News Column

NORTHERN TIER ENERGY LP - 10-K - Management's Discussion and Analysis of Financial Condition and Results of Operations.

February 27, 2014

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this Annual Report on Form 10-K. The following discussion contains "forward-looking statements" that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors, including those we discuss under "Item 1A. Risk Factors" elsewhere in this report. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See "Cautionary Note Regarding Forward-Looking Statements." Overview We are an independent downstream energy limited partnership with refining, retail and pipeline operations that serves the PADD II region of the United States. We operate our assets in two business segments: the refining business and the retail business. For the year ended December 31, 2013, we had total revenues of $5.0 billion, operating income of $238.7 million, net income of $231.1 million and Adjusted EBITDA of $363.2 million. A definition and reconciliation of Adjusted EBITDA to net income is included herein under the caption "Adjusted EBITDA." Partnership Structure and Management We commenced operations in December 2010 as Northern Tier Energy LLC ("NTE LLC") through the acquisition of our St. Paul Park, Minnesota refinery, a 17% interest in MPL and in MPL Investments, our convenience stores and related assets (the "Marathon Assets") from Marathon for $554 million, which included cash and the issuance to Marathon of $80 million of a noncontrolling preferred membership interest in NT Holdings. In July 2012, Northern Tier Energy LP ("NTE LP") was formed as a Delaware limited partnership by NT Holdings. Our non-economic general partner interest is held by Northern Tier Energy GP LLC, a Delaware limited liability company. References to our "general partner," as the context requires, include only Northern Tier Energy GP LLC. Our operations are conducted directly and indirectly through our primary operating subsidiaries. On July 31, 2012, we completed our IPO of 18,687,500 common units, representing an approximate 20.3% ownership interest in the Partnership. In exchange for contributing all of the interests in our operating subsidiaries, NT Holdings received 57,282,000 common units and 18,383,000 PIK common units. In November 2012, the PIK common units automatically converted to common units. Through the IPO and a series of secondary offerings during 2013, NT Holdings sold 40,042,500 of its common units in NTE LP. On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed its remaining 35,622,500 common units of NTE LP and its ownership rights in Northern Tier Energy GP LLC, the non-economic general partner of NTE LP, to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings sold NT InterHoldCo LLC to Western Refining. Refining Business Our refining business primarily consists of an 89,500 bpd (96,500 barrels per stream day) refinery located in St. Paul Park, Minnesota. We are one of only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the PADD II region. Our refinery's complexity allows us to process a variety of light, heavy, sweet and sour crudes, many of which have historically priced at a discount to the NYMEX WTI price benchmark, meaning we can process lower cost crude oils into higher value refined products. The PADD II region covers Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, South Dakota, Ohio, Oklahoma, Tennessee and Wisconsin. Our strategic location allows us direct access, primarily via the Minnesota Pipeline, to sources of crude oil from Western Canada and North Dakota, as well as the ability to distribute our refined products throughout the midwestern United States. Our refinery produces a broad slate of refined products including gasoline, diesel, jet fuel and asphalt, which are then marketed to resellers and consumers primarily in the PADD II region. Approximately 80%, 80% and 79% of our total refinery production for the years ended December 31, 2013, 2012 and 2011, respectively, was comprised of higher value, light refined products, including gasoline and distillates. Our refinery utilization rates, using standard industry methodologies for utilization measurement, have been 68%, 80% and 75% for the years ended December 31, 2013, 2012 and 2011, respectively. The reduction in utilization during the year ended December 31, 2013 is primary due to the major plant turnaround, capacity expansion and unplanned maintenance during 2013. We also own various storage and transportation assets, including a light products terminal, a heavy products terminal, storage tanks, rail loading/unloading facilities, the Aranco and Cottage Grove pipelines and a Mississippi river dock. Approximately 70%, 78% and 83% of our gasoline and diesel volumes for the years ended December 31, 2013, 2012 and 2011, respectively, were sold via our light products terminal located at the refinery to our company-operated and franchised SuperAmerica branded convenience stores, Marathon branded convenience stores and other resellers. We have a contract with Marathon to supply substantially all of the gasoline and diesel requirements for the independently-owned and operated Marathon branded convenience stores in our distribution area. Beginning in December 2012, we initiated a crude oil 50



--------------------------------------------------------------------------------

Table of Contents

transportation business in North Dakota to allow us to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota. Our refining business also includes our 17% interest in MPL and MPL Investments, which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery. During September 2013, our St. Paul Park refinery experienced lower utilization primarily due to a fire which occurred in our larger crude distillation unit. Due to this unplanned downtime, the start date of the planned turnaround on our Fluid Catalytic Cracker ("FCC") unit, which was scheduled to begin October 1, 2013, was accelerated into September 2013. All repairs to the refinery were completed at a cost of less than $3 million and both crude towers were restored to full functionality by October 14, 2013. Beginning on October 14, 2013, our St. Paul Park refinery was operating at a crude oil charge of between 85,000 - 90,000 bpd, which is consistent with throughput constraints related to the FCC turnaround being performed at that time. The FCC turnaround was completed by the end of October and the unit was fully functional within the first week of November. In addition to the repair costs incurred, the unplanned downtime in September and October negatively impacted our refining segment's operating results due to lower throughput levels requiring us to purchase refined products from third parties for sale to our customers. Retail Business As of December 31, 2013, our retail business operated 164 convenience stores under the SuperAmerica brand and also supported 75 franchised convenience stores, which are also operated under the SuperAmerica brand. These convenience stores are located primarily in Minnesota and Wisconsin and sell various grades of gasoline and diesel, tobacco products and immediately consumable items such as beverages, prepared food and a large variety of snacks and prepackaged items. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated stores and franchised convenience stores within our distribution area for the years ended December 31, 2013, 2012 and 2011. We also own and operate SuperMom's Bakery, which prepares and distributes baked goods and other prepared food items for sale in our company-operated and franchised convenience stores and other third party locations. Outlook Transportation fuels demand in the Upper Great Plains of the PADD II region currently exceeds supply from local refineries. Therefore, demand is fulfilled by products that are imported into the region mostly via pipeline from other parts of the Midwest, the Rocky Mountains and the U.S. Gulf Coast. Overall refined product demand declined in 2008 as a result of prevailing economic conditions and began to improve in the first quarter of 2010. While there continues to be a significant global macroeconomic risk that may affect the pace of growth in the United States, we have experienced continued strong overall product demand in our geographic area of operations. Our operating performance has benefited from the widening of the price relationship between the traditional crude oil pricing benchmark, NYMEX WTI, and the international waterborne crude oil pricing benchmark, Brent. We purchase crude oil which is priced based off NYMEX WTI. Refined products prices are set by global markets and are typically priced off Brent. Therefore, we have enjoyed a benefit during the years ended December 31, 2013, 2012 and 2011 from the overall widening of the price differential between our cost of crude oil and the price of the products we sell. The widening differential may have been attributable to several factors, including geopolitical events in the Middle East, the suspension of crude oil exports from Libya, new U.N. sanctions on Iran's oil exports, and limited pipeline and other infrastructure to transport crude oil from Cushing, Oklahoma, where NYMEX WTI is settled, to alternative markets. Please see "Item 1A. Risk Factors-Risks Primarily Related to Our Refining Business-Our results of operations are affected by crude oil differentials, which may fluctuate substantially." Regardless of the relationship in the price differential of WTI to Brent crude oil, we feel our refinery location provides us a strategic advantage. Our strategic location allows us direct access, primarily via the Minnesota Pipeline, to what we believe are abundant supplies of advantageously priced crude oils. Of the crude oil processed at our refinery in the years ended December 31, 2013, 2012 and 2011, approximately 50%, 47% and 51%, respectively, was Canadian crude oil and the remainder was primarily comprised of light sweet crude oil from the Bakken Shale in North Dakota. Many of these crudes have historically priced at a discount to WTI. Demand for these crudes extends to the coastal section of the United States. As pipeline infrastructure continues to develop for the transportation of these crudes, rail transportation will also be required to move significant portions of current and future production volumes. As such, our refinery should continue to benefit from the price advantage between rail transportation to the marginal buyers on the East/Gulf Coasts and pipe transportation to St Paul Park, MN. 51



--------------------------------------------------------------------------------

Table of Contents

Comparability of Historical Results The IPO Transactions Our results of operations for periods subsequent to the closing of our IPO may not be comparable to our results of operations for periods prior to the closing of our IPO as a result of certain aspects of our IPO, including the following: Our general and administrative expenses have increased as a result of our



IPO. Specifically, we incur certain expenses relating to being a publicly

traded partnership, including Exchange Act reporting expenses; expenses

associated with Sarbanes-Oxley Act compliance; expenses associated with

our listing on the NYSE; independent auditors fees and expenses associated

with tax return and Schedule K-1 preparation and distribution; legal fees;

investor relations expenses; transfer agent fees; director and officer

liability insurance costs; and director compensation.

Northern Tier Energy LLC and its subsidiaries have historically not been

subject to federal income and certain state income taxes. After

consummation of our IPO, Northern Tier Retail Holdings LLC, the subsidiary

of Northern Tier Energy LLC through which we conduct our retail business,

and Northern Tier Energy Holdings LLC elected to be treated as

corporations for federal income tax purposes, subjecting these

subsidiaries to corporate-level tax. As a result of the elections by

Northern Tier Retail Holdings LLC and Northern Tier Energy Holdings LLC to

be treated as corporations for federal income tax purposes, for periods

following such elections, our financial statements will include a tax

provision on income attributable to these subsidiaries. Giving effect to

such elections, we recorded an $8.0 million tax charge to recognize the

net deferred tax asset and liability position as of the date of the

elections.

2020 Secured Notes Offering and Tender Offer Our results of operations for periods subsequent to the completion of our 2020 Secured Notes offering and tender offer may not be comparable to our results of operations for periods prior to the refinancing. On November 8, 2012, we completed a private placement of $275 million in aggregate principal amount of the 2020 Secured Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Secured Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Secured Notes outstanding (which notes were called for redemption after the closing of the tender offer) and to pay related fees and expenses. The repurchase of the 2017 Secured Notes resulted in an after-tax charge of $50.0 million in the year ended December 31, 2012. Major Influences on Results of Operations Refining Our earnings and cash flows from our refining business segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Refining is primarily a margin-based business, and in order to increase profitability, it is important for the refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses. Feedstocks are petroleum products, such as crude oil and natural gas liquids that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on several factors, many of which are beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products, which depend on changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of and access to transportation infrastructure, the availability of imports, the marketing of competitive fuel, and the extent of government regulation, among other factors. Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors' facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a negative impact on product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. In order to assess our operating performance, we compare our refinery gross product margin against an industry refining margin benchmark. The industry refining margin benchmark we use is referred to as the Group 3 3:2:1 crack spread. We calculate the benchmark refining margin using the market value of PADD II Group 3 conventional gasoline and ultra low sulfur diesel against the market value of NYMEX WTI crude oil. The Group 3 3:2:1 crack spread is expressed in dollars per 52



--------------------------------------------------------------------------------

Table of Contents

barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at PADD II Group 3 prices the benchmark production of gasoline and ultra low sulfur diesel. Our direct operating expense structure is also important to our profitability. Major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations have historically been volatile. Consistent, safe and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform needed maintenance, contractual commitments, feedstock logistics and other factors. Periodically, we have planned maintenance turnarounds at our refinery, which are expensed as incurred. The refinery generally undergoes a major facility turnaround every five to six years. The length of the turnaround is contingent upon the scope of work to be completed. A major turnaround of either of the two main refinery units (fluid catalytic cracking unit and alkylation unit) generally takes two to four weeks to complete, and is planned and accomplished in a manner that allows for reduced production during maintenance instead of a complete shutdown. We completed a partial turnaround in April 2011, principally to replace a catalyst in the distillate and gas oil hydrotreaters, and to conduct basic maintenance on the No. 1 crude unit. We completed the planned partial turnaround of the alkylation unit according to schedule in May 2012 and the planned partial turnaround of the No. 1 reformer unit in November 2012. During 2013, we completed our planned major turnaround across our refinery and a partial turnaround involving our FCC unit. We are currently planning a partial turnaround to occur during 2014 for our gas oil hydrotreater unit, for which we have budgeted aggregate spending of approximately $10 million to $15 million. Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower the target inventory we are able to maintain, the lesser is the impact of commodity price volatility on our petroleum product inventory position. Our inventory of crude oil and refined products is valued at the lower of cost or market value under the LIFO cost flow assumption. For periods in which the market price declines below our LIFO cost basis, we are subject to significant fluctuations in the recorded value of our inventory and related cost of products sold. Since 2009, we have experienced LIFO liquidations based upon permanent decreased levels in our inventories. These LIFO liquidations resulted in increased cost of sales and decreased income from operations of $1.0 million for the year ended December 31, 2013 and decreased cost of sales and increased income from operations of $4.1 million for the year ended December 31, 2011. There were no such liquidations in the year ended December 31, 2012. At the closing of the Marathon Acquisition, we entered into a crude oil supply and logistics agreement with JPM CCC pursuant to which JPM CCC assists us in the purchase of most of the crude oil requirements of our refinery and provides transportation and other logistical services for delivery of the crude oil to our storage tanks in Cottage Grove, Minnesota. In March 2012, we amended and restated the crude oil supply and logistics agreement with JPM CCC. We pay JPM CCC the price of the crude oil plus certain agreed fees and expenses. This crude oil supply and logistics agreement allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, which reduces our crude inventories and reduces the time we are exposed to market fluctuations before the finished product is sold. In addition, we may hedge a portion of the sale of our gasoline and distillate production with the purpose of ensuring we can meet our fixed cost obligations, service our outstanding debt and other liabilities and meet our capital expenditure obligations. We have entered into agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. As market conditions permit, we have the capacity to hedge our crack spread risk with respect to a portion of the refinery's projected monthly production of these refined products. As of December 31, 2013, we have no hedged barrels of future gasoline and diesel production. Our refining business experiences seasonal effects. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lower gasoline prices. As a result, our operating results of our refining business for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year. Retail Our earnings and cash flows from our retail business segment are primarily affected by the volumes and margins of gasoline and diesel sold, and by the sales and margins of merchandise sold at our convenience stores. Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our convenience stores. As a result, the operating results of our retail segment are generally lower for the first quarter of the year. Weather conditions in our operating area also have a significant 53



--------------------------------------------------------------------------------

Table of Contents

effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Margins for transportation fuel sales are equal to the sales price (which includes the motor fuel taxes) less the delivered cost of the fuel and motor fuel taxes, and are measured on a cents per gallon basis. Fuel margins are impacted by local supply, demand and competition. Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of any supplier discounts and inventory shrinkage, and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding and competition. Franchisees are required to pay us an initial license fee (generally, $10,000 for licensees located in Minnesota and Wisconsin and $2,000 for licensees located in South Dakota) and a royalty fee for all products and merchandise sold at the convenience store, including motor fuel and diesel. The initial term of the license is generally 10 years, which is renewable by the licensee for a renewal term of 10 years, subject to the licensee satisfying certain conditions. The license agreements also require that, if a franchise store is located within our distribution area, then the franchise store must purchase a high minimum percentage (often 85% to 100%) of its motor fuel supply, including gasoline and distillate, from us. However, if a franchise store is not located within our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of December 31, 2013, 38 of the 75 existing franchise stores are located within our distribution area and, thus, required to purchase a high minimum percentage of their motor fuel supply from us. Results of Operations We operate our business in two segments: the refining segment and the retail segment. Each of these segments is organized and managed based upon the nature of the products and services they offer. Through the refining segment, we operate the St. Paul Park, Minnesota, refinery, terminal and related assets, and through the retail segment, we operate 164 convenience stores primarily in Minnesota. The refining segment also includes our investment in MPL and the retail segment also includes the operations of SuperMom's Bakery and SuperAmerica Franchising LLC, our wholly-owned subsidiary ("SAF"), through which we conduct our franchising operations. In this "Results of Operations" section, we first review our business on a consolidated basis, and then separately review the results of operations of each of the refining segment and the retail segment. Detailed explanations of the period over period changes in our results of operations are contained in the discussion of individual segments. We refer to our financial statement line items in the explanation of our period over period changes in results of operations. Below are general definitions of what those line items include and represent. Revenue. Revenue primarily includes the sale of refined products and crude oil in our refining segment and sales of fuel and merchandise to retail consumers in our retail segment. All sales are recorded net of customer discounts and rebates and inclusive of federal and state excise taxes. Refining revenue includes intersegment sales of refined products to the retail segment. Retail revenue primarily includes sales of fuel and merchandise to customers inclusive of related excise taxes and net of any applicable discounts. Also included in retail revenue is royalty income, revenues from car wash operations and SuperMom's Bakery sales to third parties. Cost of sales. Refining cost of sales primarily include costs of crude and refinery feedstocks purchased, ethanol and other refined products purchased, including transportation costs, and excise taxes paid to various government authorities. Retail cost of sales consists of cost of fuel, merchandise and other products, costs of sales for SuperMom's Bakery merchandise sales to third parties and excise taxes paid to various government authorities. Retail cost of sales includes intersegment purchases of refined products from the refining segment. For purposes of presenting cost of sales on a consolidated basis, such intersegment transactions are eliminated. Direct operating expenses. Direct operating expenses include the operating expenses of the refinery and costs of operating the convenience stores and the bakery. Refining direct operating expenses primarily include direct costs of labor, maintenance materials and services, chemicals and catalysts, utilities and other direct operating expenses of the refinery. Retail direct operating expenses consist primarily of salaries, labor and benefits, bankcard processing fees, contracted services, repair and maintenance, utilities and rent expense. Turnaround and related expenses. Turnaround and related expenses represent the costs of required major maintenance projects on refinery processing units. A turnaround is a standard industry operation to refurbish and maintain a refinery and usually requires the shutdown and inspection of major processing units. Processing units require major maintenance every five to six years. Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the statement of operations of the carrying value of capital and intangible assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset. 54



--------------------------------------------------------------------------------

Table of Contents

Selling, general and administrative. Selling, general and administrative expenses primarily include corporate costs, administrative expenses, shared service costs and marketing expenses. Formation and offering costs. Formation and offering costs represent charges related to offering costs for the sale of common units that did not meet the accounting requirements for deferral and charges recognized or costs incurred related to the creation of Northern Tier Energy LLC and its subsidiaries. Contingent consideration (income) expense. Contingent consideration (income) expense relates to changes in the estimated fair value of our margin support and earn-out arrangements with Marathon. Other (income) expense, net. Other (income) expense, net primarily represents (income) expense from our equity method investment in MPL and dividend income from our cost method investment in MPL Investments. Gains (losses) from derivative activities. Gain (loss) from derivative activities primarily includes impacts from our crack spread risk mitigation strategy initiated in October 2010 in anticipation of the Marathon Acquisition to mitigate market price risk. Included in gain (loss) from derivative activities are settlement gains or losses related to settled contracts during the period and the change in fair value of outstanding derivatives to partially hedge the crack spread margins for our refining business. Going forward, we plan to hedge a lesser amount of our production than we hedged at the time of the Marathon Acquisition. Interest expense, net. Interest expense, net relates primarily to interest incurred on our senior secured notes as well as commitment fees and interest on the revolving credit facility and the normal amortization of deferred financing costs. Income tax provision. Income tax provision represents federal and state income tax expense related to the current year period and includes both current and deferred income tax expense. 55



--------------------------------------------------------------------------------

Table of Contents Consolidated Financial Data Year Ended December 31, (in millions) 2013 2012 2011 Revenue $ 4,979.2$ 4,653.9$ 4,280.8 Costs, expenses and other: Cost of sales 4,291.6 3,584.9 3,512.4 Direct operating expenses 262.4 254.1 257.9 Turnaround and related expenses 73.3 26.1



22.6

Depreciation and amortization 38.1 33.2



29.5

Selling, general and administrative 85.8 88.3



88.7

Formation and offering costs 3.1 1.4



7.4

Contingent consideration loss (income) - 104.3 (55.8 ) Other income, net (13.8 ) (9.4 ) (4.5 ) Operating income 238.7 571.0 422.6



Gains (losses) from derivative activities 23.5 (271.4 ) (352.2 ) Interest expense, net

(26.9 ) (42.2 ) (42.1 ) Loss on early extinguishment of debt - (50.0 ) - Income before income taxes 235.3 207.4 28.3 Income tax provision (4.2 ) (9.8 ) - Net income $ 231.1$ 197.6$ 28.3 Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012 Revenue. Revenue for the year ended December 31, 2013 was $4,979.2 million compared to $4,653.9 million for the year ended December 31, 2012, an increase of 7.0%. Refining segment revenue increased 7.7% and retail segment revenue decreased 1.6% compared to the year ended December 31, 2012. Refining revenue included a $618.4 million increase in crude oil revenues in the year ended December 31, 2013, partially offset by a 5.8% decrease in sales volumes of refined products versus the year ended December 31, 2012. These crude oil revenues relate to the sale of crude barrels (often accompanied by an offsetting purchase) with the objective of optimizing our crude slate in a given period. The lower refined product volumes are primarily attributable to planned downtime resulting from the turnaround and capacity expansion activities and unplanned maintenance at our St. Paul Park refinery in the year ended December 31, 2013 that reduced refining throughput. Retail revenue decreased primarily due to lower market prices per gallon for fuel sales during the year ended December 31, 2013. Excise taxes included in revenue totaled $316.4 million and $300.1 million for the years ended December 31, 2013 and 2012, respectively. Cost of sales. Cost of sales totaled $4,291.6 million for the year ended December 31, 2013 compared to $3,584.9 million for the year ended December 31, 2012, an increase of 19.7%, primarily due to higher crude costs in the year ended December 31, 2013 and an increase of $618.7 million related to crude oil sales, partially offset by lower refining sales volumes. Excise taxes included in cost of sales were $316.4 million and $300.1 million for the years ended December 31, 2013 and 2012, respectively. Direct operating expenses. Direct operating expenses totaled $262.4 million for the year ended December 31, 2013 compared to $254.1 million for the year ended December 31, 2012, an increase of 3.3%, due primarily to the impact of higher catalyst, unplanned maintenance and employee related costs within our refining segment in the year ended December 31, 2013. Turnaround and related expenses. Turnaround and related expenses totaled $73.3 million for the year ended December 31, 2013 compared to $26.1 million for the year ended December 31, 2012. The turnaround costs in the year ended December 31, 2013 include the costs of a planned major plant turnaround which lasted the entire month of April 2013 and a planned partial turnaround involving our FCC unit which was completed during October 2013. The 2012 partial turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012. Depreciation and amortization. Depreciation and amortization was $38.1 million for the year ended December 31, 2013 compared to $33.2 million for the year ended December 31, 2012, an increase of 14.8%. This increase was due to increased assets placed in service as a result of our capital expenditures since December 31, 2012, primarily within our refining segment. 56



--------------------------------------------------------------------------------

Table of Contents

Selling, general and administrative expenses. Selling, general and administrative expenses were $85.8 million for the year ended December 31, 2013 compared to $88.3 million for the year ended December 31, 2012. This decrease of 2.8% from the prior-year period relates primarily to lower employee related and risk management costs. Formation and offering costs. Formation and offering costs for the years ended December 31, 2013 and 2012 were $3.1 million and $1.4 million, respectively. These formation and offering costs relate to offering costs for the sale of common units that did not meet the accounting requirements for deferral. Formation costs for the year ended December 31, 2013 include a $1.6 million charge related to a prior period adjustment to our intangible assets valuation dating back to our formation. Contingent consideration loss. Contingent consideration loss was $104.3 million for the year ended December 31, 2012 . The contingent consideration losses relate to the margin support and earn-out agreements entered into with Marathon at the time of the Marathon Acquisition. The 2012 charge of $104.3 million includes the impact of the final valuation adjustment to arrive at the agreed settlement amount which was contingent upon our IPO. There was no contingent consideration loss in the year ended December 31, 2013 as the margin support and earn-out agreements were settled in 2012. Other income, net. Other income, net was $13.8 million for the year ended December 31, 2013 compared to $9.4 million for the year ended December 31, 2012. This change is driven primarily by $4.4 million of miscellaneous income related to settlements from indemnification arrangements. Gains (losses) from derivative activities. For the year ended December 31, 2013, we had gains from derivative activities of $23.5 million versus losses from derivative activities of $271.4 million in the year ended December 31, 2012. We had settlement losses of $18.1 million in the year ended December 31, 2013 related to settled contracts compared to $339.4 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred a gain from the change in fair value of outstanding derivatives of $41.6 million for the year ended December 31, 2013 compared to a gain of $68.0 million during the year ended December 31, 2012. These derivatives were entered into to partially hedge the crack spreads for our refining business. Interest expense, net. Interest expense, net was $26.9 million for the year ended December 31, 2013 and $42.2 million for the year ended December 31, 2012. These interest charges relate primarily to our senior secured notes, commitment fees, interest on the ABL facility and the amortization of deferred financing costs. The decrease from the prior year is primarily due to the reduced principal of, and interest rate on, our new senior secured notes entered into during the fourth quarter of 2012 and the write-off of deferred financing costs in 2012 related to the amendment of our ABL facility. Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2012 of $50.0 million relates to the premiums paid and deferred financing costs written off related to the extinguishment of our senior secured notes due 2017 during the fourth quarter of 2012. Income tax provision. The income tax provision for the year ended December 31, 2013 was $4.2 million compared to $9.8 million for the year ended December 31, 2012. The 2013 income tax provision represents our first full year as a tax paying entity. Prior to August 1, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on August 1, 2012, our retail business became a tax paying entity for federal and state income taxes. The 2012 provision relates primarily to the recognition of an $8.0 million net deferred tax liability on the effective date of the conversion of our retail business to a tax paying entity. Net income. Our net income was $231.1 million for the year ended December 31, 2013 compared to $197.6 million for the year ended December 31, 2012. This improvement of $33.5 million was primarily attributable to a $294.9 million favorable variance in gains/losses from derivative activities, a $15.3 million reduction of interest expense, a $6.5 million improvement in our retail segment operating income, a $5.6 million reduction in our income tax provision and the absence of non-recurring losses recognized in the year ended December 31, 2012, including a $50.0 million loss on early extinguishment of debt and charge of $104.3 million related to our contingent consideration arrangements. These year-on-year improvements more than offset the $451.6 million reduction in operating income from our refining segment in the year ended December 31, 2013. Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011 Revenue. Revenue for the year ended December 31, 2012 was $4,653.9 million compared to $4,280.8 million for the year ended December 31, 2011, an increase of 8.7%. Refining segment revenue increased 10.7% and retail segment revenue decreased 2.5% compared to the year ended December 31, 2011. The refining segment benefited from higher sales volumes and higher average market prices for refined products. Retail revenue decreased primarily due to lower fuel sales volumes caused by reduced market demand and road construction projects impacting our retail stores. Excise taxes included in revenue totaled $300.1 million and $242.9 million for the years ended December 31, 2012 and 2011, respectively. Cost of sales. Cost of sales totaled $3,584.9 million for the year ended December 31, 2012 compared to $3,512.4 million for the year ended December 31, 2011, an increase of 2.1%, due to the impact of increased refining throughput, 57



--------------------------------------------------------------------------------

Table of Contents

partially offset by lower priced crude oil as a result of improved crude differentials in the year ended December 31, 2012. Excise taxes included in cost of sales were $300.1 million and $242.9 million for the years ended December 31, 2012 and 2011, respectively. Direct operating expenses. Direct operating expenses totaled $254.1 million for the year ended December 31, 2012 compared to $257.9 million for the year ended December 31, 2011, a decrease of 1.5%, due primarily to lower operating expenses at our retail stores and reduced utility expenses at the refinery, which were driven by lower natural gas costs, partially offset by costs recognized in the year ended December 31, 2012 related to environmental compliance projects at our refinery's wastewater treatment plant and the impact of increased volumes on variable costs at our refinery. Turnaround and related expenses. Turnaround and related expenses totaled $26.1 million for the year ended December 31, 2012 compared to $22.6 million for the year ended December 31, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 partial turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012. The 2011 partial turnaround was principally to replace catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit. Depreciation and amortization. Depreciation and amortization was $33.2 million for the year ended December 31, 2012 compared to $29.5 million for the year ended December 31, 2011, an increase of 12.5%. This increase was due to depreciation of assets placed in service primarily related to our refinery and our systems implementation project. Selling, general and administrative expenses. Selling, general and administrative expenses were $88.3 million for the year ended December 31, 2012 compared to $88.7 million for the year ended December 31, 2011. This decrease of 0.5% from the prior-year period relates primarily to lower administrative costs as the year ended December 31, 2012 did not include transition services fees to utilize Marathon systems. This reduction is partially offset by higher administrative costs in the first six months of 2012 related to post go-live systems support during the process optimization phase of our standalone systems implementation. Formation and offering costs. Formation and offering costs for the year ended December 31, 2012 and 2011 were $1.4 million and $7.4 million, respectively. The formation and offering costs in the year ended December 31, 2012 relate to offering costs for sales of common units that did not meet the accounting requirements for deferral. All of the costs from the 2011 period are attributable to the Marathon Acquisition. Contingent consideration loss (income). Contingent consideration loss was $104.3 million for the year ended December 31, 2012 compared to contingent consideration income of $55.8 million for the year ended December 31, 2011. The contingent consideration losses relate to the margin support and earn-out agreements entered into with Marathon at the time of the Marathon Acquisition. The 2012 charge of $104.3 million includes the impact of the final valuation adjustment to arrive at the agreed settlement amount which was contingent upon our IPO. The contingent consideration income in the 2011 period relates to changes in the financial performance estimates as of December 31, 2011 for the then remaining period of performance. Other income, net. Other income, net was $9.4 million for the year ended December 31, 2012 compared to $4.5 million for the year ended December 31, 2011. This change is driven primarily by increases in equity income from our investment in MPL. Gains (losses) from derivative activities. For the year ended December 31, 2012, we had losses from derivative activities of $271.4 million versus loses of $352.2 million in the year ended December 31, 2011. We had settlement losses of $339.4 million related to settled contracts for the year ended December 31, 2012 compared to $310.3 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred a gain from the change in fair value of outstanding derivatives of $68.0 million for the year ended December 31, 2012 compared to a loss of $41.9 million during the year ended December 31, 2011. These derivatives were entered into to partially hedge the crack spreads for our refining business. Interest expense, net. Interest expense, net was $42.2 million for the year ended December 31, 2012 and $42.1 million for the year ended December 31, 2011. These interest charges relate primarily to our senior secured notes as well as commitment fees and interest on the ABL facility and the amortization of deferred financing costs. Loss on early extinguishment of debt. Loss on early extinguishment of debt for the year ended December 31, 2012 relates to the premiums paid and deferred financing costs written off related to the extinguishment of our senior secured notes due 2017 during the fourth quarter of 2012. Income tax provision. The income tax provision for the year ended December 31, 2012 was $9.8 million compared to less than $0.1 million for the year ended December 31, 2011. Prior to August 1, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on August 1, 2012 our retail business became a 58



--------------------------------------------------------------------------------

Table of Contents

tax paying entity for federal and state income taxes. The 2012 provision relates primarily to the recognition of an $8.0 million net deferred tax liability on the effective date of the conversion of our retail business to a tax paying entity. Net income. Our net income was $197.6 million for the year ended December 31, 2012 compared to $28.3 million for the year ended December 31, 2011. This improvement of $169.3 million was primarily attributable to a $319.1 million increase in operating income for our refining segment due to improved refining gross margins in the year ended December 31, 2012 and reduced losses from derivative activities of $80.8 million. These improvements were partially offset by a $50.0 million loss on early extinguishment of debt and change of $160.1 million from our contingent consideration arrangement that negatively impacted net income in the year ended December 31, 2012. Segment Financial Data The segment financial data for the refining segment discussed below under "-Refining Segment" include intersegment sales of refined products to the retail segment. Similarly, the segment financial data for the retail segment discussed below under "-Retail Segment" contain intersegment purchases of refined products from the refining segment. For purposes of presenting our consolidated results, such intersegment transactions are eliminated, as shown in the following tables. Year Ended December 31, 2013 (in millions) Refining Retail Other/Elim Consolidated Revenue: Sales and other revenue $ 3,520.2$ 1,459.0 $ - $ 4,979.2 Intersegment sales 1,015.8 - (1,015.8 ) - Segment revenue $ 4,536.0$ 1,459.0$ (1,015.8 )$ 4,979.2 Cost of sales: Cost of sales $ 4,015.8$ 275.8 $ - $ 4,291.6 Intersegment purchases - 1,015.8 (1,015.8 ) - Segment cost of sales $ 4,015.8$ 1,291.6$ (1,015.8 )$ 4,291.6 Year Ended December 31, 2012 (in millions) Refining Retail Other/Elim Consolidated Revenue: Sales and other revenue $ 3,171.5$ 1,482.4 $ - $ 4,653.9 Intersegment sales 1,041.1 - (1,041.1 ) - Segment revenue $ 4,212.6$ 1,482.4$ (1,041.1 )$ 4,653.9 Cost of sales: Cost of sales $ 3,303.7$ 281.2 $ - $ 3,584.9 Intersegment purchases - 1,041.1 (1,041.1 ) - Segment cost of sales $ 3,303.7$ 1,322.3$ (1,041.1 )$ 3,584.9 Year Ended December 31, 2011 (in millions) Refining Retail Other/Elim Consolidated Revenue: Sales and other revenue $ 2,761.0$ 1,519.8 $ - $ 4,280.8 Intersegment sales 1,043.1 - (1,043.1 ) - Segment revenue $ 3,804.1$ 1,519.8$ (1,043.1 )$ 4,280.8 Cost of sales: Cost of sales $ 3,208.5$ 303.9 $ - $ 3,512.4 Intersegment purchases - 1,043.1 (1,043.1 ) - Segment cost of sales $ 3,208.5$ 1,347.0$ (1,043.1 )$ 3,512.4 59



--------------------------------------------------------------------------------

Table of Contents Refining Segment Year Ended December 31, (in millions) 2013 2012 2011 Revenue $ 4,536.0$ 4,212.6$ 3,804.1 Costs, expenses and other: Cost of sales 4,015.8 3,303.7 3,208.5 Direct operating expenses 144.1 136.3 131.3 Turnaround and related expenses 73.3 26.1



22.6

Depreciation and amortization 30.4 25.2



21.5

Selling, general and administrative 29.9 26.7 38.6 Other income, net (13.2 ) (12.7 ) (6.6 ) Operating income $ 255.7$ 707.3$ 388.2 Key Operating Statistics Refining gross product margin (in millions)(3) $ 520.2$ 908.9$ 595.6 Total refinery production (bpd)(1) 75,882 84,530



82,079

Total refinery throughput (bpd) 75,464 83,851



81,150

Refined products sold (bpd)(2) 84,231 89,162



86,038

Per barrel of throughput: Refining gross product margin(3) $ 18.89$ 29.62$ 20.11 Direct operating expenses(4) $ 5.23$ 4.44$ 4.43 Per barrel of refined products sold: Refining gross product margin(3) $ 16.92$ 27.85$ 18.97 Direct operating expenses(4) $ 4.69$ 4.18$ 4.18 Refinery product yields (bpd): Gasoline 34,329 40,825 40,240 Distillate(5) 26,074 27,113 24,841 Asphalt 8,321 11,434 9,888 Other(6) 7,158 5,158 7,110 Total 75,882 84,530 82,079 Refinery throughput (bpd): Crude oil 74,237 81,779 77,452 Other feedstocks(7) 1,227 2,072 3,698 Total 75,464 83,851 81,150 Market Statistics: Crude Oil Average Pricing: West Texas Intermediate ($/barrel) $ 98.39$ 93.81$ 95.11 PADD II / Group 3 Average Pricing: Unleaded 87 Gasoline ($/barrel) $ 114.99$ 119.40$ 117.60 Ultra Low Sulfur Diesel ($/barrel) $ 126.31$ 129.02



$ 126.26

(1) Excludes fuel and coke on catalyst, which are used in our refining process. Also excludes purchased refined products. (2) Includes produced and purchased refined products, including ethanol and biodiesel. (3) Refining gross product margin is calculated by subtracting refining costs of sales from total refining revenues. Refining gross product margin is a



non-GAAP performance measure that we believe is important to investors in

evaluating our refinery performance as a general indication of the amount

above our cost of products that we are able to sell refined products. Each

of the components used in this calculation (revenues and cost of sales)

can be reconciled directly to our statements of operations. Our calculation of refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its



usefulness as a comparative measure. For a reconciliation of refining

gross product margin to the most directly comparable GAAP measure, see

"Results of Operations-Other Non-GAAP Performance Measures." Refining

gross product margin per barrel is a per barrel measurement calculated by

dividing refining gross product margin by the total throughput or total refined products sold for the respective periods presented. 60



--------------------------------------------------------------------------------

Table of Contents

(4) Direct operating expenses per barrel is calculated by dividing direct

operating expenses by the total barrels of throughput or total barrels of

refined products sold for the respective periods presented.

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

(6) Other refinery products include propane, propylene, liquid sulfur, light cycle oil and No. 6 fuel oil, among others. None of these products, by



itself, contributes significantly to overall refinery product yields.

(7) Other feedstocks include gas oil, natural gasoline, normal butane and

isobutane, among others. None of these feedstocks, by itself, contributes

significantly to overall refinery throughput.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012 Refining gross product margin. Refining gross product margin for the year ended December 31, 2013 was $520.2 million compared to $908.9 million for the year ended December 31, 2012, a decrease of 42.8%, primarily due to lower market crack spreads, higher costs for refined product purchases, which were made during our periods of extended turnarounds and maintenance, and lower sales volumes in the year ended December 31, 2013. Refining gross product margin per barrel of throughput was $18.89 for the year ended December 31, 2013 compared to $29.62 for the year ended December 31, 2012, a decrease of $10.73, or 36.2%, which is mostly attributable to lower crack spreads and higher costs for refined product purchases in the year ended December 31, 2013. The lower sales volumes during the year ended December 31, 2013 are related to the major plant turnaround activities, capacity expansion project and unplanned maintenance, which reduced 2013 refinery throughput. Direct operating expenses. Direct operating expenses totaled $144.1 million for the year ended December 31, 2013 compared to $136.3 million for the year ended December 31, 2012, a 5.7% increase. This increase was due primarily to the impact of higher catalyst costs, unplanned maintenance and employee related costs within our refining segment in the year ended December 31, 2013. Turnaround and related expenses. Turnaround and related expenses totaled $73.3 million for the year ended December 31, 2013 compared to $26.1 million for the year ended December 31, 2012. The turnaround costs in the year ended December 31, 2013 include the costs of a planned major plant turnaround which lasted the entire month of April 2013 and a partial turnaround involving our FCC unit which was completed during October 2013. The 2012 turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012. Depreciation and amortization. Depreciation and amortization was $30.4 million for the year ended December 31, 2013 compared to $25.2 million for the year ended December 31, 2012, an increase of 20.6%. This increase was due to increased assets placed in service as a result of our capital expenditures since December 31, 2012, the most significant of which was the expansion project for our crude unit No. 2 which was placed in service in the second quarter of 2013. Selling, general and administrative expenses. Selling, general and administrative expenses were $29.9 million and $26.7 million for the year ended December 31, 2013 and 2012, respectively, an increase of 12.0%. This increase was primarily due to higher risk management costs in the year ended December 31, 2013. Other income, net. Other income, net was $13.2 million for the year ended December 31, 2013 compared to $12.7 million for the year ended December 31, 2012. This increase is driven primarily by $2.6 million of miscellaneous income related to a settlement of an indemnification arrangement partially offset by lower equity income from our investment in MPL, which experienced reduced throughput volumes partially due to our turnaround and capital expansion activities. Operating income. Income from operations was $255.7 million for the year ended December 31, 2013 compared to $707.3 million for the year ended December 31, 2012. This decrease from the prior-year period of $451.6 million is primarily due to less favorable market crack spreads and crude differentials, lower sales volumes and higher turnaround and direct operating expenses during the year ended December 31, 2013. Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011 Refining gross product margin. Refining gross profit margin totaled $908.9 million for the year ended December 31, 2012 compared to $595.6 million for the year ended December 31, 2011, a 52.6% increase. This increase was primarily due to the impact of improved crude differentials versus benchmark crude prices, favorable market crack spreads and increased sales volumes in the year ended December 31, 2012. Refining gross product margin per barrel of throughput was $29.62 for the year ended December 31, 2012 compared to $20.11 for the year ended December 31, 2011, an increase of $9.51, or 47.3%, which is mostly attributable to improved crack spreads and improved crude differentials in the year ended December 31, 2012. Direct operating expenses. Direct operating expenses totaled $136.3 million for the year ended December 31, 2012 compared to $131.3 million for the year ended December 31, 2011, a 3.8% increase. This increase was due primarily to the impact of increased volumes on variable costs at our refinery and costs recognized in 2012 related to environmental compliance 61



--------------------------------------------------------------------------------

Table of Contents

projects at our refinery's wastewater treatment plant, offset by lower utility expenses at the refinery, which resulted from decreases in natural gas prices during the year ended December 31, 2012. Turnaround and related expenses. Turnaround and related expenses totaled $26.1 million for the year ended December 31, 2012 compared to $22.6 million for the year ended December 31, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 turnarounds include the alkylation unit, which was completed according to schedule in mid-May, and the No. 1 reformer unit, which was completed in November 2012. The 2011 turnaround was principally to replace catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit and was completed in April 2011. Depreciation and amortization. Depreciation and amortization was $25.2 million for the year ended December 31, 2012 compared to $21.5 million for the year ended December 31, 2011, an increase of 17.2%. This increase was due to increased assets placed in service as a result of our capital expenditures, the most significant of which was our boiler replacement project which was placed in service in the fourth quarter of 2011. Selling, general and administrative expenses. Selling, general and administrative expenses were $26.7 million and $38.6 million for the year ended December 31, 2012 and 2011, respectively, a decrease of 30.8%. This decrease was due to the termination of our transition services agreement with Marathon in the fourth quarter of 2011, as a result of which we did not incur expenses related to the agreement in the year ended December 31, 2012. Other income, net. Other income, net was $12.7 million for the year ended December 31, 2012 compared to $6.6 million for the year ended December 31, 2011. This increase is driven primarily by an increase in equity income from our investment in MPL, which increased its tariff rates in the third quarter of 2011. Operating income. Income from operations was $707.3 million for the year ended December 31, 2012 compared to $388.2 million for the year ended December 31, 2011. This increase from the prior-year period of $319.1 million is primarily due to favorable crack spreads, crude differentials and higher throughput rates during the 2012 period. 62



--------------------------------------------------------------------------------

Table of Contents Retail Segment Year Ended December 31, (in millions) 2013 2012 2011 Revenue $ 1,459.0$ 1,482.4$ 1,519.8 Costs, expenses and other: Cost of sales 1,291.6 1,322.3 1,347.0 Direct operating expenses 119.2 118.8 126.6 Depreciation and amortization 7.1 7.5 7.2



Selling, general and administrative 25.9 25.1 25.0 Operating income

$ 15.2$ 8.7$ 14.0 Operating data: Retail gross product margin (1) $ 167.4$ 160.1$ 172.8 Company-owned stores: Fuel gallons sold (in millions) 313.2 312.4 324.0 Fuel margin per gallon (2) $ 0.19$ 0.18$ 0.21



Merchandise sales (in millions) $ 341.6$ 340.4$ 340.3 Merchandise margin % (3)

25.9 % 25.4 % 25.4 % Number of stores at period end 164 166 166



Franchisee stores: Fuel gallons sold (in millions)(4) 46.9 45.4 51.5 Royalty income (in millions) $ 2.5$ 2.1$ 1.7 Number of stores at period end

75 70 67 Market Statistics: PADD II gasoline prices ($/gallon) $ 3.52$ 3.61$ 3.53



(1) Retail gross product margin is calculated by subtracting retail costs of

sales from total retail revenues. Retail gross product margin is a

non-GAAP performance measure that we believe is important to investors in

evaluating our retail performance as a general indication of the amount

above our cost of products that we are able to sell retail products. Each

of the components used in this calculation (revenues and cost of sales)

can be reconciled directly to our statements of operations. Our calculation of retail gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its



usefulness as a comparative measure. For a reconciliation of retail gross

product margin to the most directly comparable GAAP measure, see "Results

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



measure, see "Results of Operations-Other Non-GAAP Performance Measures."

(3) Merchandise margin is expressed as a percentage of merchandise sales and is calculated by subtracting costs of merchandise from merchandise sales for company-operated stores, and then dividing by merchandise sales. Merchandise margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our



calculation of merchandise margin may differ from similar calculations of

other companies in our industry, thereby limiting its usefulness as a

comparative measure. Merchandise margin includes all non-fuel sales at our

company-operated stores including items like cigarettes, beer, milk, food,

general merchandise, car wash and other commission-based revenue. For a

reconciliation of merchandise margin to the most directly comparable GAAP

measure, see "Results of Operations-Other Non-GAAP Performance Measures."

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

refinery.

Year Ended December 31, 2013 Compared to the Year Ended December 31, 2012 Retail gross product margin. Retail gross product margin for the year ended December 31, 2013 was $167.4 million compared to $160.1 million for the year ended December 31, 2012, an increase of 4.6%. This increase was primarily due to higher fuel margin at our company operated stores which increased $4.1 million from the prior year. For company-operated stores, fuel margin per gallon was $0.19 for the year ended December 31, 2013 compared to $0.18 per gallon for the year ended 63



--------------------------------------------------------------------------------

Table of Contents

December 31, 2012. Additionally, fuel gallons sold in our company operated stores increased by 0.3% in the year ended December 31, 2013. Direct operating expenses. Direct operating expenses totaled $119.2 million for the year ended December 31, 2013 compared to $118.8 million for the year ended December 31, 2012, an increase of 0.3% from the 2012 period. Depreciation and amortization. Depreciation and amortization was $7.1 million for the year ended December 31, 2013 compared to $7.5 million for the year ended December 31, 2012, a decrease of $0.4 million. Selling, general and administrative expenses. Selling, general and administrative expenses were $25.9 million and $25.1 million for the year ended December 31, 2013 and 2012, respectively. The slight increase primarily relates to higher information technology costs in the year ended December 31, 2013. Operating income. Operating income was $15.2 million for the year ended December 31, 2013 compared to $8.7 million for the year ended December 31, 2012, an increase of $6.5 million. The increase is primarily attributable to higher fuel margins per gallon and improved gross profit margins on merchandise sales during the year ended December 31, 2013. Year Ended December 31, 2012 Compared to the Year Ended December 31, 2011 Retail gross product margin. Retail gross product margin for the year ended December 31, 2012 was $160.1 million compared to $172.8 million for the year ended December 31, 2011, a decrease of 7.3%. This decrease was primarily due to lower fuel margin at our company operated stores which decreased $10.4 million from the prior year. For company-operated stores, fuel margin per gallon was $0.18 for the year ended December 31, 2012 compared to $0.21 per gallon for the year ended December 31, 2011. Additionally, fuel gallons sold in our company operated stores decreased by 3.6% in the year ended December 31, 2012 compared to the year ended December 31, 2011. Direct operating expenses. Direct operating expenses totaled $118.8 million for the year ended December 31, 2012 compared to $126.6 million for the year ended December 31, 2011, a decrease of 6.2% from the 2011 period due to reductions in convenience store operating costs as a result of cost reduction efforts, primarily related to store personnel and contractor costs. Depreciation and amortization. Depreciation and amortization was $7.5 million for the year ended December 31, 2012 compared to $7.2 million for the year ended December 31, 2011, an increase of 4.2%. The increase is due to increased depreciation from capital expenditures at our stores and for our new systems infrastructure, offset by a change in treatment for certain sale leaseback assets. During 2011, our continuing involvement ended for a subset of our retail stores which did not meet the criteria for sale leaseback treatment at the time of the Marathon Acquisition. As such, the related fair value of the assets for these stores was removed from the consolidated balance sheet and was no longer depreciated. Selling, general and administrative expenses. Selling, general and administrative expenses were $25.1 million and $25.0 million for the year ended December 31, 2012 and 2011, respectively. The slight increase relates to higher professional service fees and personnel costs, offset by lower back office costs in 2012 period. In the year ended December 31, 2011, our back office costs were higher as we developed our stand-alone infrastructure while continuing to pay transition services fees to utilize the Speedway LLC back office infrastructure of Marathon. Operating income. Operating income was $8.7 million for the year ended December 31, 2012 compared to $14.0 million for the year ended December 31, 2011, a reduction of $5.3 million. The reduction is primarily attributable to lower fuel margins per gallon and lower fuel volumes partially offset by higher merchandise margin and lower operating expenses during the year ended December 31, 2012. Adjusted EBITDA Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with the board of directors of our general partner, creditors, analysts and investors concerning our financial performance. We also believe Adjusted EBITDA may be used by some investors to assess the ability of our assets to generate sufficient cash flow to make distributions to our unitholders. The revolving credit facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below. Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior secured notes and the revolving credit facility. Adjusted EBITDA should not be considered as an alternative to operating earnings or net earnings as measures of operating performance. In addition, Adjusted EBITDA is not presented as and should not be considered an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before turnaround 64



--------------------------------------------------------------------------------

Table of Contents

and related expenses, equity-based compensation expense, gains (losses) from derivative activities, contingent consideration, formation and offering costs, bargain purchase gain and adjustments to reflect proportionate depreciation expense from MPL operations. Other companies, including companies in our industry, may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA: does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;



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

needs;

does not reflect our interest expense, or the cash requirements necessary

to service interest or principal payments, on our debt;

does not reflect the equity income in our MPL investment, but includes 17%

of the calculated EBITDA of MPL;

does not reflect gains and losses from derivative activities, which may

have a substantial impact on our cash flow;

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

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

The following tables reconcile net income (loss) as reflected in the results of operations tables and segment footnote disclosures to Adjusted EBITDA for the periods presented: Year Ended December 31, 2013 Refining Retail Other Total (in millions) Net income (loss) $ 255.7$ 15.2$ (39.8 )$ 231.1 Adjustments: Interest expense - - 26.9 26.9 Income tax provision - - 4.2 4.2 Depreciation and amortization 30.4 7.1 0.6 38.1 EBITDA subtotal 286.1 22.3 (8.1 ) 300.3 MPL proportionate depreciation expense 2.9 - - 2.9 Turnaround and related expenses 73.3 - - 73.3 Equity-based compensation expense - - 7.1 7.1 Formation and offering costs - - 3.1 3.1 Gains from derivative activities - - (23.5 ) (23.5 ) Adjusted EBITDA $ 362.3$ 22.3$ (21.4 )$ 363.2 Year Ended December 31, 2012 Refining Retail Other Total (in millions) Net income (loss) $ 707.3$ 8.7$ (518.4 )$ 197.6 Adjustments: Interest expense - - 42.2 42.2 Income tax provision - - 9.8 9.8 Depreciation and amortization 25.2 7.5 0.5 33.2 EBITDA subtotal 732.5 16.2 (465.9 ) 282.8 MPL proportionate depreciation expense 2.8 - - 2.8 Turnaround and related expenses 26.1 - - 26.1 Equity-based compensation expense - - 0.9 0.9 Contingent consideration loss - - 104.3 104.3 Loss on early extinguishment of debt - - 50.0 50.0 Formation and offering costs - - 1.4 1.4 Losses from derivative activities - - 271.4 271.4 Adjusted EBITDA $ 761.4$ 16.2$ (37.9 )$ 739.7 65



--------------------------------------------------------------------------------

Table of Contents Year Ended December 31, 2011 Refining Retail Other Total (in millions) Net income (loss) $ 388.2$ 14.0$ (373.9 )$ 28.3 Adjustments: Interest expense - - 42.1 42.1 Depreciation and amortization 21.5 7.2 0.8



29.5

EBITDA subtotal 409.7 21.2 (331.0 ) 99.9 MPL proportionate depreciation expense 2.8 - -



2.8

Turnaround and related expenses 22.6 - -



22.6

Equity-based compensation expense - - 1.6



1.6

Contingent consideration income - - (55.8 ) (55.8 ) Formation and offering costs - - 7.4



7.4

Losses from derivative activities - - 352.2 352.2 Adjusted EBITDA $ 435.1$ 21.2$ (25.6 )$ 430.7 Other Non-GAAP Performance Measures Refining gross product margin per barrel, retail fuel margin and merchandise margin are non-GAAP performance measures that we believe are important to investors in analyzing our segment performance. Refining gross product margin per barrel is a financial measurement calculated by subtracting refining costs of sales from total refining revenues and dividing the difference by the total throughput or total refined products sold for the respective periods presented. Refining gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refining performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in these calculations (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table shows the reconciliation of refining gross product margin to refining revenue and refining cost of sales for the periods indicated. A reconciliation of refining revenue and refining cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in "-Segment Financial Data." Year Ended December 31, (in millions) 2013 2012 2011 Refining revenue $ 4,536.0$ 4,212.6$ 3,804.1 Refining cost of sales 4,015.8 3,303.7 3,208.5 Refining gross product margin $ 520.2$ 908.9$ 595.6 Retail fuel margin and merchandise margin are non-GAAP measures that we believe are important to investors in evaluating our retail segment's operating results as these measures provide an indication of our performance on significant product categories within the segment. Our calculation of fuel margin and merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures. 66



--------------------------------------------------------------------------------

Table of Contents

The following table shows the reconciliations of fuel margin and merchandise margin to retail revenue and retail cost of sales for the periods indicated. A reconciliation of retail revenue and retail cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in "-Segment Financial Data." Year Ended December 31, (in millions) 2013 2012 2011 Retail revenue: Fuel revenue $ 1,089.5$ 1,114.5$ 1,149.6 Merchandise revenue 341.6 340.4 340.3 Other revenue 46.7 45.9 49.2 Intercompany eliminations (18.8 ) (18.4 ) (19.3 ) Retail revenue 1,459.0 1,482.4 1,519.8 Retail cost of sales: Fuel cost of sales 1,029.3 1,058.4 1,083.1 Merchandise cost of sales 253.2 254.1 254.0 Other cost of sales 27.9 28.2 29.2 Intercompany eliminations (18.8 ) (18.4 ) (19.3 ) Retail cost of sales 1,291.6 1,322.3 1,347.0 Retail gross product margin: Fuel margin 60.2 56.1 66.5 Merchandise margin 88.4 86.3 86.3 Other margin 18.8 17.7 20.0 Intercompany eliminations - - -



Retail gross product margin $ 167.4$ 160.1$ 172.8

Liquidity and Capital Resources Our primary sources of liquidity have traditionally been cash generated from our operating activities and availability under our revolving credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing and selling sufficient quantities of refined products and merchandise at margins sufficient to cover fixed and variable expenses. We may make strategic investments with the objective of increasing cash available for distribution to our unitholders. These strategic investments would be financed via debt or equity issuances. Our ability to make these investments in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating. For discussions on our refinery gross product margin per barrel and retail fuel margin per gallon and merchandise margin for company-operated stores, see "Results of Operations-Refining Segment" and "Results of Operations-Retail Segment," and for discussions on factors that affect our results of operations, see "Major Influences on Results of Operations." For more information on our revolving credit facility, see "Description of Our Indebtedness-Senior Secured Asset-Based Revolving Credit Facility." On July 31, 2012, we closed our IPO of 18,687,500 common units. We used the net proceeds from our IPO of approximately $245 million and cash on hand of approximately $56 million to: (i) distribute approximately $124 million to NT Holdings, of which approximately $92 million was used to redeem Marathon's existing preferred interest in NT Holdings and $32 million was distributed to ACON Refining, TPG Refining and entities in which our President and Chief Executive Officer held an ownership interest, (ii) pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., related to deferred payment obligations from the early extinguishment of derivatives, (iii) pay $40 million to Marathon, which represents the cash component of a settlement agreement Northern Tier Energy LLC entered into with Marathon in satisfaction of a contingent consideration arrangement that was part of the Marathon Acquisition, (iv) redeem $29 million of the 2017 Secured Notes at a redemption price of 103% of the principal amount thereof, plus accrued interest, for an estimated $31 million, and (v) pay other offering costs of approximately $15 million. 67



--------------------------------------------------------------------------------

Table of Contents

On November 8, 2012, we completed a private placement of the 2020 Secured Notes. We used the net proceeds of the offering and cash on hand of $31 million (i) to repurchase our outstanding 2017 Secured Notes that were tendered pursuant to our previously announced tender offer and (ii) to satisfy and discharge any remaining 2017 Secured Notes outstanding (which notes were called for redemption after the closing of the tender offer) and to pay related fees and expenses. The 2020 Indenture has substantially the same covenants as the 2017 Indenture, except that under the 2020 Indenture we may distribute all of our available cash (as defined in the 2020 Indenture) to our unitholders if we maintain a fixed charge coverage ratio of 1.75 to 1. Based on current and anticipated levels of operations and conditions in our industry and markets, we believe that cash on hand, together with cash flows from operations and borrowings available to us under our revolving credit facility, will be adequate to meet our ordinary course working capital, capital expenditures, debt service and other cash requirements for at least the next twelve months. However, we may increase future liquidity via the sale of additional common units. We may use a variety of derivative instruments to enhance the stability of our cash flows. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Securing Act of 2007, the EPA has issued RFS implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to RFS. Under the RFS, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. The obligated volume increases annually over time until 2022. Our refinery currently does not generate enough RINs to meet the current year requirement for some fuel categories, so we must purchase RINs on the open market for these categories. We project that our 2014 RINs requirement will exceed the amount of RINs we obtain through our normal blending operations by between 15 and 20 million RINs. This shortfall, net of RIN credits on hand as of December 31, 2013 will require us to purchase between 10 and 15 million RINs on the open market in 2014. The expense related to these RINs requirements are recognized throughout the year as incurred and are included within cost of sales in our consolidated statements of operations. Cash Flows The following table sets forth our cash flows for the periods indicated: Year Ended December 31, (in millions) 2013 2012



2011

Net cash provided by operating activities $ 229.8$ 308.5$ 209.3 Net cash used in investing activities (95.5 ) (28.7 ) (156.3 ) Net cash used in financing activities (321.4 ) (130.4 ) (2.3 ) Net increase (decrease) in cash and cash equivalents (187.1 ) 149.4



50.7

Cash and cash equivalents at beginning of period 272.9 123.5

72.8

Cash and cash equivalents at end of period $ 85.8$ 272.9



$ 123.5

Net Cash Provided By Operating Activities. Net cash provided by operating activities for the year ended December 31, 2013 was $229.8 million. The most significant providers of cash were our net income ($231.1 million) adjusted for non-cash items, such as depreciation and amortization expense ($38.1 million), gain from the change in fair value of outstanding derivatives ($41.6 million) and equity-based compensation expense ($7.1 million). Additionally, cash was minimally impacted by net working capital changes. Net cash provided by operating activities for the year ended December 31, 2012 was $308.5 million. The most significant providers of cash were our net income ($197.6 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($33.2 million), deferred income taxes ($9.8 million), loss on extinguishment of debt ($50.0 million), gain from the change in fair value of outstanding derivatives ($68.0 million) and contingent consideration loss ($104.3 million). Additionally, cash was negatively impacted by a net working capital increase of $26.8 million. Net cash provided by operating activities for the year ended December 31, 2011 was $209.3 million. The most significant providers of cash were our net income ($28.3 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($29.5 million), loss gain from the change in fair value of outstanding derivatives ($41.9 million) and non-cash contingent consideration income ($55.8 million). Additionally, cash was provided by decreases in accounts receivable ($18.3 million) and increases in accounts payable and accrued expenses ($146.4 million) mainly driven by the expansion of our trade credit. Net Cash Used In Investing Activities. Net cash used in investing activities for the year ended December 31, 2013 was $95.5 million, relating primarily to capital expenditures of $96.6 million. Capital spending for the year ended December 31, 68



--------------------------------------------------------------------------------

Table of Contents

2013 primarily included the capacity expansion project on our crude unit No. 2 and our waste water treatment plant construction at our refinery and safety related enhancements and facility improvements at the refinery and retail store locations. Net cash used in investing activities for the year ended December 31, 2012 was $28.7 million, relating primarily to capital expenditures of $30.9 million. Capital spending for the year ended December 31, 2012 primarily included safety related enhancements and facility improvements at the refinery and retail store locations. Net cash used in investing activities for the year ended December 31, 2011 was $156.3 million, relating primarily to capital expenditures ($45.9 million) and cash paid to Marathon Oil with respect to a payable related to the Marathon Acquisition ($112.8 million). Capital spending for the year ended December 31, 2011 primarily included a multi-year boiler replacement project at the refinery, safety related enhancements and facility improvements at the refinery and the implementation of our new information and accounting systems. Net Cash Used In Financing Activities. Net cash used in financing activities for the year ended December 31, 2013 of $321.4 million was primarily related to our quarterly distributions to unitholders. Net cash used in financing activities for the year ended December 31, 2012 was $130.4 million. The net proceeds from our IPO of $230.4 million were the primary source of cash from financing activities. Out of those proceeds, we repaid $29.0 million of the 2017 Secured Notes and distributed $124.2 million to NT Holdings. Additionally, during the second quarter of 2012 we made an equity distribution in the amount of $40 million to NT Holdings. During the fourth quarter of 2012 we refinanced our senior secured notes, retiring our 2017 Secured Notes for their face value of $290 million plus early extinguishment premiums of $39.5 million and we received gross proceeds of $275 million related to the our 2020 Secured Notes. These proceeds were offset by related offering costs of $6.1 million. Additionally, in the fourth quarter of 2012, we issued our initial distribution to unitholders of $136.0 million. Net cash used in financing activities was $2.3 million for the year ended December 31, 2011, representing tax distributions to NT Holdings. Working Capital Working capital at December 31, 2013 was $109.5 million, consisting of $525.0 million in total current assets and $415.5 million in total current liabilities. The reduction in working capital from the prior year primarily relates to a decrease in cash as a result of our distributions to unitholders of $321.4 million and our capital expenditures of $96.6 million offset by our cash provided by operations of $229.8 million for the year ended December 31, 2013. Working capital at December 31, 2012 was $248.0 million, consisting of $599.5 million in total current assets and $351.5 million in total current liabilities. Working capital at December 31, 2012 was impacted by the short-term liability for the fair value of our outstanding derivatives of $43.7 million related to our crack spread risk management program. The offsetting benefits related to this liability should be realized over future periods as improved crack spread margins are realized. At the closing of the Marathon Acquisition, we entered into a crude oil and supply and logistics agreement with JPM CCC pursuant to which JPM CCC assists us in the purchase of the crude oil requirements of our refinery and provides transportation and other logistical services for delivery of the crude oil to our storage tanks at Cottage Grove, Minnesota, which are approximately two miles from our refinery. In March 2012, we amended and restated the crude oil supply and logistics agreement with JPM CCC. Upon delivery of the crude oil to us we pay JPM CCC the price of the crude oil plus certain agreed fees and expenses. We believe this crude oil supply and logistics agreement significantly reduces our crude inventories and allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished product output is sold. Our Distribution Policy We expect within 60 days after the end of each quarter to make distributions to unitholders of record as of the applicable record date. The board of directors of our general partner adopted a policy pursuant to which distributions for each quarter will equal the amount of available cash we generate in such quarter. Distributions on our units will be in cash. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. Distributions will be based on the amount of available cash generated in such quarter. Available cash for each quarter will generally equal our cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for turnaround and related expenses. Such a decision by the board of directors may have an adverse impact on the available cash in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized. Actual turnaround and related expenses will be funded with cash reserves or borrowings under our revolving credit facility. We do not intend to maintain excess distribution coverage or reserve cash for the purpose of maintaining stability or growth in our quarterly distribution. We 69



--------------------------------------------------------------------------------

Table of Contents

do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity. Because our policy will be to distribute an amount equal to the available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. The amount of quarterly distributions, if any, will vary based on operating cash flow during such quarter. As a result, quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements, (iv) capital expenditures and (v) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of the quarterly distributions may be significant. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change the foregoing distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis. The following table details the quarterly distributions paid to common unitholders since our IPO in July 2013 (in millions, except per unit amounts): Common Units



Distribution per Total Distribution

Date Declared Date Paid (in millions) common unit (in millions) 2012 Distributions: November 12, 2012 November 29, 2012 91.9 $ 1.48 $ 136.0 Total distributions paid during 2012 $ 1.48 136.0 2013 Distributions: February 11, 2013 February 28, 2013 91.9 $ 1.27 116.7 May 13, 2013 May 30, 2013 92.2 $ 1.23 113.4 August 13, 2013 August 29, 2013 92.2 $ 0.68 62.7 November 11, 2013 November 27, 2013 92.2 $ 0.31 28.6 Total distributions paid during 2013 $ 3.49 321.4 2014 Distributions: February 7, 2014 February 28, 2014 92.3 $ 0.41 37.8 Distributions declared during 2014 $ 0.41 37.8 Total distributions declared since our IPO $ 5.38 $ 495.2 Notwithstanding our distribution policy, certain provisions of the indenture governing the 2020 Secured Notes and our revolving credit facility may restrict the ability of Northern Tier Energy LLC, our operating subsidiary, to distribute cash to us. See "-Description of Our Indebtedness." Capital Spending Total capital spend was $96.6 million for the year ended December 31, 2013. Non-discretionary capital spending was $42.2 million for the year ended December 31, 2013 which included $13.6 million towards the upgrade of our waste water treatment facility. The remaining non-discretionary capital spending primarily related to the replacement or major maintenance of equipment at the refinery, as well as to make safety enhancements. Discretionary spending was $54.4 million for the year ended December 31, 2013. Included in this discretionary spending was approximately $40 million for a project which resulted in a 10% capacity expansion at our refinery that, along with other discretionary projects, improved our distillate recovery by 2-3%. We estimate that these discretionary projects will have an average payback of less than eighteen months. Capital spending was $30.9 million for the year ended December 31, 2012, which primarily included spending to replace or maintain equipment at the refinery, as well as to make safety enhancements. We currently expect to spend approximately $30 - $40 million on non-discretionary capital projects in 2014, including approximately $10 - 15 million to complete the upgrade of our waste water treatment facility. The remaining non-discretionary projects relate to the ongoing replacement spending also referred to as maintenance capital. 70



--------------------------------------------------------------------------------

Table of Contents

Contractual Obligations and Commitments We have the following contractual obligations and commitments as of December 31, 2013 (in millions): Less than 1-3 3-5 More than 1 year years years 5 years Total Long-term debt(1) $ 21.1$ 42.2$ 40.0$ 311.7$ 415.0 Lease obligations(2) 23.9 46.1 43.7 145.6 259.3 Capital expenditures(3) 16.1 - - - 16.1 Environmental remediation costs 0.7 1.1 0.7 6.4 8.9 (1) Long-term debt represents (i) the repayment of the $275 million of the 2020 Secured Notes at their 2020 maturity date, (ii) cash interest payments for the 2020 Secured Notes through the 2020 maturity date and



(iii) commitment fees of 0.5% on an assumed $300 million undrawn balance

under our revolving credit facility with a maturity date of 2017. (2) Lease obligations represent payments for a variety of facilities and equipment under lease, including existing real property leases and



payments pursuant to our lease arrangement with Realty Income, office

equipment and vehicles, including trucks to transport crude oil, as well as rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars.



(3) Capital expenditures represent our contractual commitments to acquire

property, plant and equipment.

Off-Balance Sheet Arrangements In connection with the closing of the Marathon Acquisition, we entered into a lease arrangement with Realty Income (the "Realty Income Lease"), pursuant to which we leased 135 SuperAmerica convenience stores and one support facility over a 15-year initial term at an aggregate annual rent fixed for five years at an annual rate of $20.3 million, with consumer price index-based rent increases thereafter. As of December 31, 2013, we have 133 SuperAmerica convenience stores and the one support facility remaining under the Realty Income Lease. Description of Our Indebtedness Senior Secured Asset-Based Revolving Credit Facility At the closing of the Marathon Acquisition, we and certain of our subsidiaries (the "ABL Borrowers") entered into an asset-backed lending facility with JP Morgan Chase Bank, N.A. as administrative agent and collateral agent (the "ABL Agent"), Bank of America, N.A., as syndication agent, and lenders party thereto. On July 17, 2012, we entered into an amendment of this asset-backed lending facility. Our revolving credit facility provides for revolving credit financing through July 17, 2017 in an aggregate principal amount of up to $300 million (of which $150 million may be utilized for the issuance of letters of credit and up to $30 million may be short-term borrowings upon same-day notice, referred to as swingline loans) and may be increased up to a maximum aggregate principal amount of $450 million, subject to borrowing base availability and lender approval. Availability under our revolving credit facility at any time will be the lesser of (a) the aggregate commitments under our revolving credit facility and (b) the borrowing base, less any outstanding borrowings and letters of credit. The borrowing base is calculated based on a percentage of eligible accounts receivable, petroleum inventory and other assets. Borrowings under our revolving credit facility bear interest, at our option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and 1.50%) or (b) a LIBOR rate plus an applicable margin (ranging between 2.00% and 2.50%). The alternative base rate is the greater of (a) the prime rate, (b) the Federal Funds Effective Rate plus 50 basis points, or (c) the one-month LIBOR rate plus 100 basis points and a spread of up to 150 basis points based upon percentage utilization of this facility. In addition to paying interest on outstanding borrowings, we are also required to pay an annual commitment fee ranging from 0.375% to 0.500% and letter of credit fees. As of December 31, 2013, the availability under our revolving credit facility was $134.6 million. This availability is net of $34.2 million in outstanding letters of credit as of December 31, 2013. We had no borrowings under our revolving credit facility at December 31, 2013. In order to borrow under our revolving credit facility, if the amount available under our revolving credit facility is less than the greater of (i) 12.5% of the lesser of (x) the $300 million commitment amount and (y) the then-applicable borrowing base and (ii) $22.5 million, the ABL Borrowers must comply with a minimum fixed charge coverage ratio of at least 1.0 to 1.0. As of December 31, 2013, the most recent determination date, the fixed charge coverage ratio was 6.5 to 1.0. Our revolving credit facility contains customary negative covenants that restrict the ABL Borrowers ability to, among other things, incur certain additional debt, grant certain liens, enter into certain guarantees, enter into certain mergers, make certain loans and investments, dispose of certain assets, prepay certain debt, make cash distributions, modify certain material agreements or organizational documents, or change the business we conduct. 71



--------------------------------------------------------------------------------

Table of Contents

Our revolving credit facility also contains certain customary representations and warranties, affirmative covenants and events of default. Events of default include, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults and cross-acceleration to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, actual or asserted failure of any guaranty or security document supporting our revolving credit facility to be in full force and effect, and change of control. If such an event of default occurs, the lenders under our revolving credit facility would be entitled to take various actions, including the acceleration of amounts due under our revolving credit facility and all actions permitted to be taken by a secured creditor. 2020 Secured Notes On November 8, 2012, Northern Tier Energy LLC, our wholly-owned subsidiary ("NTE LLC"), and Northern Tier Finance Corporation (together with NTE LLC, the "Notes Issuers"), privately placed $275 million in aggregate principal amount of 7.125% senior secured notes due 2020. The proceeds from the offering of the 2020 Secured Notes and cash on hand of $31 million were used to repurchase the 2017 Secured Notes tendered pursuant to the tender offer for the 2017 Secured Notes and to satisfy and discharge any remaining 2017 Secured Notes outstanding after completion of the tender offer and to pay related fees and expenses. Deutsche Bank Trust Company Americas acts as trustee for the 2020 Secured Notes. Effective in October 2013, the 2020 Secured Notes were registered with the SEC and became publicly traded debt. The Notes Issuers' obligations under the 2020 Secured Notes are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis by Northern Tier Energy LP and on a senior secured basis by (i) all of NTE LLC's restricted subsidiaries that borrow, or guarantee obligations, under our senior secured asset-backed revolving credit facility or any other indebtedness of NTE LLC or another subsidiary of NTE LLC that guarantees the 2020 Secured Notes and (ii) all other material wholly-owned domestic subsidiaries of NTE LLC. The 2020 Secured Notes and the subsidiary note guarantees are secured, subject to permitted liens, on a pari passu basis with certain hedging agreements by (a) a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of the Notes Issuers and each of the subsidiary guarantors in which liens have been granted in relation to the 2020 Secured Notes (other than those items described in clause (b) below) (the "Notes Priority Collateral"), and (b) a second-priority security interest in the (i) inventory, (ii) accounts receivable, (iii) investment property, general intangibles, deposit accounts, cash and cash equivalents and other assets to the extent related to the assets described in clauses (i) and (ii), (iv) books and records relating to the foregoing and (v) all proceeds of and supporting obligations, including letter of credit rights, with respect to the foregoing, and all collateral security and guarantees of any person with respect to the foregoing (the "ABL Priority Collateral"), in each case owned or hereinafter acquired by the Notes Issuers and each of the subsidiary guarantors. The 2020 Secured Notes are the Notes Issuers' general senior secured obligations that are effectively subordinated to the Notes Issuers' obligations under our revolving credit facility to the extent of the value of the ABL Priority Collateral that secures such obligations on a first-priority basis, effectively senior to the Notes Issuers' obligations under our revolving credit facility to the extent of the Notes Priority Collateral that secures the 2020 Secured Notes on a first-priority basis, structurally subordinated to any existing and future indebtedness and claims of holders of preferred stock and other liabilities of the Notes Issuers' direct or indirect subsidiaries that are not guarantors of the 2020 Secured Notes (other than Northern Tier Finance Corporation), and pari passu in right of payment with all of the Notes Issuers' existing and future indebtedness that is not subordinated. The 2020 Secured Notes rank effectively senior to all of the Notes Issuers' existing and future unsecured indebtedness to the extent of the value of the collateral, effectively equal to the obligations under certain hedge agreements and any future indebtedness which is permitted to be secured on a pari passu basis with the 2020 Secured Notes to the extent of the value of the collateral and senior in right of payment to any future subordinated indebtedness of the Notes Issuers. At any time prior to November 15, 2015, the Notes Issuers may, on any one or more occasions, upon not less than 30 nor more than 60 days' notice, redeem up to 35% of the aggregate principal amount of 2020 Secured Notes issued under the indenture (together with any additional notes) at a redemption price of 107.125% of the principal amount thereof, plus accrued and unpaid interest thereon to, but excluding, the applicable redemption date, with all or a portion of the net cash proceeds of one or more qualified equity offerings; provided that (1) at least 65% of the aggregate principal amount of the 2020 Secured Notes issued under the indenture (including any additional notes) remains outstanding immediately after the occurrence of such redemption (excluding notes held by the Notes Issuers and their subsidiaries); and (2) the redemption must occur within 90 days of the date of the closing of such qualified equity offering. At any time prior to November 15, 2015, the Notes Issuers may, on any one or more occasions, redeem all or a part of the 2020 Secured Notes, upon not less than 30 nor more than 60 days' notice, at a redemption price equal to 100% of the principal amount of the 2020 Secured Notes redeemed, plus an applicable make-whole premium as of, and accrued and unpaid interest to, but excluding, the date of redemption, subject to the rights of holders of the 2020 Secured Notes on the relevant record date to receive interest due on the relevant interest payment date. Except pursuant to the preceding paragraphs, the 2020 Secured Notes will not be redeemable at the Notes Issuers' option prior to November 15, 2015. 72



--------------------------------------------------------------------------------

Table of Contents

On or after November 15, 2015, the Notes Issuers may redeem all or a part of the 2020 Secured Notes, upon not less than 30 nor more than 60 days' notice, at the redemption prices (expressed as percentages of principal amount) set forth below plus accrued and unpaid interest thereon to, but excluding, the applicable redemption date, if redeemed during the 12-month period beginning on November 15 of the years indicated below, subject to the rights of holders of the 2020 Secured Notes on the relevant record date to receive interest on the relevant interest payment date: Year Percentage 2015 105.344 % 2016 103.563 % 2017 101.781 % 2018 and thereafter 100.000 % The indenture governing the 2020 Secured Notes contains certain covenants that, among other things, limit the ability of NTE LLC and NTE LLC's restricted subsidiaries to, subject to certain exceptions: incur, assume or guarantee additional debt or issue redeemable stock and



preferred stock if our fixed charge coverage ratio, after giving effect to

the issuance, assumption or guarantee of such additional debt or the

issuance of such redeemable stock or preferred stock, for the most

recently ended four full fiscal quarters would have been less than 2.0 to

1.0;

declare or pay dividends on or make any other payment or distribution on

account of our or any of our restricted subsidiaries' equity interests;

make any payment with respect to, or purchase, repurchase, redeem, defease

or otherwise acquire or retire for value our equity interests;

purchase, repurchase, redeem, defease or otherwise acquire or retire for

value or give any irrevocable notice of redemption with respect to certain

subordinated debt;

make certain investments, loans and advances;

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

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

create, incur, assume or otherwise cause or suffer to exist or become

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



suffer a change of control;

enter into new lines of business; and

enter into agreements that restrict distributions from certain subsidiaries.

The 2020 Secured Notes also provide for events of default which, if any of them occurs, would permit or require the principal of and accrued interest on such notes to become or to be declared to be due and payable. Under the terms of the 2020 Secured Notes, the sale of NT InterHoldCo LLC to Western Refining during the fourth quarter of 2013 represented a change in control. This change in control required us to extend a thirty day offer to our noteholders to repurchase any or all of the notes they held at a price equivalent to 101% of the aggregate principal amount. Upon expiration of the thirty day term, none of our noteholders had accepted the repurchase offer. Inflation Inflation in the United States has been relatively low in recent years and did not have a material impact on our results of operations for the years ended December 31, 2013, 2012 and 2011. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy. Critical Accounting Policies and Estimates The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain 73



--------------------------------------------------------------------------------

Table of Contents

accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 to our audited financial statements for a discussion of additional accounting policies and estimates made by management. Investment in MPL and MPL Investments Our 17% common interest in MPL is accounted for using the equity method of accounting and carried at our share of net assets in accordance with the Financial Accounting Standards Board, or the FASB, Accounting Standards Codification paragraph 323-30-35-3. Income from equity method investment represents our proportionate share of net earnings attributed to common owners generated by MPL. The equity method investment is assessed for impairment whenever changes in the facts and circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net earnings. The investment in MPL Investments, over which we do not have significant influence and whose stock does not have a readily determinable fair value, is carried at cost. MPL Investments owns all of the preferred membership units of MPL. Dividends received from MPL Investments are recorded as return of capital from cost method investment and in other income. Intangible Assets Intangible assets primarily include a retail marketing trade name and franchise agreements. The marketing trade name and franchise agreements have indefinite lives and therefore are not amortized, but rather are tested for impairment annually and when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. If the estimated fair value is less than the carrying amount of the asset, an impairment loss is recognized based on the estimated fair value of the asset. Significant assumptions in determining the estimated fair value of the indefinite lived intangibles include projected store growth, estimated market royalty rates, market growth rates and the estimated discount rate. Environmental Costs Environmental expenditures are capitalized if the costs mitigate or prevent future contamination or if the costs improve environmental safety or efficiency of the existing assets. We provide for remediation costs and penalties when the responsibility to remediate is probable and the amount of associated costs can be reasonably estimated. The timing of remediation accruals coincides with completion of a feasibility study or the commitment to a formal plan of action. Remediation liabilities are accrued based on estimates of known environmental exposure and are discounted when the estimated amounts are reasonably fixed and determinable. If recoveries of remediation costs from third parties are probable, a receivable is recorded and is discounted when the estimated amount is reasonably fixed and determinable. Defined Benefit Plans Our pension plan and a retiree medical plan are considered defined benefit plans. Expenses and liabilities related to these plans are determined on an actuarial basis and are affected by the market value of plan assets, estimates of the expected return on plan assets, and assumed discount rates and demographic data. Pension and retiree medical plan expenses and liabilities are determined based on actuarial valuations. Inherent in these valuations are key assumptions including discount rates, future compensation increases, expected return on plan assets, health care cost trends, and demographic data. Changes in our actuarial assumptions are primarily influenced by factors outside of our control and could have a significant effect on our pension and retiree medical liabilities and costs. Asset Retirement Obligations The fair value of asset retirement obligations is recognized in the period in which the obligations are incurred if a reasonable estimate of fair value can be made. A conditional asset retirement obligation for removal and disposal of fire-retardant material from certain refining assets has been recognized. The amounts recorded for this obligation is based on the most probable current cost projections. Asset retirement obligations have not been recognized for the removal of materials and equipment from or the closure of certain refinery, pipeline, terminal and retail marketing assets because the fair value cannot be reasonably estimated since the settlement dates of the obligations are indeterminable. 74



--------------------------------------------------------------------------------

Table of Contents

Current inflation rates and credit-adjusted-risk-free interest rates are used to estimate the fair value of asset retirement obligations. Depreciation of capitalized asset retirement costs and accretion of asset retirement obligations are recorded over time. Depreciation is determined on a straight-line basis, while accretion escalates over the lives of the assets. Derivative Financial Instruments We are exposed to earnings and cash flow volatility based on the timing and change in refined product prices versus crude oil prices. To manage these risks, we may use derivative instruments associated with the purchase or sale of crude oil and refined products. Crack spread option contracts may be used to hedge the volatility of refining margins. We also may use futures contracts to manage price risks associated with inventory quantities above or below target levels. We have not designated any derivative instruments as hedges for accounting purposes and we do not enter into derivative contracts for speculative purposes. All derivative instruments are recorded in the consolidated balance sheet at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of operations. These gains or losses are reported within operating activities on the consolidated statement of cash flows. As of December 31, 2013, we have no outstanding derivatives. Recent Accounting Pronouncements In February 2013, the FASB issued ASU No. 2013-2, "Reporting of Amounts Reclassified Out of Other Comprehensive Income," which requires public companies to present information about reclassification adjustments from accumulated other comprehensive income in their annual and interim financial statements in a single note or on the face of the financial statements. This standard is effective prospectively for annual and interim reporting periods beginning after December 15, 2012. Our adoption did not have a material impact on our financial position, results of operations or cash flows. In July 2012, the FASB issued guidance intended to simplify the impairment test for indefinite-lived intangible assets other than goodwill by giving entities the option to first assess qualitative factors to determine whether it is more likely than not that an indefinite-lived intangible asset is impaired. The results of the qualitative assessment would be used as a basis in determining whether it is necessary to perform the two-step quantitative impairment testing. An entity can choose to perform the qualitative assessment on none, some or all of its indefinite-lived intangible assets, or may bypass the qualitative assessment and proceed directly to the quantitative impairment test. This guidance is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted in certain circumstances. Our adoption did not have a material impact on our financial position, results of operations or cash flows. 75



--------------------------------------------------------------------------------

Table of Contents


For more stories on investments and markets, please see HispanicBusiness' Finance Channel



Source: Edgar Glimpses


Story Tools