10-K 1 nti-12312014x10k.htm 10-K NTI-12.31.2014-10K

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.

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Turnaround and Refinery Reliability
Periodically, we have planned maintenance turnarounds at our refinery, which require the temporary shutdown of certain operating units. The refinery generally undergoes a major facility turnaround every five to six years, and the last major 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.

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Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Other Non-GAAP Performance Measures.”
(2)
Merchandise margin is expressed as a percentage of the merchandise sales, calculated by subtracting the costs of merchandise from the merchandise sales, and then dividing by merchandise sales. Merchandise margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Merchandise margin includes all non-fuel sales at our company-operated stores including items like cigarettes, beer, milk, food, general merchandise, car wash and other commission-based revenue. For a reconciliation of merchandise margin to retail segment operating income, the most directly comparable GAAP measure, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Other Non-GAAP Performance Measures.”
(3)
Represents fuel gallons sold to franchised stores by our refinery.
Retail Operations Suppliers
Our refinery supplies 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.

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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

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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.

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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.

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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)