities
219.6

 
229.8

 
308.5

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
 
 
Capital expenditures
(44.8
)
 
(96.6
)
 
(30.9
)
Return of capital from investments
5.3

 
1.1

 
2.2

Net cash used in investing activities
(39.5
)
 
(95.5
)
 
(28.7
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
 
 
Borrowings from senior secured notes
79.2

 

 
275.0

Repayments of senior secured notes

 

 
(290.0
)
Premiums paid to extinguish debt

 

 
(39.5
)
Borrowings from revolving credit arrangement
30.0

 
50.0

 

Repayments of revolving credit arrangement
(30.0
)
 
(50.0
)
 

Proceeds from IPO, net of direct costs of issuance

 

 
230.4

Financing costs
(5.4
)
 

 
(6.1
)
Equity distributions
(251.8
)
 
(321.4
)
 
(300.2
)
Net cash used in financing activities
(178.0
)
 
(321.4
)
 
(130.4
)
CASH AND CASH EQUIVALENTS
 
 
 
 
 
Change in cash and cash equivalents
2.1

 
(187.1
)
 
149.4

Cash and cash equivalents at beginning of period
85.8

 
272.9

 
123.5

Cash and cash equivalents at end of period
$
87.9

 
$
85.8

 
$
272.9

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

87


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 (loss)
 
 
 
 
Member's Interest
 
Common Units
 
Value
 
 
Total
Balance at December 31, 2012
 
$
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 ($1.48 per unit)
 

 

 
(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 ($3.49 per unit)
 

 

 
(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

Net income
 

 

 
241.6

 

 
241.6

Distributions to limited partners ($2.71 per unit)
 

 

 
(251.8
)
 

 
(251.8
)
Other comprehensive loss
 

 

 

 
(1.2
)
 
(1.2
)
Equity-based compensation, net of forfeitures
 

 
612,381

 
14.0

 

 
14.0

Balance at December 31, 2014
 
$


92,712,744


$
406.9


$
(3.2
)

$
403.7

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

88


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 and a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”). MPL Investments 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 5, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed all of its 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. At the time of this transaction, Western Refining indirectly owned 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, 2014, SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 97,800 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, 2014, NTR operates 165 convenience stores under the SuperAmerica brand and SAF supports 89 franchised stores which also utilize the SuperAmerica brand. These 254 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”).

89


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 direct subsidiaries.
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.
MPL Investments owns all of the preferred membership units of MPL. This investment in MPL Investments, which provides the Company no significant influence over MPL Investments, is accounted for as a cost method investment. The investment in MPL Investments is carried at a value of $6.8 million as of both December 31, 2014 and 2013 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 MPL Investments, and
Retail – operates 165 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of SAF and NTB.
Cash and Cash Equivalents
The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.
Receivables and Allowance for Doubtful Accounts
Receivables of the Company 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 regularly 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 as of both December 31, 2014 and 2013.
Inventories
Crude oil, refined product and other feedstock and blendstock inventories are carried at the lower of cost or market ("LCM"). Cost is determined principally under the last-in, first-out (“LIFO”) valuation method to reflect a better matching of costs and revenues for refining inventories. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of sales in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances. 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. Retail merchandise inventory is valued using the average cost method.

90


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 or asset groups 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.
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 or 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.
Renewable Identification Numbers
The Company is subject to obligations to generate or purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy our RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in accrued liabilities when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in other current assets when the amount of RINs earned and purchased is greater than the RINs liability.
Financing Costs
Financing origination fees on the Company's senior secured notes, ABL 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.
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.
Nonmonetary product exchanges and certain buy/sell crude oil transactions which are entered into in contemplation one with another are included on a net cost basis in cost of sales. The Company also enters into agreements to purchase and sell crude oil to third parties and certain of these activities are recorded on a gross basis.
Prior to the fourth quarter of 2014, the Company maintained a crude oil supply and logistics agreement with JPM CCC pursuant to which JPM CCC assisted the Company in the purchase of substantially all of its crude oil needs for the refinery. As discussed in Note 7, JPM CCC and the Company mutually agreed to terminate this agreement. In the fourth quarter of 2014, subsequent to the termination of this agreement, the Company has significantly increased its crude procurement activities and related exchange and buy/sell activity to manage the volumes, grade, timing, and locations of such crude. Such activities are similar to the buy/sell crude oil transactions noted above and are recorded net in cost of sales.



91


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 recorded net in cost of sales 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.
Cost of Sales
Cost of sales in the consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.
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 $396.4 million, $316.4 million and $300.1 million for the years ended December 31, 2014, 2013 and 2012, respectively.
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 futures and swap contracts may be used to hedge the volatility of refining margins. The Company may also use futures contracts to manage price risks associated with inventory quantities above or below target levels. 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 the statements of operations. Gains and losses from derivative activity specific to the mitigation on inventory quantities are included within cost of sales. Gains and losses from derivative activity specific to the risk mitigation on the crack spread futures and swap derivatives are included within gains (losses) on derivative activities. Derivative gains and losses are reported as operating activities within the consolidated statements of cash flows.
We enter into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts may qualify for the normal purchases and normal sales exception because we physically receive and deliver the crude oil under the contracts and when we enter into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in the period that delivery of the crude oil takes place.
Advertising
The Company expenses the costs of advertising as incurred. Advertising expense was $2.3 million, $2.0 million and $1.5 million for the years ended December 31, 2014, 2013 and 2012, respectively.
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. See further information on our asset retirement obligations in Note 15.
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 feasibility studies, investigations or the commitment to a formal plan of

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action. Environmental liabilities are difficult to assess and estimate due to uncertainties related to the magnitude of possible remediation and the timing of such remediation. Such estimates are subject to change due to many factors, including the identification of new sites requiring remediation, changes in environmental laws and regulations and their interpretation, additional information related to the extent and nature of remediation efforts and potential improvements in remediation technologies. 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 cash balance 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.
Cash balance 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.
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. In 2014, the Company began awarding phantom common units which, at the discretion of the board of directors of our general partner, may be settled in either cash or the Company's common units. The first tranche of phantom unit vesting occurred in January 2015 and was settled in common units. We anticipate that the remaining unvested phantom units will ultimately be satisfied with common units and have therefore classified the accrual of the service cost as equity. However, if our general partner's board elects to settle the phantom units with cash, it could cause us to remeasure the fair value of those awards resulting in an adjustment to earnings for the cumulative difference between the fair value at the date of grant and date of the remeasurement.
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.
Comprehensive Income
The Company has unrecognized prior service cost related to its defined benefit cash balance plan as of December 31, 2014, 2013 and 2012 and unrecognized actuarial losses and prior service cost related to its retiree medical plan as of December 31, 2014 and 2013 (see Note 17). The accumulated unrecognized costs related to these plans amount to $3.2 million and $2.0 million as of December 31, 2014 and 2013, respectively. These gains/(losses) of $(1.2) million, $0.5 million and $(2.1) million were recognized directly to equity as an element of other comprehensive income (loss) in the years ended December 31, 2014, 2013 and 2012, 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.

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Reclassifications
Certain reclassifications have been made to the prior-year financial information in order to conform to the Company’s current presentation, which is intended to conform with Western Refining's presentation. The following reclassifications have been made:
Derivatives
Related to our derivative activities, a $7.4 million net gain and a $1.7 million net loss from derivative activity not related to our crack spread hedges have been reclassified from gains (losses) from derivative activities to cost of sales for the years ended December 31, 2013 and 2012, respectively, within the consolidated statements of operations and comprehensive income.
Income from equity method investment
Income from our equity method investment in MPL has been reclassified from other (income) loss, net to a separate line titled income from equity method investment. The amount of this reclassification was income of $10.0 million and $12.3 million for the years ended December 31, 2013 and 2012, respectively.
Recent Accounting Pronouncements
In April 2014, the Financial Accounting Standards Board (“FASB”) issued ASU No. 2014-08, which updated the guidance in ASC Topic 205, “Presentation of Financial Statements”, and ASC Topic 360, “Property, Plant and Equipment.” This ASU raises the threshold for a disposal to qualify as discontinued operations and requires new disclosures for individual material disposal transactions that do not meet the definition of a discontinued operation.  Under the new standard, companies report discontinued operations when they have a disposal that represents a strategic shift that has or will have a major impact on operations or financial results.  This update will be applied prospectively and is effective for annual periods, and interim periods within those years, beginning after December 15, 2014.  Early adoption is permitted provided the disposal was not previously disclosed.  The adoption of this guidance is not expected to have a material impact on our results of operations, cash flows or financial position.
In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition. The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance will be effective for our financial statements in the annual period beginning after December 15, 2016. We are evaluating the effect of adopting this new accounting guidance we do not expect adoption will have a material impact on our results of operations, cash flows or financial position.
In August 2014, the FASB issued ASU No. 2014-15 “Presentation of Financial Statements - Going Concern,” which sets forth new provisions that require management of an entity to evaluate whether there is substantial doubt about the entity's ability to continue as a going concern and to provide related footnote disclosures. This guidance will become effective for annual periods beginning after December 15, 2016, and for annual periods and interim periods thereafter with early application permitted. The changed requirements are intended to reduce diversity in the timing and content of footnote disclosures. We do not expect the adoption of these new provisions to materially affect 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.

94


In connection with the closing of the IPO the following transactions and events occurred in the third quarter of 2012: 
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 original investors in NTE LLC, which included ACON Refining Partners L.L.C. and TPG Refining L.P., were related parties of the Company from inception through November 12, 2013, the date they sold their remaining indirect interest in the Company to a subsidiary of Western Refining (see Note 1). Upon execution of that transaction, Western Refining became a related party to the Company. For the year ended December 31, 2014, the Company purchased $6.3 million of crude oil from a subsidiary of Western Refining. During the year ended December 31, 2014, the Company sold asphalt and RINs at market price totaling $19.0 million to Western Refining (see Note 2). Additionally, for the year ended December 31, 2014, the Company realized $0.1 million in lease revenue from the sublease of railcars to a subsidiary of Western Refining.
On October 30, 2014, the Company entered into a shared services agreement with Western Refining whereby the Company receives administrative support services. The shared services agreement is effective as of September 1, 2014, and was approved by the Conflicts Committee of the Company's Board of Directors. These services include assistance with treasury, risk management and commercial operations, environmental compliance, information technology support, legal and others. For the year ended December 31, 2014, the Company recognized $1.1 million in expense for these services, which are included in selling, general and administrative expenses. As of December 31, 2014, Western Refining owed the Company $5.1 million. There were no related party transactions with Western Refining during the year ended December 31, 2013.
MPL is also a related party of the Company, however the Company had a crude oil supply and logistics agreement with a third party until September 30, 2014 and had no direct supply transactions with MPL prior to this date. Beginning on September 30, 2014, the Company began paying MPL for transportation services at published tariff rates. During the year ended December 31, 2014, we incurred $12.6 million in crude transportation costs with MPL. As of December 31, 2014, the Company owed MPL $2.1 million.
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 for the year ended December 31, 2012. 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. Included in the purchase agreement were 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 arrangements. The settlement agreement was contingent upon the consummation of the IPO, which occurred on July 31, 2012 (see Note 3). 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.

95


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 income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable.
 
 
Year Ended December 31,
(in millions)
 
2014
 
2013
 
2012
Current tax expense
 
$
4.5

 
$
3.3

 
$

Deferred tax expense
 
$
2.6

 
$
0.9

 
$
9.8

Income tax provision
 
$
7.1

 
$
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, 2014, 2013 and 2012 was 2.9%, 1.8% and 4.7%, respectively, as compared to the Company's consolidated federal and state expected statutory tax rate of 40.4% for all periods. The Company's effective tax rate was lower than the statutory rate for the years ended December 31, 2014, 2013 and 2012 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 income tax expense to income taxes computed by applying the applicable statutory federal income tax rate of 35% to income before income taxes for the applicable periods:
 
 
Year Ended December 31,
(in millions)
 
2014
 
2013
 
2012
Federal statutory rate applied to income before taxes
 
$
87.0

 
$
82.4

 
$
72.6

Taxes on earnings attributable to flow-through entities
 
(81.0
)
 
(78.6
)
 
(71.6
)
State and local income taxes, net of federal income tax effects
 
1.0

 
0.9

 

Initial charge upon NTRH's election to be treated as a corporation
 

 

 
8.0

Work opportunity tax credit
 
(0.3
)
 
(0.6
)
 

Other, net
 
0.4

 
0.1

 
0.8

Income tax provision
 
$
7.1

 
$
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 in 2013. As of December 31, 2014 and 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. The Company classifies interest to be paid on an underpayment of income taxes and any related penalties as income tax expense.

96


The net deferred tax assets (liabilities) as of December 31, 2014 and 2013 consisted of the following components:
 
 
 
 
December 31,
(in millions)
 
2014
 
2013
Deferred tax assets:
 
 
 
 
 
Lease financing obligations
 
2.4

 
2.6

 
Customer loyalty accrual
 
0.9

 
0.9

 
Other
 
0.8

 
1.1

Total deferred taxes, net
 
4.1

 
4.6

 
 
 
 
 
Deferred tax liabilities:
 
 
 
 
 
Accelerated depreciation
 
$
(5.4
)
 
$
(3.4
)
 
Intangible assets
 
(11.8
)
 
(11.7
)
 
Other
 
(0.2
)
 
(0.2
)
Deferred tax liabilities
 
(17.4
)
 
(15.3
)

 
$
(13.3
)
 
$
(10.7
)
The net deferred tax assets (liabilities) are included in the December 31, 2014 and 2013 balance sheets as components of other current assets and other liabilities.
7. INVENTORIES
 
 
December 31,
(in millions)
2014
 
2013
Crude oil and refinery feedstocks
$
137.5

 
$
29.4

Refined products
150.0

 
106.7

Merchandise
22.3

 
22.6

Supplies and sundry items
15.9

 
14.8

 
325.7

 
173.5

Lower of cost or market inventory reserve
(73.6
)
 

Total
$
252.1

 
$
173.5

Inventories accounted for under the LIFO method comprised 88% and 78% of the total inventory value at December 31, 2014 and 2013, respectively.
Historically, the Company maintained a crude oil supply and logistics agreement with JPM CCC pursuant to which JPM CCC assisted the Company in the purchase of the crude oil for its storage tanks at Cottage Grove, Minnesota, which are approximately two miles from the refinery. Upon delivery of the crude oil to the Company, we paid JPM CCC the price of the crude oil plus certain agreed fees and expenses. JPMorgan Chase & Co. had announced its intention to sell the physical portions of its commodities business (which includes JPM CCC) to Mercuria Energy Group Ltd. during the fourth quarter of 2014. In advance of this sale, JPM CCC and the Company mutually agreed to terminate the Crude Intermediation Agreement. This resulted in our acquisition of approximately 1.2 million barrels of crude oil inventory from JPM CCC as of September 30, 2014. This purchase of crude oil from JPM CCC in September 2014 resulted in an additional layer of inventory subject to the LIFO valuation method.
In the fourth quarter of 2014, market prices of feedstocks and refined products decreased significantly. Because of this, the Company reduced the carrying value of its inventory by $73.6 million in order to state the value at market prices, which were lower than our LIFO cost at December 31, 2014.
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. There were no such LIFO liquidations during 2014 or 2012.

97


8. EQUITY METHOD INVESTMENT
The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $80.7 million and $86.2 million at December 31, 2014 and 2013, respectively.
Summarized financial information for MPL is as follows:
 
 
 
 
Year Ended December 31,
(in millions)
 
2014
 
2013
 
2012
Revenues
 
$
184.7

 
$
161.9

 
$
153.6

Operating costs and expenses
 
141.3

 
74.5

 
52.7

Income from operations
 
43.4

 
68.2

 
82.1

Net income
 
22.8

 
68.2

 
82.1

Net income available to MPL common members
 
13.1

 
58.6

 
72.4

 
 
 
 
December 31,
(in millions)
 
2014
 
2013
Balance sheet data:
 
 
 
 
 
Current assets
 
$
9.6

 
$
26.1

 
Noncurrent assets
 
450.7

 
462.9

 
 
Total assets
 
$
460.3

 
$
489.0

 
 
 
 
 
 
 
 
Current liabilities
 
$
21.9

 
$
19.8

 
Noncurrent liabilities
 

 

 
 
Total liabilities
 
$
21.9

 
$
19.8

 
Members capital
 
$
438.4

 
$
469.2

As of December 31, 2014 and 2013, the carrying amount of the equity method investment was $6.2 million and $6.4 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 $7.5 million, $11.1 million and $14.5 million for the years ended December 31, 2014, 2013 and 2012, respectively. Equity income from MPL was $2.2 million, $10.0 million and $12.3 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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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
 
2014
 
2013
Land
 
 
$
9.0

 
$
9.0

Retail stores and equipment
2 - 22 years
 
65.7

 
54.9

Refinery and equipment
5 - 24 years
 
444.6

 
403.5

Buildings and building improvements
25 years
 
10.2

 
8.9

Software
5 years
 
18.8

 
18.6

Vehicles
5 years
 
4.7

 
4.7

Other equipment
2 - 7 years
 
9.1

 
8.5

Precious metals
 
 
10.2

 
10.2

Assets under construction
 
 
12.6

 
26.3

 
 
 
584.9

 
544.6

Less: Accumulated depreciation
 
 
(139.1
)
 
(98.4
)
Property, plant and equipment, net
 
 
$
445.8

 
$
446.2

PP&E includes gross assets acquired under capital leases of $10.8 million and $8.6 million at December 31, 2014 and 2013, respectively, with related accumulated depreciation of $1.7 million and $1.2 million, respectively. The Company had depreciation expense related to capitalized software of $3.7 million, $3.7 million and $3.2 million for years ended December 31, 2014, 2013 and 2012, respectively.
10. INTANGIBLE ASSETS
Intangible assets are comprised of franchise rights and trade name amounting to $33.8 million at both December 31, 2014 and 2013. At both December 31, 2014 and 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 are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. Historically, the Company performed its annual indefinite lived intangible testing as of October 31. During 2014, we changed the date of our annual impairment test to June 30. Based on the testing performed as of June 30, 2014, the Company noted no indications of impairment.
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 reorganization and related 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. Historically, the Company entered into crack spread derivative contracts as a strategy to mitigate refining margin risk on a portion of its 2011 through 2013 projected refining production. As of December 31, 2013, all of the Company's crack spread derivative contracts had expired and, as such, at both December 31, 2014 and 2013, the Company had no open crack spread derivative instruments.
The Company periodically use futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. Under the Company's risk mitigation strategy, it 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 in 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.

99


At December 31, 2014 and 2013, the Company had open commodity derivative instruments as follows:
 
December 31,
 
2014
 
2013
 
(in thousands of barrels or barrels of oil equivalent)
Open commodity hedging instruments:
 
 
 
Crude oil and refined product futures and swaps, net short positions
(124
)
 

Natural gas swaps, net long positions
617

 

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:
 
 
Year Ended December 31,
(in millions)
 
2014
 
2013
 
2012
Gain (loss) on the change in fair value of outstanding derivatives
 
$
(2.8
)
 
$
41.6

 
$
68.0

Settled derivative gains (losses)
 
12.4

 
(18.1
)
 
(339.4
)
Total recognized gain (loss)
 
$
9.6

 
$
23.5

 
$
(271.4
)
 
 
 
 
 
 
 
Gain (loss) recognized in Cost of sales
 
$
9.6

 
$
7.4

 
$
(1.7
)
Gain (loss) recognized in Gains (losses) from derivative activities
 

 
16.1

 
(269.7
)
Total recognized net gain (loss) on derivatives
 
$
9.6

 
$
23.5

 
$
(271.4
)
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 were fully paid by January 2014. The early extinguishments were treated as a current period loss as of the date of extinguishment. Interest accrued 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.

100


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, 2014 and 2013:
 
 
 
 
December 31,
(in millions)
 
Balance Sheet Classification
 
2014
 
2013
Commodity swaps and futures
 
Other current assets
 
$
1.7

 
$

Commodity swaps and futures
 
Accrued liabilities
 
(4.1
)
 

Commodity swaps and futures
 
Other liabilities
 
$
(0.4
)
 
$

Net asset (liability) position
 
 
 
$
(2.8
)
 
$

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at December 31, 2014:
 
Notional Contract Volumes by Year of Maturity
 
2014
 
2015
 
(in thousands of barrels or barrels of oil equivalent)
Open commodity hedging instruments:
 
Crude oil and refined product futures and swaps, net short positions
(124
)
 

Natural gas swaps, net long positions
419

 
198

The Company is exposed to credit risk in the event of nonperformance by our counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with credit ratings of at least A- by Standard and Poor’s and Baa1 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.
12. DEBT
ABL Facility
On September 29, 2014, the Company and its subsidiaries entered into an amended and restated asset-based ABL Facility with JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as collateral agent for the other secured parties. The borrowers under the ABL Facility are SPPR, NTB, NTR and SAF, each of which is a wholly owned subsidiary of the Company.
Lenders under the ABL Facility hold commitments totaling $500 million, all of which mature on September 29, 2019. Borrowings under the ABL Facility can be either base rate loans plus a margin ranging from 0.50% to 1.00% or LIBOR loans plus a margin ranging from 1.50% to 2.00%, in each case subject to adjustment based upon the average historical excess availability. The ABL Facility also provides for a quarterly commitment fee ranging from 0.25% to 0.375% per annum, subject to adjustment based upon the average utilization ratio, and letter of credit fees ranging from 1.50% to 2.00% per annum payable quarterly, subject to adjustment based upon the average historical excess availability. The facility may be used for general corporate purposes, including to fund working capital needs and letter of credit requirements. The Company incurred financing costs associated with the new ABL Facility of $3.0 million which are being amortized to interest expense through the date of maturity.
The ABL Facility is guaranteed, on a joint and several basis, by the Company and its subsidiaries and will be guaranteed by any newly acquired or formed subsidiaries, subject to certain limited exceptions. The ABL Facility and such guarantees are secured on a first priority basis by substantially all of the Company and such subsidiaries’ cash and cash equivalents, accounts receivable and inventory and on a second priority basis by the Company and such subsidiaries’ fixed assets (other than real property).
The ABL Facility contains certain covenants, including but not limited to limitations on debt, liens, investments, and dividends and the maintenance of a minimum fixed charge coverage ratio in certain circumstances.
Borrowing availability under the ABL Facility is tied to a borrowing base dependent upon the amount of eligible accounts receivable and inventory. As of December 31, 2014, the borrowing base under the ABL Facility was $308.3 million and availability under the ABL Facility was $296.2 million (which is net of $12.1 million in outstanding letters of credit). The Company had no borrowings under the ABL Facility at December 31, 2014.

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2020 Secured Notes
At December 31, 2014 and 2013, NTE LLC had outstanding $354 million and $275 million, respectively, in aggregate principal amount of 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering will both be amortized as a net reduction to interest expense over the remaining life of the notes.
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 guaranteed on a full and unconditional basis as a result of subsidiaries being released as guarantors. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary being 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 consolidated financial information is not included as the guarantor company, NTE LP, does not have independent assets or operations. 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 $500 million secured asset-based ABL Facility with a maturity date of September 29, 2019. Additionally, the 2020 Secured Notes are fully and unconditionally guaranteed on a senior unsecured basis by NTE LP. NTE LP's creditors have no recourse to the assets of Western Refining and its subsidiaries. Western Refining's creditors have no recourse to the assets of NTE LP and its subsidiaries. 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 2020 Secured Notes maturing on November 15, 2020. Effective in October 2013, the original issue of $275 million of the 2020 Secured Notes were registered with the SEC. In January 2015, the follow on offering of $75.0 million was also registered with the SEC.
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.
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 equity interests, to purchase, redeem or otherwise acquire or retire its equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of its property or assets, to merge, consolidate, lease or sell substantially all of the Company’s assets, to suffer a change of control or to enter into new lines of business.
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.
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

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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.
For the year ended December 31, 2013, the Company recognized a charge of $3.1 million for equity offering costs that did not meet the requirements for deferral, related to a secondary public offering of common units held by the owner of the Company's general partner interest at that time, NT Holdings.
Western Refining Acquisition
On November 5, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and later contributed all of its 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, on November 12, 2013, NT Holdings entered into a definitive agreement to sell all of its 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 owned 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 generally 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.

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The following table details the quarterly distributions paid to common unitholders since our IPO in July 2012 (in millions, except per unit amounts):
Date Declared
 
Date Paid
 
Common Units and equivalents (in millions)
 
Distribution per common unit and equivalent
 
Total Distribution (in millions)
2012 Distributions:
 
 
 
 
 
 
 
 
November 12, 2012
 
November 29, 2012
 
92.0

 
$
1.48

 
$
136.1

Total distributions paid during 2012
 
 
 
 
 
$
1.48

 
$
136.1

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
 
92.7

 
$
0.41

 
$
38.0

May 6, 2014
 
May 30, 2014
 
93.0

 
$
0.77

 
71.6

August 5, 2014
 
August 29, 2014
 
93.0

 
$
0.53

 
49.3

November 4, 2014
 
November 25, 2014
 
93.1

 
$
1.00

 
92.9

Total distributions paid during 2014
 
 
 
 
 
$
2.71

 
$
251.8

On February 6, 2015, the Company declared a quarterly distribution of $0.49 per unit to common unitholders of record on February 17, 2015, payable on February 27, 2015. This distribution of approximately $45.6 million in aggregate is based on available cash generated during the three months ended December 31, 2014.
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 to NT Holdings in 2012.
Earnings per Unit
The following tables illustrate the computation of basic and diluted earnings per unit for the years ended December 31, 2014, 2013 and 2012. 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 this method, distributed earnings and undistributed earnings are allocated between unrestricted common units and restricted common units.
 
 
Year Ended December 31,
(in millions, except unit and per-unit data)
 
2014
 
2013
 
2012
Net income available to common unitholders (a)
 
$
241.6

 
$
231.1

 
$
126.9

Less: income allocated to participating securities
 
(1.1
)
 
(0.6
)
 

Net income attributable to unrestricted common units
 
$
240.5

 
$
230.5

 
$
126.9

 
 
 
 
 
 
 
Weighted average unrestricted common units - basic
 
92,222,793

 
91,915,335

 
91,915,000

Plus: dilutive potential common securities
 
37,252

 

 

Weighted average unrestricted common units - diluted
 
92,260,045

 
91,915,335

 
91,915,000

 
 
 
 
 
 
 
Basic earnings per unit
 
$
2.61

 
$
2.51

 
$
1.38

Diluted earnings per unit
 
$
2.61

 
$
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

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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, 2014 and 2013:
 
 
Balance at
 
Quoted prices in active markets
 
Significant other observable inputs
 
Unobservable inputs
(in millions)
 
December 31, 2014
 
(Level 1)
 
 (Level 2)
 
 (Level 3)
ASSETS
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
87.9

 
$
87.9

 
$

 
$

Other current assets
 
 
 
 
 
 
 
 
Derivative asset - current
 
1.7

 

 
1.7

 

 
 
$
89.6

 
$
87.9

 
$
1.7

 
$

 
 
 
 
 
 
 
 
 
LIABILITIES
 
 
 
 
 
 
 
 
Accrued liabilities
 
 
 
 
 
 
 
 
Derivative liability - current
 
$
4.1

 
$

 
$
4.1

 
$

Other liabilities
 
 
 
 
 
 
 
 
Derivative liability - long-term
 
0.4

 

 
0.4

 

 
 
$
4.5


$


$
4.5


$

 
 
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

 
$

 
$

As of December 31, 2014 and 2013, 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

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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.
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, 2014 and 2013, 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, 2014, 2013 and 2012 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, 2014
 
December 31, 2013
(in millions)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
2020 Secured Notes
 
$
354.2

 
$
351.3

 
$
275.0

 
$
291.1

15. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in asset retirement obligations: 
 
 
Year Ended December 31,
(in millions)
 
2014
 
2013
 
2012
Asset retirement obligation balance at beginning of period
 
$
2.2

 
$
1.9

 
$
1.5

Revisions of previous estimates
 

 

 
0.2

Accretion expense
 
0.2

 
0.3

 
0.2

Asset retirement obligation balance at end of period
 
$
2.4

 
$
2.2

 
$
1.9

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 $14.0 million, $7.1 million and $0.9 million for the years ended December 31, 2014, 2013 and 2012, respectively, related to these plans. This expense is included in selling, general and administrative expenses and reorganization and related costs (see Note 22) in the consolidated statements of operations and comprehensive income.
LTIP
Approximately 8.1 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, distribution equivalent rights, unit appreciation rights and other awards that derive their value from the market price of NTE LP’s common units. As of December 31, 2014, approximately 0.7 million units were outstanding under the LTIP. The Company recognizes the expense on all LTIP awards 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 forfeiture rate which is subject to revision depending on the actual forfeiture experience.
As of December 31, 2014 and 2013, the total unrecognized compensation cost for LTIP restricted units was $12.1 million and $6.1 million, respectively.
Restricted Common Units
As of December 31, 2014, the Company had 0.4 million restricted common units outstanding. Upon vesting, these common units will no longer be restricted. All restricted common units participate in distributions on an equal basis with common units

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and any such distributions must be paid no later than 30 days after the distribution date to common unitholders. For restricted common unit awards outstanding at December 31, 2014, the forfeiture rates on LTIP awards ranged from zero to 30%, depending on the employee classification and the length of the award's vesting period.
A summary of the restricted common unit activity is set forth below:
 
 
 
Number of
 
Weighted
 
Weighted Average Term
 
 
restricted common units
 
Average Grant
 
Until Maturity
 
 
(in thousands)
 
Date Price
 
(years)
Outstanding at December 31, 2012
 
6.1

 
$
25.69

 
3.0

Awarded
 
321.9

 
27.02

 
3.5

Cancelled
 
(3.5
)
 
28.28

 

Vested
 
(17.9
)
 
26.38

 

Nonvested at December 31, 2013
 
306.6

 
$
27.02

 
2.9

Awarded
 
486.9

 
24.31

 
2.0

Cancelled
 
(7.2
)
 
25.21

 

Vested
 
(390.1
)
 
25.99

 

Nonvested at December 31, 2014
 
396.2

 
$
24.73

 
1.3

Phantom Common Units
In 2014, the Company began issuing time-based phantom common units to key employees. As of December 31, 2014, the Company had 0.3 million phantom common units outstanding. Upon vesting, the Company may settle these units in common units or cash at the discretion of the board of directors of NTE GP, or its compensation committee. Like the restricted common units, the phantom common units participate in distributions on an equal basis with common units. However, distributions on phantom common units are accrued until the underlying units vest at which time the distributions are paid in cash. In the event that unvested phantom common units are canceled, any accrued distributions on the underlying units are forfeited by the grantee. As of December 31, 2014, the Company had $0.8 million in accrued phantom common unit distributions located in accrued liabilities in the consolidated balance sheet. For phantom common unit awards outstanding at December 31, 2014, the forfeiture rates on LTIP awards ranged from 5% to 20%, depending on the employee classification.
A summary of the phantom common unit activity is set forth below: 
 
 
Number of
 
Weighted
 
Weighted Average Term
 
 
phantom common units
 
Average Grant
 
Until Maturity
 
 
(in thousands)
 
Date Price
 
(years)
Nonvested at December 31, 2013
 

 
$

 

Awarded
 
351.5

 
26.99

 
2.7

Cancelled
 
(12.9
)
 
27.01

 

Vested
 
(0.9
)
 
27.01

 
2.3

Nonvested at December 31, 2014
 
337.7

 
$
26.99

 
2.0

In January and February 2015, the Company issued an additional 0.7 million phantom common units to key employees and non-employee directors. These phantom units had an aggregate grant date fair value of $15.1 million and contain both time-based vesting and performance based vesting conditions expected to mature at the end of three years following at the issuance date.
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

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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 awards were issued or outstanding under this plan 2014 and 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:
 
 
Number of NT Investor Profit Units
 
Weighted Average Exercise Price
 
Weighted Average Remaining Contractual Term
 
 
(in millions)
 
 
 
(years)
Outstanding at December 31, 2012
 
19.5

 
1.96

 
8.1

  Vested
 
(19.5
)
 
1.96

 


Outstanding at December 31, 2013
 

 

 

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, was $0.88, based upon the following assumptions:
 
 
2012
Expected life (years)
 
6.5
Expected volatility
 
55.5%
Expected dividend yield
 
0.0%
Risk-free interest rate
 
1.4%
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 and 2012, the Company recognized $5.3 million and $0.9 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
The Company sponsors two 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 of a percentage of their annual compensation subject to Internal Revenue Service limits. For certain participant groups, the Company provides a matching contribution at the rate of 100% of up to 6.0% of a participant’s contribution and a non-matching contribution of 3.0% of eligible compensation. For other participant groups, the Company provides a non-elective fixed annual contribution of 3.5% of eligible compensation. Total Company contributions to the Retirement Savings Plans were $7.1 million, $6.1 million and $3.7 million for the years ended December 31, 2014, 2013 and 2012, respectively.
Cash Balance Plan
The Company sponsors 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
The Company also sponsors 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-

109


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.
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, 2014, 2013 and 2012 were as follows:
 
 
 
Cash Balance Plan
 
Retiree Medical Plan
 
 
 
Year Ended December 31,
 
Year Ended December 31,
(in millions)
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Change in benefit obligation:
 
 
 
 
 
 
 
 
 
 
 
 
Benefit obligation at beginning of year
$
4.6

 
$
2.3

 
$
0.5

 
$
2.1

 
$
2.4

 
$

 
 
Service cost
2.1

 
1.9

 
1.7

 
0.2

 
0.3

 
0.1

 
 
Interest cost
0.3

 
0.2

 
0.1

 
0.1

 
0.1

 
0.1

 
 
Actuarial loss (gain)
0.6

 
0.3

 
0.1

 
0.7

 
(0.6
)
 
0.8

 
 
Plan amendments

 

 

 

 

 
1.4

 
 
Benefits paid
(0.6
)
 
(0.1
)
 
(0.1
)
 

 
(0.1
)
 

 
Benefit obligation at end of year
7.0

 
4.6

 
2.3

 
3.1

 
2.1

 
2.4

Change in plan assets:
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of plan assets at beginning of year
4.6

 
2.1

 
0.1

 

 

 

 
 
Employer contributions
0.2

 
2.5

 
2.1

 

 
0.1

 

 
 
Return on plan assets
0.1

 
0.1

 

 

 

 

 
 
Benefits paid
(0.6
)
 
(0.1
)
 
(0.1
)
 

 
(0.1
)
 

 
Fair value of plan assets at end of year
4.3

 
4.6

 
2.1

 

 

 

Reconciliation of funded status:
 
 
 
 
 
 
 
 
 
 
 
 
Fair value of plan assets at end of year
4.3

 
4.6

 
2.1

 

 

 

 
Benefit obligation at end of year
7.0

 
4.6

 
2.3

 
3.1

 
2.1

 
2.4

 
Funded status at end of year
$
(2.7
)
 
$

 
$
(0.2
)
 
$
(3.1
)
 
$
(2.1
)
 
$
(2.4
)
At December 31, 2014 and 2013, the projected benefit obligations exceeded the fair value of the Plans’ assets by $5.8 million and $2.1 million, respectively. This unfunded obligation is classified in other liabilities on the consolidated balance sheets.
Our cash balance plan held investments in mutual funds of $4.3 million and $4.6 million at December 31, 2014 and 2013, respectively, that were valued using level 1 inputs from the fair value hierarchy (see Note 14).


110


The components of net periodic benefit cost and other amounts recognized in equity related to the Plans for the years ended December 31, 2014, 2013 and 2012 were as follows:
 
 
Cash Balance Plan
 
Retiree Medical Plan
 
 
Year Ended December 31,
 
Year Ended December 31,
(in millions)
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Components of net periodic benefit cost:
 
 
 
 
 
 
 
 
 
 
 
 
Service cost
$
2.1

 
$
1.9

 
$
1.7

 
$
0.2

 
$
0.3

 
$
0.1

 
Amortization of prior service cost

 

 

 
0.1

 
0.2

 
0.1

 
Interest cost
0.3

 
0.2

 
0.1

 
0.1

 
0.1

 
0.1

 
Expected return on plan assets
(0.2
)
 
(0.1
)
 

 

 

 

 
Net periodic benefit cost
$
2.2

 
$
2.0

 
$
1.8

 
$
0.4

 
$
0.6

 
$
0.3

Changes recognized in other comprehensive (income) loss:
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost addition (amortization)
$

 
$

 
$
(0.1
)
 
$
(0.2
)
 
$
(0.2
)
 
$
1.3

 
Actuarial (gain) loss
0.7

 
0.3

 

 
0.7

 
(0.6
)
 
0.8

 
Experience loss

 

 
0.1

 

 

 

 
Total changes recognized in other comprehensive (income) loss
$
0.7

 
$
0.3

 
$

 
$
0.5

 
$
(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,
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Discount rate
4.00%
 
5.00%
 
4.00%
 
4.00%
 
5.00%
 
4.00%
Rate of compensation increase
3.00%
 
4.00%
 
4.00%
 
N/A
 
N/A
 
N/A
Health care cost trend rate:
 
 
 
 
 
 
 
 
 
 
 
Initial rate
N/A
 
N/A
 
N/A
 
7.50%
 
7.00%
 
7.50%
Ultimate rate
N/A
 
N/A
 
N/A
 
5.00%
 
5.00%
 
5.00%
Years to ultimate
N/A
 
N/A
 
N/A
 
5
 
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,
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Discount rate
5.00%
 
4.00%
 
4.75%
 
5.00%
 
4.00%
 
4.75%
Expected long-term rate of return on plan assets
4.75%
 
4.25%
 
4.50%
 
N/A
 
N/A
 
N/A
Rate of compensation increase
4.00%
 
4.00%
 
4.00%
 
N/A
 
N/A
 
N/A
Heather care cost trend rate:
 
 
 
 
 
 
 
 
 
 
 
Initial rate
N/A
 
N/A
 
N/A
 
7.00%
 
7.50%
 
7.50%
Ultimate rate
N/A
 
N/A
 
N/A
 
5.00%
 
5.00%
 
5.00%
Years to ultimate
N/A
 
N/A
 
N/A
 
4
 
5
 
5
The assumptions used to determine 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

111


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 $0.2 million, $2.5 million and $2.1 million were made during the years ended December 31, 2014, 2013 and 2012, 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 $5.1 million during the year ending December 31, 2015.
At December 31, 2014, anticipated benefit payments to participants from the Plans in future years are as follows:
(in millions)
Cash Balance Plan
 
Retiree Medical Plan
2015
$
0.3

 
$
0.1

2016
0.4

 
0.1

2017
0.5

 
0.1

2018
0.6

 
0.1

2019
0.8

 
0.1

2020-2024
6.5

 
1.0

18. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information is as follows: 
 
Year Ended December 31,
(in millions)
2014
 
2013
 
2012
Net cash from operating activities included:
 
 
 
 
 
Interest paid
$
22.5

 
$
26.7

 
$
32.9

Income taxes paid
5.0

 
3.7

 

 
 
 
 
 
 
Noncash investing and financing activities include:
 
 
 
 
 
Capital expenditures included in accounts payable
$
2.9

 
$
10.2

 
$
1.2

PP&E derecognized in sale leaseback

 

 
(4.7
)
PP&E additions resulting from a capital lease
1.7

 
1.2

 
1.0

19. LEASING ARRANGEMENTS
Concurrent with the Marathon Acquisition (see Note 5), 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, 2014, 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 “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 lease 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, the Company’s continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the lease 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. Many of our operating leases have renewal options at various future dates and some of our leases have escalation clauses which are indexed to CPI or other inflation related measures.

112


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)
 
Capital Leases
 
Operating Leases
 
Total Leases
2015
 
$
1.2

 
$
22.7

 
$
23.9

2016
 
1.2

 
23.4

 
$
24.6

2017
 
1.0

 
22.7

 
$
23.7

2018
 
0.9

 
22.2

 
$
23.1

2019
 
0.9

 
21.8

 
$
22.7

Thereafter
 
9.2

 
133.0

 
142.2

Total
 
$
14.4

 
$
245.8

 
$
260.2

Less: amount representing interest
 
$
(9.6
)
 
$

 
$
(9.6
)
Present value of net minimum lease payments
 
$
4.8

 
$
245.8

 
$
250.6

Rental expense was $25.4 million, $24.0 million, $23.5 million for the years ended December 31, 2014, 2013 and 2012, 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.
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, 2014 and 2013, accruals for remediation and closure obligations totaled $8.7 million and $1.5 million, respectively. Of the $8.7 million and $1.5 million accrued, $2.9 million and $1.5 million are recorded on a discounted basis as of December 31, 2014 and 2013, respectively. These discounted liabilities are expected to be settled over at least the next 23 years. At December 31, 2014, the estimated future cash flows to settle these discounted liabilities totaled $3.5 million and are discounted at a rate of 2.55%. 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 $0.2 million and $0.1 million at December 31, 2014 and 2013, respectively. Costs associated with environmental remediation are recorded in direct operating expenses in the statement of operations.
On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park Refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014 and, following our review of the test results and additional discussions with the MPCA, we now regard the likelihood of future remediation costs related to the lagoon as probable. At December 31, 2014, we estimate the remediation costs to be approximately $5.8 million subject to further engineering and methodology studies. Some or all of this cost cost may be recoverable from Marathon Petroleum under an agreement entered into in connection with our December 2010 acquisition of the St. Paul Park Refinery, among other assets, from Marathon. However, at December 31, 2014 it is unclear how much, if any, of our future costs may be reimbursed by Marathon, and as such, we have not at this time recognized any receivable for this matter.

113


Future estimated cash outflows to remediate environmental matters are as follows:
(in millions)
 
Groundwater Contamination
 
Wastewater Lagoon
 
Total
2015
 
$
0.5

 
$
5.8

 
$
6.3

2016
 
0.3

 

 
$
0.3

2017
 
0.2

 

 
$
0.2

2018
 
0.2

 

 
$
0.2

2019
 
0.2

 

 
$
0.2

Thereafter
 
2.1

 

 
$
2.1

Total
 
$
3.5

 
$
5.8

 
$
9.3

Less: amount representing interest
 
$
(0.6
)
 
$

 
$
(0.6
)
Present value of estimated future cash flows
 
$
2.9

 
$
5.8

 
$
8.7


It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred by the Company or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates for which a liability has been recorded either in accrued liabilities or other liabilities in the balance sheet because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology.
Franchise Agreements
In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.
Guarantees
Certain agreements related to assets sold in the normal course of business contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require the Company to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications were part of the normal course of selling assets. The Company has assumed these guarantees and indemnifications upon the Marathon Acquisition. However, in certain cases, MPC LP has also provided an indemnification in favor of the Company.
The Company is not typically able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the Company has little or no past experience associated with the underlying triggering event upon which a reasonable prediction of the outcome can be based. The Company is not currently making any payments relating to such guarantees or indemnifications.
21. SEGMENT INFORMATION
The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management’s current organizational structure.
Refining – operates the St. Paul Park, Minnesota refinery, terminal, NTOT and related assets, and includes the Company’s interest in MPL and MPL Investments, and
Retail – operates 165 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:

114


(in millions)
 
 
 
 
 
 
 
 
Year ended December 31, 2014
 
Refining
 
Retail
 
Other
 
Total
Revenues
 
 
 
 
 
 
 
 
Customer
 
$
4,165.6

 
$
1,390.4

 
$

 
$
5,556.0

Intersegment
 
932.1

 

 

 
932.1

Segment revenues
 
5,097.7

 
1,390.4

 

 
6,488.1

Elimination of intersegment revenues
 

 

 
(932.1
)
 
(932.1
)
Total revenues
 
$
5,097.7

 
$
1,390.4

 
$
(932.1
)
 
$
5,556.0

 
 
 
 
 
 
 
 
 
Income (loss) from operations
 
$
303.5

 
$
22.9

 
$
(51.1
)
 
$
275.3

Income from equity method investment
 
$
2.2

 
$

 
$

 
$
2.2

Depreciation and amortization
 
$
33.7

 
$
7.3

 
$
0.9

 
$
41.9

Capital expenditures
 
$
35.4

 
$
8.8

 
$
0.6

 
$
44.8

(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
 
$
263.1

 
$
15.2

 
$
(32.2
)
 
$
246.1

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
 
$
705.6

 
$
8.7

 
$
(145.0
)
 
$
569.3

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

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.

115


Total assets by segment were as follows: 
(in millions)
 
Refining
 
Retail
 
Corporate/Other
 
Total
At December 31, 2014
 
$
932.9

 
$
134.0

 
$
113.5

 
$
1,180.4

 
 
 
 
 
 
 
 
 
At December 31, 2013
 
$
875.6

 
$
138.2

 
$
104.0

 
$
1,117.8

The Company's equity method investment in MPL is included in the refining segment's assets and had a carrying value of $80.7 million and $86.2 million at December 31, 2014 and 2013, respectively. See Note 8 for further information on the Company’s equity method investment.
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. REORGANIZATION AND RELATED COSTS
During the first quarter of 2014, the Company initiated a plan that included the relocation of its corporate offices from Ridgefield, Connecticut to Tempe, Arizona and the reorganization of various positions within the Company, primarily among senior management. In relation to this reorganization plan, it was determined during the year ended December 31, 2014 that certain employees of the Company would be terminated. The Company recognized $12.9 million of expense during the year ended December 31, 2014, which included compensation related to the severance of employment and the acceleration of unvested equity based compensation. These costs are recognized in the reorganization and related costs line within the consolidated statements of operations and comprehensive income. All reorganization and related costs are recognized in the Other segment. Substantially all reorganization costs associated with the corporate office relocation were fully recognized at December 31, 2014. As of December 31, 2014, the Company had $0.8 million in unpaid reorganization expenses included in the accrued liabilities line item of the consolidated balance sheets, which will be paid from 2014 through 2016.
(in millions)
 
For the year ended December 31, 2014
Reorganization and related costs incurred during period
 
$
12.9

Less: non-cash equity based awards with accelerated vesting
 
(4.8
)
Cash payments made to severed employees
 
(7.3
)
Ending liability for cash portion of reorganization costs
 
$
0.8

23. SUPPLEMENTARY QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
(in millions, except per unit data)
First Quarter
 
Second Quarter
 
Third Quarter
 
Fourth Quarter
 
Total
2014
 
 
 
 
 
 
 
 
 
 
Revenue
$
1,346.3

 
$
1,602.5

 
$
1,547.4

 
$
1,059.8

 
$
5,556.0

 
Operating income
77.8

 
65.6

 
104.8

 
27.1

 
275.3

 
Net income
71.5

 
57.9

 
96.2

 
16.0

 
241.6

 
Earnings per common unit - basic
$
0.77

 
$
0.62

 
$
1.04

 
$
0.17

 
$
2.61

 
Earnings per common unit - diluted
$
0.77

 
$
0.62

 
$
1.04

 
$
0.17

 
$
2.61

 
 
 
 
 
 
 
 
 
 
 
2013
 
 
 
 
 
 
 
 
 
 
Revenue
$
1,115.0

 
$
1,131.2

 
$
1,440.9

 
$
1,292.1

 
$
4,979.2

 
Operating income
132.2

 
52.6

 
27.5

 
33.8

 
246.1

 
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

Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.

116


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, 2014 (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 81 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, 2014, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
None.


117


PART III
Item 10. Directors, Executive Officers, and Corporate Governance.
Our Board of Directors
As a limited partnership, we are managed by the board of directors of our general partner (the “Board”), subject to the terms and conditions set forth in our partnership agreement. The Board is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Instead, the Board is appointed by the sole member of our General Partner, NT InterHoldCo LLC, which is a wholly-owned subsidiary of Western Refining. Western Refining also owns 35,622,500, or 38.4%, of our limited partner common units. Western Refining’s ownership of NT InterHoldCo LLC gives Western Refining the authority to appoint our Board.
During 2014, the Board consisted of four independent, non-employee directors (Messrs. Bennett, Duckworth, Hofmann and Smith) and four non-employee directors who are also directors and/or executive officers of Western Refining (Messrs. Barfield, Foster, Jeff Stevens and Weaver), as well as one employee director. This employee director was Mr. Hank Kuchta until March 1, 2014, when Mr. Kuchta retired as President, Chief Executive Officer and director of our General Partner, and Mr. Lamp, who has served as our President and Chief Executive Officer since March 1, 2014, beginning April 30, 2014. The Board is led by its Chairman, Mr. Foster. As required by our Corporate Governance Guidelines, the Board, through its Nominating and Governance Committee (“Governance Committee”) periodically evaluates the composition of the Board, including the skill sets, diversity, leadership structure, background and experience of its directors. The Board is confident that its current structure and composition is best for the Company and its unitholders at this time.
All actions of the Board, other than any matters delegated to a committee, will require approval by majority vote of the directors, with each director having one vote. Our partnership agreement contains various provisions which replace default fiduciary duties under applicable law with contractual corporate governance standards. 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. 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.
The following table sets forth the names, positions and ages (as of February 26, 2015) of our directors:
Name
 
Age
 
Title
Paul L. Foster
 
57
 
Chairman of the Board
Lowry Barfield
 
57
 
Director
Timothy Bennett
 
57
 
Director
Rocky Duckworth
 
64
 
Director
Thomas Hofmann
 
63
 
Director
David L. Lamp
 
57
 
President and Chief Executive Officer and Director
Dan F. Smith
 
68
 
Director
Jeff A. Stevens
 
51
 
Director
Scott D. Weaver
 
56
 
Director
Set forth below is a description of the backgrounds, experience and qualifications of our directors as of December 31, 2014.
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 until January 2010, when he was appointed its executive chairman. In addition, Mr. Foster served as Western Refining’s 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 that owns and operates logistics, storage, transportation and wholesale assets; as chairman of the University of Texas System Board of Regents; as a director of WestStar Bank, an El Paso-based bank; as a

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chairman of the board 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; as a director of the Federal Reserve Bank of Dallas - El Paso Branch; 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. Except as previously mentioned, in the past five years, Mr. Foster has not served as a director of any other publicly traded company or as a director of a registered investment company.
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 holdings in the sole member of our 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 that owns and operates logistics, storage, transportation and wholesale assets. 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. Except as previously mentioned, in the past five years, Mr. Barfield has not served as a director of any other publicly traded company or as a director of a registered investment company.
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. Except as previously mentioned, in the past five years, Mr. Bennett has not served as a director of any other publicly traded company or as a director of a registered investment company.
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, and retired from KPMG in 2010 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. Since 2011, Mr. Duckworth has been a member of the Texas State Board of Public Accountancy. Mr. Duckworth is also a member of the board of directors and chairman of the audit committee of Magnum Hunter Resources Corporation (NYSE: MHR), a Houston-based oil, natural gas and natural gas liquids exploration and production company; and a member of the board of directors, chairman of the audit committee and a member of the compensation and nominating and governance committees of Glori Energy, Inc. (NYSE: GLRI), a company focused on increasing production and recovery from mature oil wells. He has a Bachelor of Science degree with honors in accounting from Oklahoma State University and is a certified public accountant. Except as previously mentioned, in the past five years, Mr. Duckworth has not served as a director of any other publicly traded company or as a director of a registered investment company.
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, as well as his experiences with other energy-related companies, 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. Mr. Hofmann served as senior vice president and chief financial officer of Sunoco, Inc., an oil refining and

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marketing company, from January 2002 until his retirement in December 2008. Mr. Hofmann also serves as a director of West Pharmaceuticals Services, Inc., a pharmaceutical and medical device company, and of CPP GP LLC, the general partner of Columbia Pipeline Partners LP, a master limited partnership which owns and operates natural gas pipelines and integrated underground storage systems, and served as a director of the general partner of PVR Partners, L.P., a natural gas gathering and processing company and coal and natural resources property management company, until 2014. Mr. Hofmann also serves on the boards of various non-profit and charitable organizations. Except as previously mentioned, in the past five years, Mr. Hofmann has not served as a director of any other publicly traded company or as a director of a registered investment company. Mr. Hofmann received a Bachelor of Science 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.
David L. Lamp has served as the President and CEO of our general partner since March 2014. He has served as a director of our general partner since April 2014. Mr. Lamp has 34 years of experience in the petroleum refining industry, including technical, operations, commercial and senior management endeavors. Previously, Mr. Lamp served as the Senior Vice President and Chief Operating Officer for HollyFrontier Corporation, an independent petroleum refiner, since 2011, and in a variety of senior management positions with Holly Corporation, an independent petroleum refiner, including President, since 2004. He currently serves as Chairman of the American Fuel & Petrochemical Manufacturers Association, the industry trade association for the refining and petrochemical industry. Except as previously mentioned, in the past five years, Mr. Lamp has not served as a director of any other publicly traded company or as a director of a registered investment company.
Mr. Lamp’s extensive knowledge and experience in all aspects of the petroleum refining industry, as well as significant background serving in key leadership roles at public and private petroleum refining entities are key attributes, among others, that make him well qualified to serve as a director of the Company.
Dan F. Smith has served as a director of our general partner since June 2012 and of Northern Tier Energy LLC since May 2011. Mr. 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 is the former chairman, president and chief executive officer of Lyondell Chemical Company, a plastics, chemicals and refining company. He began his career with ARCO (Atlantic Richfield Company) in 1968 as an engineer. He was elected president of Lyondell Chemical Company in August 1994, chief executive officer in December 1996 and chairman of the board of directors in May 2007. Mr. Smith retired in December 2007 from Lyondell Chemical Company following the acquisition of Lyondell by Basell Polyolefins. Mr. Smith also served as chief executive officer of Equistar Chemicals, LP, a producer of ethylene, propylene, polyethylene and other products, from December 1997 through December 2007 and as chief executive officer of Millennium Chemicals Inc., a manufacturer and marketer of chemicals, from November 2004 until December 2007. At the time Mr. Smith served in such positions, Equistar and Millennium were 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., a global producer of engineered polymers, since 2008, chairman and a director of Axip Energy Services, LP (successor to Valerus Compression Services, L.P.), a compression production and facility services provider, since 2010; chairman and a director of Nexeo Solutions Holdings, LLC, a global distributor of chemical products, since 2011; and Orion Engineered Carbons S.A., a producer of carbon black, since 2014. He also serves as a member of the College of Engineering Advisory Council at Lamar University. Mr. Smith also served as a director of Cooper Industries PLC, an electrical products manufacturer, for 12 years, until its sale to Eton Corp. PLC, an industrial manufacturer, in 2012. Except as previously mentioned, in the past five years, Mr. Smith has not served as a director of any other publicly traded company or as a director of a registered investment company. Mr. Smith is a graduate of Lamar University with a Bachelor of Science 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 that owns and operates logistics, storage, transportation and wholesale assets. 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. Except as previously mentioned, in the past

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five years, Mr. Stevens has not served as a director of any other publicly traded company or as a director of a registered investment company. Mr. Stevens has spent his entire career working in the refined product production and marketing industry.
His 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.
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 consist of independent directors and the requirements that the Board have compensation and nominating and governance committees that are composed entirely of independent directors. As a result of these exemptions, our Board is not comprised of a majority of independent directors and the Compensation and 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 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 has affirmatively determined that Messrs. Bennett, Duckworth, Hofmann and Smith are independent under applicable NYSE rules.
Board Committees
Our Board has four standing committees: the Audit Committee, the Compensation Committee, the Governance Committee and the Conflicts Committee. Each of these standing committees has a written charter that may be found on our website at www.ntenergy.com. Paper copies of each of our committee charters are each available free of charge to all unitholders by calling (602) 302-5450 or by writing to Melissa Buhrig, Secretary, at our corporate headquarters located at 1250 W. Washington Street, Suite 300, Tempe, Arizona 85281.
Each of our standing committees reviews the adequacy of its charter on an annual basis, in addition to evaluating its performance and reporting to the Board on such evaluation. All of the members of the Audit Committee and Conflicts Committee are independent and non-employee directors as defined by the rules and regulations of the NYSE, the SEC, and our corporate governance guidelines. The Governance Committee reviews regularly the membership on each of the Board's four standing committees.

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The composition of the Board’s four standing committees is as follows:
Director
Audit Committee
Compensation Committee
Governance Committee
Conflicts Committee
Lowry Barfield
 
X
X
 
Timothy Bennett
X
 
 
X
Rocky Duckworth
X
 
 
X (C)
Paul L. Foster
 
 
 
 
Thomas Hofmann
X (C)
 
X
X
David L. Lamp
 
 
 
 
Dan F. Smith
 
X (C)
 
X
Jeff A. Stevens
 
 
 
 
Scott D. Weaver
 
X
X (C)
 
C = Chairman
Previously, the Board had an Executive Committee comprised of Messrs. Foster, Smith, Stevens and Weaver. This Executive Committee handled matters that arose during the intervals between meetings of the Board that did not warrant convening a special meeting of the Board but should not be postponed until the next scheduled meeting of that Board, and also exercised the approval authority delegated by the Board under the general partner’s previous Delegation of Authority Policy. The Board did not reappoint an Executive Committee in 2014, and instead determined to bring all matters previously handled by the Executive Committee to the attention of the full Board.
Audit Committee
As required by the Exchange Act and the listing standards of the NYSE, our Audit Committee consists of three directors, each of whom has been affirmatively determined by the Board to meet the independence standards established by the NYSE and the Exchange Act for membership on an audit committee: Mr. Hofmann, who also serves as chairman, and Messrs. Bennett and Duckworth. The Board has determined that each of Messrs. Hofmann, Bennett and Duckworth are “financially literate” and that Messrs. Hofmann and Duckworth further qualify as “Audit Committee Financial Experts,” as defined by SEC rules. Among other responsibilities, the Audit Committee:
Is directly responsible for the appointment, compensation, retention and oversight of the independent auditors;
Evaluates the qualifications, performance and independence of the independent auditors and pre-approves the services (audit and non-audit) provided by the independent auditors;
Discusses with management, internal auditors and independent auditors the Company's accounting principles and financial statement presentations and the critical accounting policies and practices of the Company;
Reviews with management, internal auditors and independent auditors the Company's annual and quarterly financial statements;
Reviews the Company’s Code of Business Conduct and Ethics and its enforcement;
Evaluates the performance, responsibilities, budget and staffing of the Company's internal audit team;
Reviews and assesses the Company's policies and practices with respect to risk assessment and risk management;
Establishes procedures for and oversees handling complaints including, whistleblower hotline complaints regarding accounting, internal accounting controls and auditing matters;
Reviews and approves or ratifies all related party transactions as required to be disclosed under SEC rules; and
Prepares the Audit Committee report and recommends to the Board whether the annual financial statements should be included in the Company's annual report.
The Audit Committee met five times during fiscal year 2014, either in person or by telephone. In performing its functions and fulfilling its oversight responsibilities, the Audit Committee consults separately and jointly with the independent auditors, the Company’s internal auditors, the Chief Financial Officer and other members of the Company's management. The Audit Committee reviewed and discussed with management the audited financial statements contained in this Annual Report on Form 10-K. The Audit Committee also discussed with Deloitte & Touche LLP (“Deloitte”), the Company’s independent registered accounting firm, the matters required to be discussed by Auditing Standards No. 16, as issued by the Public

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Company Accounting Oversight Board. The Audit Committee (i) received written disclosures and the letter from Deloitte required by applicable requirements of the Public Company Accounting Oversight Board regarding Deloitte’s communications with the audit committee concerning independence (ii) and has discussed with Deloitte its independence from management and the Company. Based on the reviews and discussions referred to above, the Audit Committee recommended to the Board that the audited financial statements be included in the Annual Report on Form 10-K for the year ended December 31, 2014 for filing with the SEC.
Compensation Committee
Although not required by NYSE listing standards, the Board has a Compensation Committee comprised of Mr. Smith, who also serves as its chairman, and Messrs. Barfield and Weaver. While none of the members of our Compensation Committee is required to be “independent,” the Board has affirmatively determined that Mr. Smith meets the independence standards established by the NYSE and the Exchange Act. Among other responsibilities, the Compensation Committee:
Reviews and approves the Company's compensation and benefits policies generally, including any incentive compensation and equity-based plans that are subject to Board approval;
Reviews and makes recommendations to the Board with respect to the compensation of the Company’s named executive officers, including the Chief Executive Officer;
Reviews and makes recommendations to the Board with respect to the compensation of non-employee directors;
Reviews periodically, in consultation with the Company's CEO, the Company's management succession planning including policies for CEO selection and succession;
Reviews and assesses risks arising from the Company's compensation policies and practices; and
Reviews and discusses the Compensation Committee Report and the Compensation Discussion and Analysis and recommends to the Board their inclusion in the Company's Annual Reports on Form 10-K.
Since the Compensation Committee is not comprised entirely of independent directors, all compensation for the Company’s named executive officers are determined by the full Board, upon recommendation of the Compensation Committee. The Compensation Committee has the sole authority to retain any compensation consultant, legal counsel or other adviser that the Compensation Committee determines is independent from management under the independence factors enumerated by the rules of the NYSE, and is directly responsible for the appointment, compensation and oversight of the work of any such consultant or adviser. The Compensation Committee met six times during fiscal year 2014, either in person or by telephone, and acted by written consent once. In performing its functions and fulfilling its oversight responsibilities, the Compensation Committee consults separately and jointly with the Chief Executive Officer and other members of the Company's management, as well as any independent compensation consultant, legal counsel or other adviser retained by the Compensation Committee.
Governance Committee
Although not required by NYSE listing standards, the Board has a Governance Committee comprised of Mr. Weaver, who also serves as its chairman, and Messrs. Barfield and Hofmann. While none of the members of our Governance Committee is required to be “independent,” the Board has affirmatively determined that Mr. Hofmann meets the independence standards established by the NYSE and the Exchange Act. Among other responsibilities, the Governance Committee:
Recommends criteria for the selection of candidates to the Board and identifies individuals qualified to become members of the Board consistent with such criteria;
Reviews and evaluates the size, composition, function and duties of the Board consistent with its needs;
Makes recommendations to the Board regarding the composition of the committees of the Board in light of current challenges and needs of the Board, the Company and each committee and considers the rotation of committee members and committee chairs;
Makes recommendations to the Board as to determinations of director independence including reviewing potential conflicts of interest involving directors;
Develops and recommends to the Board Corporate Governance Guidelines, and various codes of business conduct and ethics and reviews and oversees compliance with such guidelines and codes; and
Leads the Board and its committees in their annual self-evaluation procedures.
While we do not have a specific policy regarding diversity of our directors, the Governance Committee generally seeks directors with varying viewpoints, professional experiences, backgrounds, education, skill sets and gender who have business and/or professional knowledge and experience applicable to our business; are well regarded in their communities with a long-term, good reputation for the highest ethical standards; possess common sense and good judgment; have a positive

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record of accomplishment in present and prior positions; have an excellent reputation for preparation, attendance, participation, interest and initiative on other boards on which they may serve; and have the time, energy, interest and willingness to become involved in our business and future. The Governance Committee periodically assesses whether our Board and its Committees possess the right diversity of skills and backgrounds, including through its annual Board and Committee Self-Assessment Questionnaires.
The Governance Committee met four times during fiscal year 2014, either in person or by telephone. In performing its functions and fulfilling its oversight responsibilities, the Governance Committee consults separately and jointly with the Chief Executive Officer and other members of the Company's management.
Conflicts Committee
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 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.
On April 30, 2014, the Board created a Conflicts Committee and appointed to the Conflicts Committee Mr. Duckworth, who also serves as its chairman, and Messrs. Hofmann and Smith. On June 17, 2014, the Board also appointed Mr. Bennett to the Conflicts Committee. Among other responsibilities, the Conflicts Committee:
As requested by the Board, investigates, reviews, evaluates and acts upon any potential conflicts of interest between the Company and Western Refining or any of the Company or Western Refining’s affiliates, on one hand, and any other person who acquires an interest in the partnership, on the other; and
Carries out any other duties delegated by the Board that relate to potential conflicts of interest.
In performing its functions and fulfilling its responsibilities, the Conflicts Committee has the sole authority to retain, compensate, direct, oversee and terminate any counsel and other advisers hired to assist the Conflicts Committee, including engaging consultants, attorneys, independent accountants and other service providers to assist in the evaluation of conflicts matters and approving such consultants’ fees and other retention terms. The Conflicts Committee met two times during fiscal year 2014.
Meeting Attendance and Other Information
During fiscal year 2014, our Board met eight times, either in person or by telephone, and acted pursuant to written consent once. All of our directors had access to members of management and a substantial amount of information transfer and informal communication took place between management and the Board between meetings. None of our directors attended fewer than 75% of the aggregate number of meetings of the Board and the committees on which such 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.
Risk Oversight
The Board considers oversight of risk management efforts to be a responsibility of the entire Board as well as its committees. The Board's role in risk oversight includes receiving regular reports from its committees and members of senior management on areas of material risk to the Company, including operational, financial, liquidity, credit, legal and regulatory, strategic, commercial, enterprise and reputational risks. The Board (or the appropriate committee, in the case of risks that are under the purview of a particular committee) receives these reports from the appropriate members of management to enable the Board and, as appropriate, its committees to understand and oversee risk identification, risk management and risk mitigation strategies. When a report is reviewed at the committee level, the chairman of that committee subsequently reports on the matter to the Board. This enables both the Board and its committees to coordinate the Board's risk oversight role.
The Audit Committee assists the Board in monitoring and assessing the Company's financial, commercial, liquidity, credit, regulatory, enterprise and other risks and in developing guidelines and policies to govern processes for managing these risks. The Audit Committee discusses the Company's policies with respect to risk assessment and risk management in general, as well as with respect to the specific risks the Audit Committee oversees. The Audit Committee also regularly discusses risk

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management in the context of compliance and internal controls. In addition, in October 2014, we formed the Enterprise Risk and Compliance Committee (the "ERCC") for the purpose of assisting the Company in evaluating and maintaining compliance with significant applicable legal, ethical and regulatory requirements. The ERCC consists of key management employees from across the Company and is responsible for helping the company (1) identify principal compliance risks based on the Company's businesses, customers, geographic operations, distribution channels and other factors identified by the ERCC; (2) provide input and oversight on Company policies and procedures relating to compliance with relevant laws, regulations and ethical standards and discuss and recommend new or revisions to policies and procedures relating to compliance; (3) assist with the implementation and monitoring of an annual compliance operating plan; and (4) providing additional guidance to the Company on compliance related matters. The ERCC meets regularly and also regularly reports to the CEO and the Audit Committee and its chair, Mr. Hofmann, on its meetings and activities. The Audit Committee regularly reports to the Board on its discussions and oversight relating to risk as well as its discussions and oversight relating to the ERCC.
The Governance Committee assists the Board in monitoring the Company's risks incident to its board and committee structures and governance structures and processes. The Governance Committee discusses risk management in the context of general governance matters, Board succession planning and committee service by directors, among other topics. The Governance Committee regularly reports to the Board on its discussions and oversight.
The Compensation Committee assists the Board in monitoring the risks associated with the Company's compensation policies and practices as well as executive officer succession planning. The Compensation Committee reviews the design and goals of the Company's compensation programs and practices in the context of possible risks to the Company's financial and reputational well-being as well as possible risks to the continuity of the Company's management. The Compensation Committee regularly reports to the Board on its discussions and oversight.
The Conflicts Committee assists the Board in monitoring the risks associated with actual or perceived conflicts of interest relating to the Company’s interactions with its affiliates, including Western Refining.
Corporate Governance Guidelines
Our Board has adopted a set of Corporate Governance Guidelines. A copy of the Corporate Governance Guidelines may be found on our website at www.ntenergy.com. In addition, paper copies of the Corporate Governance Guidelines are available to all unitholders free of charge by calling (602) 302-5450 or by writing to Melissa Buhrig, Secretary, at our corporate headquarters located at 1250 W. Washington Street, Suite 300, Tempe, Arizona 85281. The guidelines set out our and the Board's thoughts on, among other things, the following:
The role of the Board and management;
The functions of the Board and its committees and the expectations we have for directors;
The selection of directors, the Chairman of the Board and the Chief Executive Officer and the qualifications for directors to sit on the standing committees of the Board;
Independence requirements, election terms, retirement of directors, unit ownership requirements, management succession and executive sessions for non-management directors; and
Compensation of directors and evaluation of director performance.
Code of Business Conduct and Ethics and Financial Code of Ethics
Our Board has adopted a Code of Business Conduct and Ethics that applies to all directors, officers and employees as well as a Financial Code of Ethics that applies to our Chief Executive Officer, Chief Financial Officer and principal accounting officer. These codes are posted on our website at www.ntenergy.com. In addition, paper copies of these codes are available to all unitholders free of charge by calling (602) 302-5450 or by writing to Melissa Buhrig, Secretary, at our corporate headquarters located at 1250 W. Washington Street, Suite 300, Tempe, Arizona 85281. The Company will, within the time periods proscribed by the SEC and the NYSE, timely post on our website at www.ntenergy.com, or in a Current Report on Form 8-K filed with the SEC, any amendments to these codes and any waiver of these codes on behalf of any executive officer or director.
Meeting of Independent Directors and Communications with Directors
At least quarterly, during a meeting of the Board, all of our directors meet in an executive session without management or non-independent directors present. In 2014, Mr. Smith presided over these executive sessions. The Board welcomes questions or comments about us and our operations. Unitholders or interested parties may contact the Board, including any individual director, by contacting our Secretary at the following address and fax number: Secretary, Northern Tier Energy LP, 1250 W. Washington Street, Suite 300, Tempe, Arizona 85281, (602) 302-5450. Letters to a director should be sent to the attention of the Secretary at the same address.

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Section 16(a) Beneficial Ownership Reporting Compliance
Section 16(a) of the Exchange Act requires the Board 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, 2014.
Executive Officers
While the Board provides high-level strategy and guidance for the Company, our day-to-day activities are carried out by our executive officers. Our executive officers are appointed by the Board, and act within the authorities granted by the Board and our organizational documents. Limited partners are not entitled to appoint our executive officers or directly or indirectly participate in our management or operations. 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 26, 2015) of our executive officers:
Name
 
Age
 
Title
David L. Lamp
 
57
 
President and Chief Executive Officer and Director
David Bonczek
 
45
 
Executive Vice President and Chief Financial Officer
Melissa M. Buhrig
 
39
 
Executive Vice President, General Counsel & Secretary
Karen B. Davis
 
58
 
Executive Vice President
Scott L. Stevens
 
53
 
Senior Vice President and Chief Commercial Officer
Set forth below is a description of the backgrounds, experience and qualifications of our executive officers as of February 26, 2015, with the exception of Mr. Lamp, whose information is included under the “Director” section above.
David Bonczek has served as Executive Vice President and Chief Financial Officer of our general partner since May 2014, and 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 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 chemical manufacturing company, from April 2008 through March 2011. From September 1998 through March 2008, Mr. Bonczek held finance management positions within Eastman Kodak, a technology company 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 Bachelor of Science degree in accounting from Binghamton University, and he is a certified public accountant.
Melissa M. Buhrig has served as Executive Vice President, General Counsel and Secretary of our general partner since May 2014. Previously, Ms. Buhrig served as the vice president, assistant general counsel and assistant secretary of Western Refining, a publicly traded refining and marketing company, since 2010 and of the general partner of its publicly traded master limited partnership that owns and operates logistics, storage, transportation and wholesale assets, Western Refining Logistics, LP, since 2013; and as Senior Counsel of Western Refining since 2005. Ms. Buhrig has represented Western Refining and its affiliates, as well as other large manufacturing and business clients, as a partner and associate in various national law firms since 2000. Ms. Buhrig received her Bachelor of Arts degree in Political Science from the University of Michigan and her Juris Doctorate with honors from the University of Miami School of Law, where she served as a member of the University of Miami Law Review.
Karen B. Davis has served as the Executive Vice President our general partner since February 2015. Previously, Ms. Davis served as the Chief Financial Officer of the general partner of Western Refining Logistics, LP, a publicly traded master limited partnership that owns and operates logistics, storage, transportation and wholesale assets, from December 2014 through February 2015. Ms. Davis also served as the Vice President - Director of Investor Relations of Western Refining, Inc., a publicly traded refining and marketing company, from December 2014 through February 2015. Previously, Ms. Davis served as the Chief Accounting Officer of PBF Energy Inc., an independent crude oil refiner, from February 2011 to November 2014, and of PBF Logistics GP LLC the general partner of PBF Logistics LP, a master limited partnership, from its inception in February 2013 until November 2014. She previously served as the Global Controller of Petroplus Holdings AG, a public independent refiner and wholesaler of petroleum products, from October 2009 to December 2010. Prior to this, Ms. Davis has served in various chief financial officer and financial reporting officer positions with public and private companies in the United States.

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Scott L. Stevens has served as Senior Vice President and Chief Commercial Officer of our general partner since May 2014. Previously, Mr. Stevens has worked in various commercial and operational roles in the petroleum refining and marketing industry over the last twelve years. He was most recently the Senior Vice President of Southwest Marketing for Western Refining, a publicly traded refining and marketing company, where he oversaw the Wholesale organization, Rail operations and Refined Products Marketing. Mr. Stevens received a Bachelor of Science in Business Administration degree in Accounting from the University of Arizona.
Item 11. Executive Compensation.
The following discussion and analysis of compensation arrangements (the "Compensation Discussion and Analysis") of our named executive officers (defined below) for 2014 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 activities. Our actual compensation activities may differ materially from the currently planned programs and payouts summarized in this discussion.
Named Executive Officers
During 2014, in connection with the November 2013 indirect acquisition by Western Refining of our general partner, the Company experienced a change in executive officers. This included the appointment of Mr. Lamp as President and Chief Executive Officer effective March 1, 2014 and the appointments of Ms. Buhrig as Executive Vice President, General Counsel and Secretary and Mr. Stevens as Senior Vice President and Chief Commercial Officer, both effective May 5, 2014. As a result, “named executive officers” in this Form 10-K are as follows:
1.
the individuals serving as principal executive officer during the last completed fiscal year (David L. Lamp, who has served as President and Chief Executive Officer since March 1, 2014, and Hank Kuchta, who served as President and Chief Executive Officer from January 1, 2014 until March 1, 2014); 
2.
the individual serving as principal financial officer during the last completed fiscal year (David Bonczek, Executive Vice President and Chief Financial Officer); and
3.
the next most highly compensated individuals who were serving as executive officers at the end of the last completed fiscal year (Melissa Buhrig, Executive Vice President, General Counsel and Secretary; and Scott Stevens, Senior Vice President and Chief Commercial Officer).
We have determined that, as of December 31, 2014, no other individual met the standards necessary to classify him or her as a “named executive officer.”
Compensation Philosophy and Objectives
In establishing named executive officer compensation, the Board and its Compensation Committee seek to compensate named executive officers in a way that meaningfully aligns their interests with the interests of our unitholders, and includes:
Recruiting and retaining highly qualified individuals to manage and lead the Company;
Aligning named executive officers’ compensation opportunities with our short-term and long-term operational and financial objectives using metrics to evaluate and reward performance;
Incentivizing important business priorities such as safety, reliability, environmental performance and earnings growth; and
Rewarding positive growth and the achievement and implementation of specific goals that advance the interests of the Company and its unitholders.
Named executive officer compensation will generally include a mix of fixed elements, intended to provide stability and reliability to our named executive officers, as well as variable elements, which allow us to “pay for performance”, incentivizing and rewarding our named executive officers in years where they have provided us with superior services.
The Decision-Making Process, Generally
Since our Compensation Committee is not required to be, and is not, made up exclusively of independent directors, our named executive officer compensation is determined by the Board, based in part upon the analysis and recommendations of the Compensation Committee.
In accomplishing its objectives, the Board and its Compensation Committee consider, among other factors, the success and performance of the Company, the contributions of named executive officers to such success and performance, and the current economic conditions and industry environment in which the Company operates. Each year, the Compensation

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Committee and the Board utilize various tools in evaluating and establishing named executive officer compensation, including their own common sense, knowledge and experience, as well as some or all of the following:
Input from Board members and management including the Chief Executive Officer. The Board and/or its Compensation Committee may from time to time ask that certain members of the Board and/or management provide information and recommendations relating to named executive officer compensation. Such information typically would include the named executive officers' roles and responsibilities, job performance, the Company's performance generally and among its peer groups, and such other information as may be requested by the Board or its Compensation Committee. The Chief Executive Officer generally provides input and recommendations regarding the compensation of named executive officers other than himself.
Market data and peer comparisons. The Board and its Compensation Committee generally utilize market data derived from the executive pay practices and levels of the applicable peer group supplemented with broad-based compensation survey data, with the assistance of an independent compensation consultant. Compensation survey data generally includes companies from the broader energy, refining and processing industries that influence the competitive market for executive compensation levels and/or from companies comparable to the Company in terms of size and scale. The Compensation Committee and the Board use this market data as comparative information and not as a formulaic approach to compensation levels.
The analysis, judgment and expertise of an independent compensation consultant. The Compensation Committee has historically engaged an independent outside compensation consultant periodically to provide a comprehensive analysis and recommendations regarding named executive officer compensation; the information received from such consultants is generally shared with the Board in connection with establishing named executive officer compensation. The Compensation Committee currently intends to engage an independent outside compensation consultant annually, with such consultants providing a comprehensive analysis and recommendations as to named executive officer compensation every three years, and interim updates in the years without a comprehensive analysis. To the extent the Compensation Committee perceives there are major shifts in compensation trends or desires to modify the Company's compensation programs, the Compensation Committee may decide, in its discretion, to retain independent outside compensation consultants to provide more comprehensive analyses more frequently.
Compensation Consultant Independence
In 2013 and 2014, the Compensation Committee retained Pearl Meyer & Partners (“Pearl Meyer”) to provide it with various analysis regarding, among other things, the selection of peer companies, compensation paid to our directors and our current and former named executive officers and comparative data of compensation paid to directors and named executive officers of peer entities (the services and information that Pearl Meyer provided to be referred to as the "Services"). The analyses received from Pearl Meyer were utilized in establishing named executive officer compensation for 2013, 2014 and 2015. In connection with the Services, the Compensation Committee considers Pearl Meyer independent under the standards set forth in the Dodd-Frank Wall Street Reform and Consumer Protection Act and the rules of the SEC, for the following reasons:
Pearl Meyer performed no services for the Company other than the Services;
The ratio of the fees Pearl Meyer receives from the Company compared to Pearl Meyer’s total revenue is less than 1%;
Pearl Meyer retains a "conflicts policy" to prevent any conflict of interests between Pearl Meyer and the Company that could impact Pearl Meyer's independence;
None of the Pearl Meyer staff performing the Services has any business or personal relationship with any Company executive or Compensation Committee member other than relating to the Services;
None of the Pearl Meyer personnel performing the Services individually owns any Company securities;
Pearl Meyer has neither provided to nor received from the Company any gifts, benefits or donations other than its compensation for the Services; and
Pearl Meyer interacts directly with the Compensation Committee, and only interacts with Company management at the request of or with the knowledge of the Compensation Committee and/or its chairman, Mr. Smith.
Compensation Risk Assessment
Our Compensation Committee has reviewed our compensation policies and practices as generally applicable to our employees, including our named executive officers, and believes that our policies and practices do not encourage excessive or unnecessary risk-taking, and are not reasonably likely to have a material adverse effect on us. In reaching this conclusion, our Compensation Committee reviewed and discussed the design features, characteristics, and performance metrics of our compensation programs, approval mechanisms for compensation awarded to all employees for 2014 and generally, and

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observed the following factors, among others, which the Compensation Committee believes reduces risks associated with our compensation policies and practices:
Our compensation policies and practices are centrally designed and administered;
Our overall compensation levels are competitive with the market;
Our compensation is balanced among (i) fixed components like salary and benefits, and (ii) annual and long-term incentives tied to a mix of financial, operational and individual performance; and
The Board and its Compensation Committee have discretion to adjust annual or performance-based awards when appropriate based on our interests and the interests of our unitholders.
2014 Named Executive Officer Compensation
In establishing the compensation of Messrs. Lamp, Bonczek and Stevens and Ms. Buhrig for 2014, the Board and its Compensation Committee utilized the objectives, process and sources of information described above, and also referred to analyses from Pearl Meyer in May 2013 and November 2013 relating to compensation paid to the Company's previous named executive officers, as well as comparative data of compensation paid to named executive officers of certain peer entities. These peer entities had been selected during 2013 by the Company's previous management, upon consultation with Pearl Meyer, and included both refining entities and retail entities. The Board and its Compensation Committee did not specifically benchmark the information of such peer entities in setting 2014 compensation; instead, the Board and its Compensation Committee generally referenced the compensation paid to named executive officers of the refining peers, including CVR Energy Inc., HollyFrontier Corp., NuStar Energy LP, PBF Energy Inc., Tesoro Corp. and Western Refining. The Board and its Compensation Committee considered the information it received from Pearl Meyer in 2013 to be current and relevant to compensation decisions made during 2014, though did not utilize Pearl Meyer directly in setting 2014 named executive officer compensation.
For each of Messrs. Lamp, Bonczek and Stevens and Ms. Buhrig, the Board approved annual base salaries, targets and ranges under an incentive-based annual bonus program and long-term incentive awards under the Partnership’s Long-Term Incentive Plan (“LTIP”). Mr. Kuchta’s 2014 compensation is further discussed below.
2014 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 officer based on his or her position and responsibility. The Board reviews the base salaries for each named executive officer annually as well as at the time of any promotion or significant change in job responsibilities. In establishing base salaries for 2014, the Board and its Compensation Committee considered, in addition to the factors discussed above, with respect to Mr. Bonczek, his base salary received in 2013, and with respect to Messrs. Lamp and Stevens and Ms. Buhrig, each of their background and experience. The Board, based in part upon recommendation of the Compensation Committee, approved annual base salaries for each of Mr. Lamp ($850,000), Mr. Bonczek ($400,000, increased from $375,000), Ms. Buhrig ($275,000) and Mr. Stevens ($275,000), to be effective on March 1, 2014, for Mr. Lamp and May 5, 2014, for Messrs. Bonczek and Stevens and Ms. Buhrig. The Board also approved an additional payment of $7,913 to Ms. Buhrig, representing the difference between the compensation she received from Western Refining during the period March 1, 2014, through May 5, 2014, and the compensation she would have received from the Company at an annual base salary of $275,000, in connection with the services she performed for the Company during this time, while still an employee of Western Refining. The amount of annual base salary received by each named executive officer during the 2014 fiscal year is set forth in the 2014 Summary Compensation Table.

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2014 Bonuses
Each of the named executive officers (other than Mr. Kuchta) was eligible to receive annual bonus payments pursuant to an incentive compensation plan (the “2014 Bonus Plan”), which was designed to encourage our employees to achieve our business objectives and to attract and retain key employees through the opportunity for performance-related incentive compensation. The 2014 Bonus Plan was generally based on the bonus plan utilized by the Board for 2013; the metrics and targets included in the 2014 Bonus Plan were determined by the Board and its Compensation Committee based on their judgment and expertise, as well as the Company's goals, objectives and expected performance for 2014. The metrics and targets in the 2014 Bonus Plan were as follows:
2014 Bonus Plan Performance Metrics
Metric
Weighting (%)
Threshold ($)(3)
Target ($)(3)
Maximum ($)(3)
Consolidated EBITDA(1)
50%
287.7 million
350.7 million
413.7 million
Cost/Budget Achievement(2)
30%
N/A
55.5 million
N/A
Individual Performance
20%
N/A
N/A
N/A
(1)
"Consolidated EBITDA” under the 2014 Bonus Plan represents earnings before interest, taxes, depreciation, and amortization measured on an internal reporting basis which is consistent with our actual cash flows from operations excluding working capital changes.
(2)
"Cost/Budget Achievement” is defined as internally reported corporate Selling, General and Administrative Expenses ("SG&A") excluding growth initiatives and/or special one-time charges.
(3)
Payout under Threshold, Target and Maximum equals 25% of target, 100% of target and 200% of target, respectively, calculated based on the slope of the curve between Threshold and Maximum.
While EBITDA represented the primary performance measure in the 2014 Bonus Plan, our Board and its Compensation Committee retained the discretion to adjust payouts to named executive officers as they deemed appropriate. The Board established a target for each named executive officer (excluding Mr. Kuchta) under the 2014 Bonus Plan equal to 100% of such named executive officer's base salary, with possible payout between 0% and 200% of target, subject to discretionary adjustments by the Board.
In February 2015, the Board and its Compensation Committee evaluated the performance metrics in the 2014 Bonus Plan, and determined achievement of Consolidated EBITDA at $357.6 million and Cost/Budget Achievement at $54.6 million, equal to a combined calculated payout of 104%. The Board and its Compensation Committee then considered individual named executive officer performance as well as significant accomplishments of the Company led by this new management team during 2014, including, among other accomplishments;
the highly efficient management transition;
improvement in year-over-year Adjusted EBITDA by more than $67 million;
termination of the crude oil intermediation agreement with JPM CCC;
an amendment and restatement of the Company's ABL Facility from $300 million to $500 million; and
the successful offering of $75 million in additional senior secured notes due 2020.
Based on its analysis and these accomplishments, the Board, based in part upon recommendation of its Compensation Committee, and utilizing its discretion and judgment, increased payouts to Mr. Lamp, Ms. Buhrig and Ms. Stevens above the 104% target, and determined to pay cash bonuses under the 2014 Bonus Plan of $1,034,000 to Mr. Lamp; $406,000 to Mr. Bonczek; $311,000 to Ms. Buhrig and $336,000 to Mr. Stevens.
2014 Long-Term Equity-Based Incentives
In order to incentivize our management to continue to grow our business, our general partner adopted 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 LTIP provides us with the flexibility to grant various equity awards, including restricted units, phantom units and other unit-based awards, designed to align the interests of participants (including named executive officers) with those of our unitholders and to give LTIP participants the opportunity to share in our long-term performance.

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On March 1, 2014, in connection with his retention as President and Chief Executive Officer, Mr. Lamp was awarded 400,000 common units pursuant to a Restricted Unit Agreement (Time Based) ("Restricted Units"), which units generally vest ratably on March 1, 2014; December 31, 2015; and December 31, 2016. This award was based on his background and experience, expected responsibilities and certain long-term incentive compensation from his previous employer which were forfeited as a result of his employment by the Company, among other factors. On May 15, 2014, Mr. Bonczek was awarded 100,000 phantom units pursuant to a Time-Based Phantom Unit Award Agreement (“Time-Based Phantom Units”), based on his agreement to remain employed by the Company at least through March 31, 2015 (or such earlier date as may be determined by the Company), and in consideration of his previous contributions to the Company, among other factors. Also on May 15, 2014, Ms. Buhrig and Mr. Stevens were each awarded 30,272 Time-Based Phantom Units in connection with their retention as officers of our general partner, based on their background and experience, expected responsibilities and certain long-term incentive compensation from their previous employers which were forfeited as a result of their employment by the Company. The Time-Based Phantom Units awarded to each of Messrs. Bonczek and Stevens and Ms. Buhrig generally vest ratably on the third Wednesday of January 2015, 2016 and 2017 and may be settled, in the discretion of Board, in cash or common units of the Partnership. Upon vesting, the vested common units underlying the Time-Based Phantom Units, or the cash value thereof, will be delivered to the named executive officer on or promptly following the vesting date applicable thereto, but not later than the 70th calendar day following such vesting. Both the Restricted Units awarded to Mr. Lamp and the Time-Based Phantom Units awarded to Messrs. Bonczek and Stevens and Ms. Buhrig accrue distribution equivalents on unvested units, which are subject to the same vesting and forfeiture restrictions as the underlying award, and will be paid out at the same time that the underlying award is settled. For a description of potential accelerated vesting or forfeiture of these Restricted Units and Time-Based Phantom Units, see the section below titled "Potential Payments Upon Termination or a Change in Control."
Severance and Change in Control Benefits
We maintained agreements with certain of our named executive officers during 2014 that provided for severance and/or change in control protections. We believe these agreements are an important retention tool and also maximize unitholder value by encouraging 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 named executive officer will continue to be employed. We also believe these agreements allow us to remain competitive in attracting and retaining skilled professionals in our industry, as executive officers at other companies in our industry and the general market against which we compete for executive talent commonly generally offer agreements providing for post-termination payments.
Effective March 1, 2014, we entered into a Change in Control Agreement with Mr. Lamp with a term of three years, with automatic one-year renewals absent notice by either Mr. Lamp or us of the intention not to renew the agreement. This agreement provides for payment of certain severance and other benefits to Mr. Lamp in the event his employment is terminated for any reason within 24 months following a Change in Control other than (a) by Mr. Lamp without good reason, (b) by the Company for Cause, or (c) due to death or disability, equal to two times the sum of (y) the higher of his then-current annual base salary and the highest base salary in effect at any time during the three months preceding the Change in Control and (z) the average of the annual bonuses paid over the three most recent years, as well as outplacement services not to exceed $15,000 and continued employee benefits for a period of two years.
Effective August 4, 2014, we entered into a letter agreement with Mr. Bonczek which superseded all previous employment and related agreements between Mr. Bonczek and the Company. This agreement provides for certain payments to Mr. Bonczek upon termination of employment, following his execution and return of a valid release agreement, provided he agrees to remain employed by the Company at least through March 31, 2015 (or such earlier date as may be determined by the Company). This agreement provides for a lump sum payment equal to 100% of his annual base salary in effect on his date of termination, acceleration of all awards issued under the LTIP prior to January 1, 2014, payment of certain healthcare benefits for a period of six months following termination and outplacement support not to exceed $3,000. In January 2015, Mr. Bonczek elected to resign as Executive Vice President and Chief Financial Officer effective March 16, 2015. We currently expect he may receive some or all of the severance benefits outlined above.
Effective December 1, 2010, we also entered into an employment agreement with Mr. Kuchta which had a term of one year, with automatic one-year renewals absent notice by either Mr. Kuchta or us of the intention not to renew the agreement, and provided for certain payments to Mr. Kuchta upon his termination. This agreement was triggered upon his retirement effective March 1, 2014, following Western Refining’s indirect acquisition of our general partner. Under this agreement, Mr. Kuchta received certain severance benefits during 2014, and will continue to receive his base salary of $675,000, payable monthly, through February 2016, as well as the right to participate in certain benefit programs, subject to his continued compliance with certain confidentiality, non-solicitation and non-compete provisions.
At this time, neither Ms. Buhrig nor Mr. Stevens have severance agreements or change in control benefits, although the LTIP awards that each of our named executive officers currently hold contain potential accelerated vesting provisions.

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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 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 2014 are reflected in the 2014 Summary Compensation Table.
We established the Northern Tier Energy LLC Supplemental Plan (the “Supplemental Plan”) in 2012 for those active employees who were required to receive a reduced matching contribution into the 401(k) plan due to the non-discrimination requirements in the 401(k) plan. Employees were not allowed to contribute any of their own compensation into the plan, thus the only amounts that were deferred into the plan will be Company contributions and any earnings thereon. No new contributions were made to the plan in 2013 or 2014; this plan was terminated and paid out in 2014. 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 2014 are listed in the Pension Benefits table.
Other Compensation Items
Unit Ownership Guidelines. During 2013, the Board 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 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. Satisfaction of these ownership guidelines is required within five years of adoption or appointment, whichever is later. Each of our directors and named executive officers either satisfies these ownership guidelines or is within the five year period permitted for compliance.
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.
2014 Compensation for Mr. Hank Kuchta. With respect to Mr. Kuchta, in light of his impending retirement, the Board made no changes to his compensation for 2014. Instead, for his service as President and Chief Executive Officer from January 1, 2014, until March 1, 2014, he received the same base salary that had been approved by the Board effective February 2013 of $675,000. He also participated in broad-based retirement, health and welfare benefits generally available to other employees during this time. Under his employment agreement, following his retirement as President and Chief Executive Officer effective March 1, 2014, Mr. Kuchta also received certain severance payments as set forth in the 2014 Summary Compensation Table.
2015 Named Executive Officer Compensation
In connection with establishing named executive officer compensation for 2015, the Compensation Committee again retained Pearl Meyer to provide it with an analysis of the Company's named executive officer compensation, comparative data and associated recommendations regarding peer groups. The Board and its Compensation Committee utilized the November 2014 Pearl Meyer analysis, in conjunction with the other sources of information described above, in establishing 2015 base salaries, a performance based incentive compensation (the "2015 Bonus Plan") and long-term incentives under the LTIP. The Board, based in part upon recommendation of the Compensation Committee, resolved to pay its named executive officers 2015 compensation as follows:
Annual base salaries for Mr. Lamp ($900,000), Mr. Bonczek ($412,000), Ms. Buhrig ($302,000) and Mr. Stevens ($289,000);
Targets under the 2015 Bonus Plan equal to 100% of annual base salary, with possible payout ranging from 0% to 200% of target, depending upon certain performance criteria including both operational and financial metrics;
Time-Based Phantom Units under the LTIP equal to 100% of annual base salary, based on the closing common unit price on January 2, 2015, vesting ratably on the third Wednesday of January 2016, 2017 and 2018;

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Performance-Based Phantom Unit Awards under the LTIP with a target of 100% of annual base salary and possible payout ranging from 0% to 200% of target, depending upon certain long-term performance metrics over a three year performance period ending on September 30, 2017; and
Participation in broad-based retirement, health and welfare benefits generally available to other employees.
In January 2015, Mr. Bonczek elected to resign as the Executive Vice President and Chief Financial Officer of the general partner effective March 16, 2015, and therefore will not receive any of the 2015 compensation described above, with the exception of his annual base salary through his last date of employment. Also in January 2015, the Board retained Ms. Karen B. Davis to serve as Executive Vice President effective February 2, 2015, and as Executive Vice President and Chief Financial Officer effective March 16, 2015. The Board, based in part upon the recommendation of the Compensation Committee, resolved to pay Ms. Davis an annual base salary of $340,000 and other compensation for 2015 consistent with that awarded to the other named executive officers. We currently expect Ms. Davis will be a named executive officer with respect to fiscal year 2015.
Compensation Committee Report
The Compensation Committee 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 has recommended to the Board that this Compensation Discussion and Analysis be included in the Annual Report on Form 10-K for the year ended December 31, 2014 for filing with the SEC.
The Compensation Committee
Mr. Dan F. Smith, Chairman
Mr. Lowry Barfield
Mr. Scott D. Weaver
2014 Summary Compensation Table
The table below sets forth the annual compensation earned during the 2014, 2013 and 2012 fiscal years and for those current named executives that were considered named executive officers for each applicable year.
 
 
 
 
Salary
 
Bonus
 
Option Awards
 
Stock Awards
 
Change in Pension Value
 
All Other Compensation
 
Total
Name and Principal Position
 
Year
 
($)(1)
 
($)(2)
 
($)
 
($)(3)
 
($)
 
 ($)(4)
 
 ($)
David L. Lamp
 
2014
 
670,192

 
1,034,000

 

 
9,672,000

 

 
329,495

 
11,705,687

President and Chief Executive Officer
 
2013
 

 

 

 

 

 

 

 
 
2012
 

 

 

 

 

 

 

David Bonczek
 
2014
 
390,385

 
406,000

 

 
2,703,000

 
32,464

 
112,848

 
3,644,697

Executive Vice President and Chief Financial Officer
 
2013
 
363,500

 
267,144

 

 
577,214

 
19,594

 
45,300

 
1,272,752

 
 
2012
 
294,231

 
420,000

 
361,957

 
71,367

 
12,870

 
12,654

 
1,173,079

Melissa M. Buhrig
 
2014
 
218,203

 
311,000

 

 
818,252

 

 
4,795

 
1,352,250

Executive Vice President, General Counsel & Secretary
 
2013
 

 

 

 

 

 

 

 
 
2012
 

 

 

 

 

 

 

Scott L. Stevens
 
2014
 
169,231

 
336,000

 

 
818,252

 

 
7,968

 
1,331,451

Senior Vice President and Chief Commercial Officer
 
2013
 

 

 

 

 

 

 

 
 
2012
 

 

 

 

 
 
 

 

Hank Kuchta
 
2014
 
142,788

 

 

 

 
13,537

 
626,985

 
783,310

Former President and Chief Executive Officer
 
2013
 
640,000

 
708,750

 

 
1,558,474

 
25,698

 
83,899

 
3,016,821

 
 
2012
 
450,000

 
900,000

 

 

 
12,947

 
22,099

 
1,385,046


133


(1)
For Mr. Lamp, his 2014 Salary reflects amounts received for the period March 1, 2014, through December 31, 2014, based on an annual base salary of $850,000. For Mr. Bonczek, his 2014 Salary reflects amounts received for the period January 1, 2014, through May 4, 2014, based on an annual base salary of $375,000, and for the period May 5, 2014, through December 31, 2014, based on an annual base salary of $400,000. For Ms. Buhrig, her 2014 Salary reflects $41,059 received as compensation from a Western Refining subsidiary for the period March 1, 2014, through May 4, 2014, a payment of $7,913 previously approved by the Board discussed under "Base Salaries" above and for the period May 5, 2014, through December 31, 2014, amounts received based on an annual base salary of $275,000. For Mr. Stevens, his 2014 Salary reflects amounts received for the period May 5, 2014, through December 31, 2014, based on an annual base salary of $275,000. For Mr. Kuchta, his 2014 Salary reflects amounts received for the period January 1, 2014, through March 1, 2014, based on an annual base salary of $675,000.
(2)
The amounts reported in this column for 2014 reflect actual bonuses that were approved by the Board on February 20, 2015 with respect to the 2014 year, under the 2014 Bonus Plan, and will be paid on or before March 15, 2015.
(3)
The amounts in this column represent the grant date fair value of the award of Restricted Units or Time-Based Phantom Units, as applicable, calculated in accordance with FASB ASC Topic 718, as follows: (a) for Mr. Lamp, using the closing price of one common unit of the Partnership on the trading day immediately preceding the March 1, 2014, grant date, or $24.18, multiplied by 400,000 Restricted Units; and (b) for Messrs. Bonczek and Stevens and Ms. Buhrig, using the closing price of one common unit of the Partnership on the May 15, 2014, grant date, or $27.03, multiplied by 100,000 Time-Based Phantom Units for Mr. Bonczek and 30,272 Time-Based Phantom Units for each of Ms. Buhrig and Mr. Stevens. Other assumptions used to value the grant of the equity awards in this column may be found in Note 16 to our Consolidated Financial Statements.
(4)
The Company's named executive officers are eligible to participate in benefit plans generally available to the Company's other employees including, but not limited to, the Company's match of 401(k) plan contributions, Company paid life insurance premiums and reimbursement of certain moving expenses. Named executive officers also received distributions on certain unvested Restricted Units when the Partnership paid cash distributions to its unitholders. In addition, for Mr. Kuchta, he received certain severance benefits under his employment agreement described in the “Potential Payments Upon Termination or a Change in Control” section below. The following table details the amounts included in the "All Other Compensation" column for the 2014 Summary Compensation Table:
 
 
 
 
Company
401(k) Plan
Contribution
 
Life
Insurance
 
Taxable Moving Expense Reimbursement
 
Distributions on Restricted Units
 
Severance Payments
 
Total
Name
 
Year
 
($)
 
($)
 
($)
 
($)(a)
 
($)
 
($)
David L. Lamp
 
2014
 
23,400

 
436

 
100,325

 
205,334

 

 
329,495

David Bonczek
 
2014
 
23,400

 
540

 

 
88,908

 

 
112,848

Melissa M. Buhrig
 
2014
 
4,442

 
353

 

 

 

 
4,795

Scott L. Stevens
 
2014
 
7,615

 
353

 

 

 

 
7,968

Hank Kuchta
 
2014
 
21,750

 
104

 

 
98,881

 
506,250

 
626,985

(a)
The Partnership paid cash distributions to unitholders in 2014. The amounts in the "Distributions on Restricted Units" column includes distributions that were earned and either accrued or paid on Restricted Units that had not yet vested in 2014, pursuant to the terms of the applicable Restricted Unit agreement. Certain of the named executive officers also held unvested Time-Based Phantom Units which provide for distribution equivalent rights; however, such distribution equivalent rights are only settled if and when such units vest and are therefore not reflected in this column.
Grants of Plan-Based Awards for the 2014 Fiscal Year
 
 
 
 
All Other Stock Awards: Number of Units
 
Grant Date Fair Value of Stock and Option Awards
Name
 
Grant Date
 
(#)(1)
 
($)(2)
David L. Lamp
 
3/1/2014
 
400,000

 
9,672,000

David Bonczek
 
5/15/2014
 
100,000

 
2,703,000

Melissa M. Buhrig
 
5/15/2014
 
30,272

 
818,252

Scott L. Stevens
 
5/15/2014
 
30,272

 
818,252


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(a)
For Mr. Lamp, the units reported in this column represent Restricted Units vesting ratably on March 1, 2014, December 31, 2015, and December 31, 2016. For Messrs. Bonczek and Stevens and Ms. Buhrig, the units reported in this column represent Time-Based Phantom Units each vesting ratably over three years.
(b) The amounts in this column represent the grant date fair value of the award of Restricted Units or Time-Based Phantom Units, as applicable, calculated in accordance with FASB ASC Topic 718, as follows: (i) for Mr. Lamp, using the closing price of one common unit of the Partnership on the trading day immediately preceding the March 1, 2014, grant date, or $24.18; and (ii) for Messrs. Bonczek and Stevens and Ms. Buhrig, using the closing price of one common unit of the Partnership on the May 15, 2014, grant date, or $27.03.
Narrative Description to the 2014 Summary Compensation Table and the Grant of Plan-Based Awards Table for the 2014 Fiscal Year
The terms and conditions of each of the Restricted Units and Time-Based Phantom 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 and Time-Based Phantom Units, see the “Potential Payments Upon Termination or Change in Control” section below.
Percentage of Salary and Bonus in Comparison to Total Compensation
Each of our named executive officers received less than 40% of their 2014 compensation in the form of cash salary and bonus.
Name
 
Salary and Bonus
Percentage of Total
Compensation
David L. Lamp
 
15
%
David Bonczek
 
22
%
Melissa M. Buhrig
 
39
%
Scott L. Stevens
 
38
%
Hank Kuchta
 
18
%
Outstanding Equity Awards at 2014 Fiscal Year-End
The following table provides information on the current equity awards held by the named executive officers.
 
 
 
Number of Units that have not Vested
 
Market Value of Units that have not Vested
 
 
Name
 
(#)(1)
 
($)(2)
 
David L. Lamp
 
266,666

 
5,903,985

 
David Bonczek
 
120,290

 
2,663,243

 
Melissa M. Buhrig
 
30,272

 
670,222

 
Scott L. Stevens
 
30,272

 
670,222

(1)
Amounts in this column represent all outstanding LTIP awards as of December 31, 2014 and include both Restricted Units and Time-Based Phantom Units, as applicable. For Mr. Lamp, outstanding awards include unvested Restricted Units from an award dated March 1, 2014. For Mr. Bonczek, outstanding awards include 926 unvested Restricted Units from an award dated December 19, 2012 which units vest on December 19, 2015; 7106 unvested Restricted Units from an award dated May 20, 2013, which units vest ratably on May 20, 2015 and May 20, 2016; 12,259 unvested Restricted Units from a performance award dated May 20, 2013 and settled February 21, 2014, which units vest ratably on January 1 2015, 2016 and 2017; and 100,000 unvested Time-Based Phantom Units from an award dated May 15, 2014, which units vest ratably on the third Wednesday of January 2015, 2016 and 2017. For Ms. Buhrig and Mr. Stevens, outstanding awards include, for each, 30,272 unvested Time-Based Phantom Units granted on May 15, 2014 which vest ratably on the third Wednesday of January 2015, 2016 and 2017.
(2)
Market values on unvested units were calculated using the closing trading price as of December 31, 2014 of $22.14.

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Option Exercises and Stock Vested in the 2014 Fiscal Year
 
 
Stock Awards
 
 
Number of Units Acquired on Vesting
 
Value Realized on Vesting
Name
 
 (#)(1)
 
 ($)(2)
David L. Lamp
 
133,334

 
3,224,016

David Bonczek
 
4,479

 
117,256

Melissa M. Buhrig
 

 

Scott L. Stevens
 

 

Hank Kuchta
 
61,899

 
1,665,083

(1)
On March 1, 2014, Mr. Lamp vested in 1/3 of the 400,000 Restricted Units awarded to him on March 1, 2014. On May 20, 2014, Mr. Bonczek vested in 1/3 of the 10,660 Restricted Units awarded to him on May 20, 2013, or 3,553 units, and on December 19, 2014, vested in 1/3 of the 2,778 Restricted Units awarded to him on December 19, 2012, or 926 units. On March 17, 2014, following his retirement from the Company on March 1, 2014, all of Mr. Kuchta's outstanding Restricted Units were accelerated and vested, including 68,199 Restricted Units awarded to him on May 20, 2013. None of the remaining named executive officers had any LTIP awards vested during 2014.
(2)
For Mr. Lamp, value was calculated by multiplying the number of Restricted Units that vested by the closing price of one common unit of the Partnership on the trading day immediately preceding the March 1, 2014, vesting date, or $24.18 (as March 1, 2014, was a Saturday and not a trading day). For Mr. Bonczek, value was calculated by multiplying the number of Restricted Units that vested, or 3,533 and 926, by the closing price of our common units on the vesting dates of May 20, 2014, or $27.07, and December 19, 2014, or $22.76, respectively. For Mr. Kuchta, value was calculated by multiplying the number of Restricted Units that vested by the closing price of one common unit of the Partnership on March 17, 2014, or $26.90.
Pension Benefits
Each of the named executive officers is eligible to participate in the cash balance pension plan that we adopted during November 2011.
 
 
 
 
Number of Years Credited Service
 
Present Value of Accumulated Benefit
 
Payments During 2014 Fiscal Year
Name
 
Plan Name
 
(#)
 
($)
 
($)
David L. Lamp
 
Northern Tier Energy Retirement Plan
 
0.84

 
13,000

 

David Bonczek
 
Northern Tier Energy Retirement Plan
 
3.80

 
46,684

 

Melissa M. Buhrig
 
Northern Tier Energy Retirement Plan
 
0.66

 
8,857

 

Scott L. Stevens
 
Northern Tier Energy Retirement Plan
 
0.66

 
8,462

 

Hank Kuchta
 
Northern Tier Energy Retirement Plan
 
3.25

 
52,182

 

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

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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. Any distribution received by a participant before age 59 ½ is considered taxable unless rolled over into an individual retirement account (“IRA”) or eligible retirement plan as a tax free rollover. A participant is deemed to be disabled if he or she qualifies for benefits under the long-term disability plan or qualifies for Federal Social Security disability benefits.
The amount of benefit payable with respect to a participant will be his or her vested account balance if payable in lump sum or the actuarially equivalent of such balance if paid in another form; however, where a participant terminated after attaining his or her normal retirement date, the benefit is the greater of the vested account balance or the actuarial increase in such balance as of the end of the preceding plan year (or, of later, his or her normal retirement date). The normal form of distribution is a qualified joint and survivor annuity if the participant is married on his or her annuity starting date or a single life annuity if he or she is unmarried on that date. Optional forms of distribution include as follows: (1) lump sum, (2) single life annuity, (3) qualified joint and survivor annuity, or (4) the optional joint and survivor annuity.
Mr. Kuchta retired from the Company effective March 1, 2014. As of December 31, 2014, he had not elected to take a distribution under the Plan. Should Mr. Kuchta elect to take a distribution, he would receive distribution of his accumulated benefit of $52,182 either in lump sum or by one of the other forms described above, which amount would be taxable unless transferred into an IRA or eligible retirement plan as a tax-free rollover if distribution takes place before he turns age 59 ½.
Nonqualified Deferred Compensation
 
 
Registrant Contributions in the 2014 Fiscal Year($)
 
Aggregate Earnings in 2014 Fiscal Year ($)
 
Aggregate Withdrawals or Distributions ($)
 
Aggregate Balance at December 31, 2014
Name
 
($)
 
($)
 
($)
 
David Bonczek
 

 
303

 
5,826

 

Hank Kuchta
 

 
328

 
7,589

 

We established the Supplemental Plan during the 2012 year. Eligible participants in the Supplemental Plan were 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. Neither Messrs. Lamp and Stevens nor Ms. Buhrig were eligible for the Supplemental Plan. Employees were not allowed to contribute any of their own compensation into the Supplemental Plan, thus the only amounts that would be deferred into the Supplemental Plan would be Company contributions and any earnings thereon, although no Company contributions were made into the plan for the 2014 year. Under the Supplemental Plan, participants were not vested in their accounts until they completed three years of service with us. However, in the event that the participant reached retirement (at age 65), or separated from service due to his death or disability (defined below), the account would immediately vest. If the participant separated from service for any other reason prior to the account being vested, the account balance would be forfeited. If the participant was terminated for cause (defined below), the account balance, whether vested or unvested, would be forfeited. The Supplemental Plan accounts would 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 have made certain elections upon becoming eligible to participate in the Supplemental Plan. Participants were allowed to make investment decisions regarding their accounts, and such decisions could have been subsequently changed or modified by the participant. The investment fund options and the respective interest rates for the 2014 year were generally the same as those that were 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 2014 Fiscal Year” above. The participant must also have established when and how the participant desired to receive distributions from the

137


Supplemental Plan, otherwise the default distribution form will be a lump sum cash payment. If a participant separated from service, the election options would 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 were to have occurred, a participant may have chosen to receive his or her account balance, which would override the elections made for a separation from service. If an account balance still existed at the time of a participant’s death, the participant’s beneficiaries would receive the balance of the Supplemental Plan account in the form of a lump sum cash payment. The plan administrator may have approved an early distribution from the Supplemental Plan if the participant had suffered a financial hardship or an unforeseeable emergency, in an amount limited to the amount necessary to alleviate the hardship. While we entered each participant’s accounts as a bookkeeping entry, we had set up a rabbi trust to assist us in funding the Supplemental Plan. This trust was only used to fund payments to the Supplemental Plan, and it remained subject to our creditors.
The Supplemental Plan was terminated on October 1, 2014. The trustee was instructed to distribute the account balances for the remaining participants in the Plan and lump-sum payments were processed on October 31, 2014.
Potential Payments Upon Termination or a Change in Control
We provide certain of 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
We have previously entered into formal employment or change in control agreements with three of our named executive officers: Messrs. Lamp, Bonczek and Kuchta.
We entered into a Change in Control Agreement with Mr. Lamp effective March 1, 2014, which has a term of three years, with automatic one-year renewals absent notice by either Mr. Lamp or us of the intention not to renew the agreement. This agreement provides for payment of certain severance and other benefits to Mr. Lamp in the event his employment is terminated for any reason within 24 months following a Change in Control other than (a) by Mr. Lamp without Good Reason, (b) by the Company for Cause, or (c) by reason of his death or disability, equal to two times the sum of (y) the higher of his then-current annual base salary and the highest base salary in effect at any time during the three months preceding the Change in Control and (z) the average of the annual bonuses paid over the three most recent years or, if he has not been employed for a full year, his current target bonus. He will also receive outplacement services not to exceed $15,000 and continued employee benefits for a period of two years. Mr. Lamp's rights to continue to receive any benefits described above are subject to his continued compliance with the restrictive covenants in his agreement, including non-disparagement, non-disclosure of confidential information and non-solicitation provisions. Under his agreement, “Change in Control” means and shall be deemed to have occurred upon one or more of the follow events: (i) any “person”, including a “group” (as such terms are used in Sections 13(d) and 14(d)(2) of the Exchange Act), other than the Company or any affiliate or an employee benefit plan of the Company or any affiliate becomes the “beneficial owner” (as defined in Rule 13(d)(3) under the Exchange Act), directly or indirectly, by way of merger, consolidation, recapitalization, reorganization or otherwise of 50% or more of the voting power of the voting securities of our general partner or the Partnership; (ii) our general partner or the limited partners of the Partnership approve, in one transaction or series of transactions, a plan of complete liquidation of the general partner or the Partnership; (iii) the sale or other disposition by either the general partner or the Partnership of all or substantially all of its assets in one or more transactions to any person other than the Company or any affiliate; or (iv) the general partner or any affiliate ceases to be the general partner of the Partnership; provided that a conversion or reorganization of the Partnership (including, but not limited to, a reorganization of the Partnership into a C-Corporation) following which the Company or any affiliate remains in control of the Partnership shall not be considered a Change in Control. “Cause” means his (a) intentional failure or refusal to comply with instructions of the Board that are consistent with his duties and relevant requirements of law and regulation, (b) engagement in gross negligence, gross incompetence or willful misconduct in the performance of his duties or that is materially injurious to the Company or any affiliates, (c) perpetration of a fraud, embezzlement or willful breach of a fiduciary duty to the Company or any affiliates (including the unauthorized disclosure of confidential or proprietary material information), (d) material breach of his agreement or any other agreement with the Company or any affiliate or (e) a charge that is not resolved in his favor within 12 months of it initially being brought, conviction of, or plea of guilty or no contest to, a felony or a crime involving fraud, dishonesty or moral turpitude. “Good Reason” means without his consent, (a) a material and adverse change in the nature or scope of his duties, (b) a reduction in his base salary other than a reduction consistent with reductions made to other members of the senior management team, (c) a change in the location of his principal place of employment by more than 60 miles or (d) the Company’s material breach of his agreement.
On August 4, 2014, we entered into a letter agreement with Mr. Bonczek which replaced and superseded all previous employment and related agreements in place between us and Mr. Bonczek. This agreement provided for an annual base salary to Mr. Bonczek of $400,000 per year and the opportunity to earn an incentive-based annual cash bonus under the 2014 Bonus Plan with a target bonus equal to 100% of his annual base salary and a possible payout range between 0% and 200% of target,

138


depending upon the achievement of certain performance metrics. Under the agreement, Mr. Bonczek is also eligible to participate in other employee benefit plans, practices and programs maintained by the Company, as in effect from time to time on the same basis as other similarly situated executives of the Company, to the extent consistent with applicable law and the terms of such plans and programs. The agreement further provides for relocation benefits consistent with the Company’s relocation policies, as well as certain severance benefits. Under this agreement, if Mr. Bonczek elects not to relocate to our corporate offices in Tempe, Arizona, and provided he agrees to remain employed by the Company at least through March 31, 2015 (or such earlier date as may be determined by the Company), upon his termination he will receive a lump sum payment equal to one times his then-current annual base salary, acceleration of all unvested LTIP awards issued prior to January 1, 2014, outplacement support up to $3,000 and reimbursement for a portion of up to six months’ worth of COBRA premiums. If he elects to relocate, and is terminated after March 31, 2015, he will receive one times his then-current annual base salary only, plus acceleration of all outstanding LTIP awards in the event such termination is within twelve months following a Change in Control that occurs after the agreement's effective date. In January 2015, Mr. Bonczek elected not to relocate to the Company's corporate offices in Tempe, Arizona, and will resign as Executive Vice President and Chief Financial Officer effective March 16, 2015. Assuming he is not earlier terminated for Cause, and following his execution of a valid release in our favor, he would be entitled to receive the severance benefits described above. For the purposes of Mr. Bonczek’s employment agreement, “Cause” means (A) the continuous failure by him to substantially perform your duties with the Company (other than such failure resulting from his incapacity due to physical or mental illness) following his being advised of such failure and having a reasonable opportunity to cure his performance failure, (B) gross misconduct or gross negligence by him as determined by the Board in good faith, or (C) his conviction of, or entering a plea of guilty or nolo contendere to the commission of a felony; “Good Reason” means (A) a material diminution of his position, duties, or responsibilities, a diminution in his title or offices or any removal of him from or any failure to reelect him to any such positions; (B) a reduction in his base salary or target incentive opportunity; (C) a material reduction in the aggregate, of the benefits provided under employee benefit plans, (D) without his express consent, the relocation of your principal place of business to a location that is more than 40 miles from Ridgefield, Connecticut, or (E) any breach by us of any material provision of his employment agreement.
We had previously entered into an employment agreement with Mr. Kuchta effective December 1, 2010, with a term of one year, with automatic one-year renewals, absent notice by either Mr. Kuchta or us of the intention not to renew the agreement. Under this agreement, Mr. Kuchta has an annual base salary of $675,000, and an annual cash incentive bonus target of 100% of his annual base salary. Mr. Kuchta is eligible to participate in our employee benefit programs, plans and practices in accordance with the terms and conditions of the individual plans, and we provide a life insurance benefit to him in an amount that will equal no less than 200% of his base salary. This employment agreement contains severance protections, standard confidentiality, non-solicitation and non-compete provisions, and also provides for certain severance benefits, among other circumstances, in the event of a separation in service within twelve months following a “Change in Control.” On March 1, 2014, in connection with Mr. Kuchta’s retirement as President and Chief Executive Officer of our general partner, which retirement was within twelve months following Western Refining’s indirect acquisition of our general partner, and following his execution of a general release in our favor, certain of Mr. Kuchta’s rights under his employment agreement were triggered, including (a) payment of 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”); (b) 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”); (c) continued base salary payments for a period of twenty-four months following March 1, 2014; and (d) certain health care continuation benefits following the date of termination of his employment (the “Medical Benefits”). Mr. Kuchta’s rights to continue to receive any benefits described above are subject to his continued compliance with the restrictive covenants in his employment agreement, 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. The amount of cash severance that Mr. Kuchta received during 2014 is $506,250, as included in the Summary Compensation Table. Payments to Mr. Hank Kuchta under his employment agreement were deferred until six months following termination of his employment, consistent with Section 409A of the Code.
Any severance payments and benefits to each of Messrs. Lamp, Bonczek and Kuchta will be made less applicable withholdings and deductions, following execution and delivery of a valid release, and otherwise in accordance with Section 409A of the Code.
LTIP Awards
Under the award agreement for Restricted Units under the LTIP, in the event the employee’s termination of employment with us occurs due to (i) death or Disability, or (ii) termination by us (or an applicable affiliate) without Cause, or (iii) 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. If termination is within twelve

139


months following a Change in Control, all outstanding unvested Restricted Units would be immediately accelerated and become vested.
Under the award agreement for Time-Based Phantom Units, 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 by the employee for Good Reason within twelve months following a Change in Control, all outstanding unvested Time-Based Phantom Units would be immediately accelerated and become vested.
For purposes of both the current Restricted Unit agreements and Time-Based Phantom Unit agreements under the LTIP, 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 or Western Refining 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) our 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.
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, 2014. 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.

140


 
 
Termination For Cause or by Executive without Good Reason
 
Termination due to Death
 
Termination due to Disability
 
Termination without Cause or by Executive for Good Reason outside Change in Control Period
 
Termination Without Cause or by Executive for Good Reason within Change in Control Period
Executive
 
($)
 
($)
 
($)(8)
 
($)
 
($)(9)
David L. Lamp
 
 
 
 
 
 
 
 
 
 
Cash Payments(1)
 

 

 
38,077

 

 
3,400,000

Accelerated Equity Awards(2)
 

 
2,951,993

 
2,951,993

 
2,951,993

 
5,903,985

Continued Benefits(3)
 

 

 

 

 
31,228

Outplacement Services
 

 

 

 

 
15,000

Total
 


2,951,993


2,990,070


2,951,993


9,350,213

David Bonczek
 
 
 
 
 
 
 
 
 
 
Cash Payments(4)
 

 

 
96,662

 
790,385

 
790,385

Accelerated Equity Awards(5)
 

 
2,403,651

 
2,403,651

 
449,221

 
2,663,221

Continued Benefits(6)
 

 

 

 
6,332

 
6,332

Outplacement Services
 

 

 

 
3,000

 
3,000

Total
 


2,403,651


2,500,313


1,248,938


3,462,938

Melissa M. Buhrig
 
 
 
 
 
 
 
 
 
 
Cash Payments
 

 

 
12,777

 

 

Accelerated Equity Awards(7)
 

 
670,222

 
670,222

 

 
670,222

Continued Benefits
 

 

 

 

 

Outplacement Services
 

 

 

 

 

Total
 


670,222


682,999




670,222

Scott L. Stevens
 
 
 
 
 
 
 
 
 
 
Cash Payments
 

 

 
12,227

 

 

Accelerated Equity Awards(7)
 

 
670,222

 
670,222

 

 
670,222

Continued Benefits
 

 

 

 

 

Outplacement Services
 

 

 

 

 

STD
 

 

 

 

 

Total
 

 
670,222

 
682,449

 

 
670,222

(1)
This amount in the "Termination Without Cause or by Executive for Good Reason within Change in Control Period" column reflects two times the sum of Mr. Lamp’s 2014 annual base salary and 2014 target annual bonus under the 2014 Bonus Program, payable in twelve equal monthly installments following his execution and return of a timely and effective release of claims. See footnote (8) below for information of the "Termination due to Disability" column.
(2)
For Mr. Lamp, accelerated equity awards (i) in the event of termination for death or disability, without Cause or by executive for Good Reason outside a Change in Control Period equals 133,333 units, comprising the next tranche scheduled to vest for his outstanding unvested Restricted Units, and (b) in the event of termination without Cause or by executive for Good Reason within a Change in Control Period equals 266,666 units under his Restricted Unit agreement times the closing unit price on December 31, 2014, or $22.14.
(3)
Mr. Lamp and his dependents may receive certain employee benefits for a period of up to two years. "Continued Benefits" represents two years of Mr. Lamp’s currently elected medical, vision, dental, life and disability benefits.
(4)
The amounts in the last two columns reflect the sum of Mr. Bonczek’s 2014 annual base salary and 2014 target annual bonus under the 2014 Bonus Program, payable in a lump sum following his execution and return of a timely and effective release of claims. See footnote (8) below for information of the "Termination due to Disability" column.
(5)
For Mr. Bonczek, accelerated equity awards in the event of termination for death or disability equals 108,566 units, comprising the next tranche scheduled to vest for each of his outstanding unvested Restricted Units and all outstanding unvested Time-Based Phantom Units, times the closing unit price on December 31, 2014, or $22.14. Accelerated equity awards in the event of termination without Cause or by executive for Good Reason (a) outside a Change in Control Period equals 20,290 Restricted Units made prior to January 1, 2014, and (b) within a Change in Control Period that takes place after May 15, 2014, equals 20,290 Restricted Units and 100,000 Time-Based Phantom Units, in each case, times the closing unit price on December 31, 2014, or $22.14.

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(6)
Mr. Bonczek may be reimbursed on a monthly basis for up to six months the difference between amounts he pays for coverage under the Company’s group health plans under COBRA for himself and his eligible dependents, and the employee contribution amount for similar coverages paid by active Company employees. "Continued Benefits" represents six months of Mr. Bonczek’s 2014 elected medical, vision, dental, life and disability benefits, less premiums.
(7)
For Ms. Buhrig and Mr. Stevens, accelerated equity awards in the event of death or disability or termination without Cause or by executive for Good Reason within a Change in Control Period that takes place after May 15, 2014, equals 30,272 units each under the Time-Based Phantom Unit agreement, times the closing unit price on December 31, 2014, or $22.14.
(8)
Our Company’s long-term disability benefit plan (“LTD Plan”) will provide up to 60% of pre-disability earnings up to a maximum of $20,000 per month for an illness or injury that lasts longer than 180 days. The LTD Plan is fully-insured and benefits are paid by the insurance company. Amounts shown here reflect only the sick pay plan payments.
(9)
Change in Control Period means, (a) under Mr. Lamp’s Change in Control Agreement and the Time-Based Phantom Unit agreements, 24 months following a Change in Control, and (b) under Mr. Bonczek’s letter agreement, and the Restricted Unit agreements, 12 months following a Change in Control, in each case, subject to the terms of the respective agreement.
Non-Employee Director Compensation
Non-Employee Director Compensation Process Generally
The compensation paid to directors who are not employees of the Partnership or any subsidiaries (referred to here as "non-employee directors") is designed to attract and retain nationally recognized, highly qualified directors to lead the Company, to meaningfully align the interests of those directors with the interests of unitholders and to be demonstrably fair to both the Company and its non-employee directors. In setting non-employee director compensation, the Compensation Committee and the Board consider these factors, as well as the significant amount of time that directors spend fulfilling their duties, the skill and experience required of the directors and other factors. Non-employee director compensation typically consists of both cash and equity components.
The Compensation Committee evaluates non-employee director compensation and makes its recommendations to the Board, which then sets non-employee director compensation. In developing and making its recommendations to the Board, the Compensation Committee follows a process similar to the process it follows for setting named executive officer compensation, discussed above. The Compensation Committee relies upon various sources of information and advice including the analysis of independent consultants, comparative surveys, third party proprietary databases providing comparative information, the current economic conditions and industry environment in which the Company operates and the Compensation Committee members' common sense, experience and judgment. Generally, the Compensation Committee anticipates receiving a comprehensive analysis from an independent compensation consultant every three years. In years where a comprehensive analysis from an independent compensation consultant is not provided, the Compensation Committee relies upon the other sources and factors referenced above. To the extent the Compensation Committee perceives there are major shifts in compensation trends or desires to make significant modifications to non-employee director compensation, the Compensation Committee may decide, in its discretion, to retain independent compensation consultants to provide more comprehensive analyses more frequently.
2014 Director Compensation
Consistent with the process described above, in 2013 the Compensation Committee retained Pearl Meyer as its independent compensation consultant to provide an analysis of the Company's director compensation, comparative data and associated recommendations. Pearl Meyer provided its analysis on director compensation in November 2013. In setting director compensation for 2014, the Board and its Compensation Committee considered the information in the Pearl Meyer analysis as well as the other factors and objectives discussed above. For 2014, the Board, based in part upon recommendation of the Compensation Committee, elected to pay each director, other than any director who is also an employee of the Partnership or its subsidiaries, as compensation:
an annual retainer of $60,000, payable quarterly;
an award of Restricted Units under the LTIP, which Restricted Units vested in full on January 3, 2015;
an additional annual fee of $15,000 to the chairman of the Audit Committee and of $10,000 to each of the chairmen of the Compensation Committee, Governance Committee and Conflicts Committee, in each case, payable quarterly; and
an additional $1,500 per meeting to each member, including the chairman, of the Conflicts Committee.
Directors will also be reimbursed for certain reasonable expenses in connection with their services to us.

142


2014 Director Compensation
 
 
Fees Earned or paid in Cash
 
Stock Awards
 
All Other Compensation
 
Total
Name
 
($)(1)
 
($)(2)
 
($)(3)
 
($)
Paul L. Foster, Chairman
 
60,000

 
102,730

 
11,190

 
173,920

Lowry Barfield
 
60,000

 
102,730

 
11,190

 
173,920

Timothy Bennett
 
63,000

 
102,730

 
11,190

 
176,920

Rocky Duckworth
 
67,274

 
102,730

 
11,190

 
181,194

Thomas Hofmann
 
78,000

 
102,730

 
11,190

 
191,920

Dan F. Smith
 
73,000

 
102,730

 
11,190

 
186,920

Jeff A. Stevens
 
60,000

 
102,730

 
11,190

 
173,920

Scott D. Weaver
 
46,667

 
116,438

 
6,317

 
169,422

(1)
Amounts in this column reflect the actual cash amount received by each director for 2014 compensation.
(2)
The amounts in this column represent the grant date fair value of the award of Restricted Units calculated in accordance with FASB ASC Topic 718, as follows: (a) for all directors except Mr. Weaver, using the closing price of one common unit of the Partnership on the January 3, 2014, grant date, or $24.88, multiplied by 4,129 Restricted Units; and (b) For Mr. Weaver, using the closing price of one common unit of the Partnership on the June 17, 2014, grant date, or $28.20, multiplied by 4,129 Restricted Units. Other assumptions used to value the grant of the equity awards in this column may be found in Note 16 to our Consolidated Financial Statements. None of these directors held any other outstanding equity awards as of December 31, 2014.
(3)
Messrs. Foster, Barfield, Bennett, Duckworth, Hofmann, Smith and Stevens were each granted 4,129 Restricted Units on January 3, 2014, and Mr. Weaver was granted 4,129 Restricted Units on June 17, 2014; all of these Restricted Units were issued under the LTIP and vested in full on January 3, 2015. Please see Note 16 to our Consolidated Financial Statements for assumptions used in valuing our common units.
(4)
Amounts in this column reflect the quarterly distributions paid in 2014 on these unvested Restricted Units.
2015 Director Compensation
In connection with establishing director compensation for 2015, the Compensation Committee again retained Pearl Meyer as its independent compensation consultant to provide an updated analysis of our director compensation, including comparative data and associated recommendations. Pearl Meyer issued this analysis in November 2014. In setting director compensation for 2015, the Board and its Compensation Committee considered the information in the Pearl Meyer analysis as well as the other factors and objectives discussed above. For 2015, the Board, based in part upon recommendation of the Compensation Committee, elected to pay each director, other than any director who is also an employee of the Partnership or its subsidiaries, an annual retainer of $70,000, payable quarterly, and an award of Time-Based Phantom Units under the LTIP equal to $110,000, the number of Time-Based Phantom Units under such award to be calculated based on the closing price of one common unit of the Partnership on January 2, 2015, which units shall vest in full on the third Wednesday of January 2016 and accrue distribution equivalents which are . In addition, the Board elected to keep committee chairmen and meeting fees the same as in 2014, including an additional fee of $15,000 to the chairman of the Audit Committee and of $10,000 to each of the chairmen of the Compensation Committee, Governance Committee and Conflicts Committee, payable quarterly; and a fee of $1,500 for each meeting of the Conflicts Committee.
Compensation Committee Interlocks and Insider Participation
Mr. Smith served as a member of our Compensation Committee throughout 2014. Messrs. Barfield and Weaver served as members of our Compensation Committee throughout 2014, beginning on January 2, 2014. Mr. Scott Josey, who resigned from our Board on January 2, 2014, served as a member of the Compensation Committee for one day during 2014, until his resignation on January 2, 2014. During 2014, 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, except that from December 23, 2013, until April 30, 2014, Mr. Weaver served as Interim Vice President-Administration of our general partner and of Northern Tier Energy LLC, solely to assist with certain transition activities in connection with Western Refining’s indirect acquisition of our general partner. Mr. Weaver was not an employee during this time. In addition, none of the members of the Compensation Committee are former employees of ours or any of our subsidiaries.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.

143


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, 2015 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 1250 W. Washington Street, Suite 300, Tempe, Arizona 85281.
 
 
Norther Tier Energy, LP
 
Western Refining, Inc.
Name
 
Common Units Beneficially Owned
 
Percentage of Common Units Beneficially Owned
 
Common Units Beneficially Owned
 
Percentage of Common Units Beneficially Owned
Paul L. Foster, Chairman(4)
 
4,129

 
*

 
19,158,509

 
20.1
%
Jeff A. Stevens, Director(4)
 
4,129

 
*

 
3,490,649

 
3.7
%
Scott D. Weaver, Director(4)
 
4,129

 
*

 
1,301,691

 
1.4
%
Lowry Barfield, Director(4)
 
4,129

 
*

 
53,126

 
0.1
%
Thomas Hofmann, Director(4)
 
7,627

 
*

 

 
*

Rocky Duckworth, Director(4)
 
7,471

 
*

 

 
*

Timothy Bennet, Director(4)
 
4,129

 
*

 

 
*

Dan F. Smith, Director(4)
 
7,627

 
*

 

 
*

David L. Lamp, President and CEO, Director(3)(4)
 
400,000

 
0.4
%
 

 
*

David Bonczek, EVP and CFO(3)
 
45,817

 
*

 

 
*

Melissa M. Buhrig, EVP and General Counsel(3)
 
6,676

 
*

 
5,162

 
*

Karen B. Davis, EVP(3)
 

 
*

 

 
*

Scott L. Stevens, SVP and CCO(3)
 
6,673

 
*

 

 
*

Hank Kuchta, former President and CEO(2)
 
66,199

 
0.1
%
 

 
*

All directors and executive officers as a group
 
568,735

 
0.6
%
 
24,009,137

 
25.2
%
Other 5% or more unitholders:
 
 
 
 
 
 
 
 
NT InterHoldCo LLC(1)
 
35,622,500

 
38.4
%
 

 
%
 * Represents less than 1%.
(1)
All of the membership interests in NT InterHoldCo LLC are owned by Western Refining, a Delaware corporation.
(2)
Includes 1,100 common units held by Mr. Kuchta’s son and 1,100 common units held by his daughter, who shares his household. Mr. Kuchta disclaims beneficial ownership of the securities except to the extent of his pecuniary interest therein. Information for Mr. Kuchta is as of March 1, 2014, the last date information regarding Mr. Kuchta’s holdings was available to us.
(3)
Executive officer of our general partner.
(4)
Director of our general partner.
Equity Compensation Plan Information
The following table provides information as of December 31, 2014, regarding compensation plans (including individual compensation arrangements) under which our common units are authorized for issuance.

144


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 owned 100% of our general partner and approximately 38.7% of our outstanding common units.
As of February 26, 2015, Western Refining owns 35,622,500 common units, representing an approximately 38.4% limited partner interest in us. Transactions with Western Refining and its affiliated entities are considered to be related party transactions because Western Refining and its affiliates own more than 5% of our equity interests; in addition, some of Western Refining's executive officers serve as directors of our general partner.
Whenever a conflict arises between our general partner or its affiliates on the one hand, and us or our limited partners on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is:
approved by the conflicts committee of our general partner, although our general partner s not obligated to seek such approval; or
approved by the holders of a majority of the outstanding common units, excluding any such units owned by our general partner or any of its affiliates.
Our general partner may, but is not required to, seek the approval of such resolutions or courses of action from the conflicts committee of its board of directors or from the holders of a majority of the outstanding common units as described above. If our general partner does not seek approval from the conflicts committee or from holders of common units as described above and the board of directors of our general partner approves the resolution or course of action taken with respect to the conflict of interest, then it will be presumed that, in making its decision, the board of directors of our general partner acted in good faith, and in any proceeding brought by or on behalf of us or any of our unitholders, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, the board of directors of our general partner or the conflicts committee of the board of directors of our general partner may consider any factors they determine in good faith to consider when resolving a conflict. An independent third party is not required to evaluate the resolution. Under our partnership agreement, a determination, other action or failure to act by our general partner, the board of directors of our general partner, or any committee thereof (including the conflicts committee) will be deemed to be in “good faith” if our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) subjectively believed such determination, other action or failure to act was in, or not opposed to, the best interests of the partnership or meets the standard otherwise specified in our partnership agreement.
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.”

145


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.
On March 25, 2014, we changed our independent registered public accounting firm from PricewaterhouseCoopers LLP to Deloitte & Touche LLP. 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 Deloitte & Touche LLP and PricewaterhouseCoopers LLP for 2014 and 2013, respectively:
(in thousands)
 
2014
 
2013
Audit fees
 
$
1,089

 
$
1,572

Audit related
 
60

 
41

Tax Fees
 
785

 

All other fees
 
2

 
2

Total
 
$
1,936

 
$
1,615

For 2014, audit fees consisted of fees billed for professional services rendered for (i) the audit of the Company’s 2014 consolidated financial statements, (ii) the audit of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2014, (iii) the review of the Company’s interim consolidated financial statements included in quarterly reports and (iv) other services that were regularly provided by Deloitte & Touche LLP in connection with security offerings. Tax fees include $0.5 million for tax compliance services, $0.1 million for tax planning services and $0.2 million of pass through expenses in connection with acquiring investor data necessary for preparation of Form K-1s.
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.
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 Deloitte & Touche LLP. This policy lists specific audit-related services as well as any other services that Deloitte & Touche 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 2014, all fees reported above were approved in accordance with the Pre-Approval Policy.

146


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, 2014 and 2013
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2014, 2013 and 2012
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
Consolidated Statements of Partners' Capital and Member's Interest for the Years Ended December 31, 2014, 2013 and 2012
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. (Incorporated by reference to Exhibit 3.3 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
 
 
 
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).
 
 

147


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 Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, 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).
 
 
 
4.4
 
Supplemental Indenture, dated November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
4.5
 
Registration Rights Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
 
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).
 
 
10.8(c)
 
Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference Exhibit 10.2 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).
 
 

148


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(c)
 
Form of 2012 Long Term Incentive Plan Restricted Unit Agreement (Performance-Based) (Incorporated by reference to Exhibit 10.14 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
 
 
10.15(c)
 
Form of Time-Based Phantom Unit Award Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
 
 
 
10.16(c)
 
2014 Incentive Compensation Plan (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
 
 
 
10.17(c)
 
Change in Control Severance Agreement between Northern Tier Energy LLC and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).
 
 
 
10.18(c)
 
Restricted Unit Agreement (Time-Based) between Northern Tier Energy LP and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).
 
 
 
10.19(c)
 
Employment Letter Agreement, dated August 4, 2014, by and between Northern Tier Energy LLC and David Bonczek (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on August 5, 2014).
 
 
 
10.20
 
Credit Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, each subsidiary of Northern Tier Energy LLC party thereto, the lenders party thereto, the issuing banks party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
 
10.21
 
Shared Services Agreement by and among Northern Tier Energy LLC and Western Refining Southwest, Inc. and Western Refining Company, L.P., dated October 30, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on November 4, 2014).
 
 
 
10.22(c)
 
Northern Tier 2015 Performance Bonus Program (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
 
 
 
10.23(c)
 
Form of Performance-Based Phantom Unit Agreement (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
 
 
 
10.24(c)
 
Form of Employment Agreement for Executive Officers (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on January 26, 2014).
 
 
 
10.25(c)
 
Form of Indemnification Agreement for Executive Officers (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on January 26, 2014).
 
 
 
21.1(a)
 
List of subsidiaries of Northern Tier Energy LP.
 
 
23.1(a)
 
Consent of Deloitte and Touche LLP - Independent Registered Public Accounting Firm.
 
 
 
23.2(a)
 
Consent of PricewaterhouseCoopers LLP—Independent Registered Public Accounting Firm.
 
 
 
31.1(a)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2014 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 

149


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, 2014 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.1(b)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2014 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, 2014 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101.INS(a)
 
XBRL Instance Document.
 
 
101.SCH(a)
 
XBRL Taxonomy Extension Schema Document.
 
 
101.CAL(a)
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF(a)
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
101.LAB(a)
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE(a)
 
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.

150


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/ David L. Lamp
Name:
 
David L. Lamp
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/ DAVE LAMP
 
Director, President and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)
 
February 27, 2015
Dave Lamp
 
 
 
 
 
 
/s/ DAVID BONCZEK
 
Executive Vice President and Chief Financial Officer of
Northern Tier Energy GP LLC
(Principal Financial Officer and Principal Accounting Officer)
 
February 27, 2015
David Bonczek
 
 
 
 
 
 
/s/ PAUL FOSTER
 
Director and Chairman of Northern Tier Energy GP LLC
 
February 27, 2015
Paul Foster
 
 
 
 
 
 
 
/s/ LOWRY BARFIELD
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Lowry Barfield
 
 
 
 
 
 
 
/s/ TIMOTHY BENNETT
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Timothy Bennett
 
 
 
 
 
 
 
/s/ ROCKY DUCKWORTH
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Rocky Duckworth
 
 
 
 
 
 
 
/s/ THOMAS HOFMANN
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Thomas Hofmann
 
 
 
 
 
 
 
/s/ DAN F. SMITH
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Dan F. Smith
 
 
 
 
 
 
/s/ JEFF STEVENS
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Jeff Stevens
 
 
 
 
 
 
 
 
 
/s/ SCOTT WEAVER
 
Director of Northern Tier Energy GP LLC
 
February 27, 2015
Scott Weaver
 
 
 
 

151


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. (Incorporated by reference to Exhibit 3.3 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
 
 
 
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 Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, 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).
 
 
 
4.4
 
Supplemental Indenture, dated November 2, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
4.5
 
Registration Rights Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the guarantors party thereto and Deutsche Bank Trust Company Americas, as trustee (Incorporated by reference to Exhibit 4.2 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
 
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).
 
 

152


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).
 
 
10.8(c)
 
Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference Exhibit 10.2 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(c)
 
Form of 2012 Long Term Incentive Plan Restricted Unit Agreement (Performance-Based) (Incorporated by reference to Exhibit 10.14 to our Annual Report on Form 10-K, File No. 001-35612, filed on February 27, 2014).
 
 
10.15(c)
 
Form of Time-Based Phantom Unit Award Agreement (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
 
 
 
10.16(c)
 
2014 Incentive Compensation Plan (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on May 2, 2014).
 
 
 
10.17(c)
 
Change in Control Severance Agreement between Northern Tier Energy LLC and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).
 
 
 
10.18(c)
 
Restricted Unit Agreement (Time-Based) between Northern Tier Energy LP and David L. Lamp, effective March 1, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on May 7, 2014).
 
 
 

153


10.19(c)
 
Employment Letter Agreement, dated August 4, 2014, by and between Northern Tier Energy LLC and David Bonczek (Incorporated by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on August 5, 2014).
 
 
 
10.20
 
Credit Agreement, dated September 29, 2014, by and among Northern Tier Energy LLC, each subsidiary of Northern Tier Energy LLC party thereto, the lenders party thereto, the issuing banks party thereto and JPMorgan Chase Bank, N.A., as administrative agent (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on October 3, 2014).
 
 
 
10.21
 
Shared Services Agreement by and among Northern Tier Energy LLC and Western Refining Southwest, Inc. and Western Refining Company, L.P., dated October 30, 2014 (Incorporated by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q, File No. 001-35612, filed on November 4, 2014).
 
 
 
10.22(c)
 
Northern Tier 2015 Performance Bonus Program (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
 
 
 
10.23(c)
 
Form of Performance-Based Phantom Unit Agreement (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on December 8, 2014).
 
 
 
10.24(c)
 
Form of Employment Agreement for Executive Officers (Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K, File No. 001-35612, filed on January 26, 2014).
 
 
 
10.25(c)
 
Form of Indemnification Agreement for Executive Officers (Incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K, File No. 001-35612, filed on January 26, 2014).
 
 
 
21.1(a)
 
List of subsidiaries of Northern Tier Energy LP.
 
 
23.1(a)
 
Consent of Deloitte and Touche LLP - Independent Registered Public Accounting Firm.
 
 
 
23.2(a)
 
Consent of PricewaterhouseCoopers LLP—Independent Registered Public Accounting Firm.
 
 
 
31.1(a)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2014 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, 2014 Annual Report on Form 10-K, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.1(b)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, for the December 31, 2014 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, 2014 Annual Report on Form 10-K, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101.INS(a)
 
XBRL Instance Document.
 
 
101.SCH(a)
 
XBRL Taxonomy Extension Schema Document.
 
 
101.CAL(a)
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF(a)
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
101.LAB(a)
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
 
101.PRE(a)
 
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.


154