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EX-32.2 - EXHIBIT 32.2 - Northern Tier Energy LPnti-3312016xexx322.htm
EX-32.1 - EXHIBIT 32.1 - Northern Tier Energy LPnti-3312016xexx321.htm
EX-31.2 - EXHIBIT 31.2 - Northern Tier Energy LPnti-3312016xexx312.htm
EX-31.1 - EXHIBIT 31.1 - Northern Tier Energy LPnti-3312016xexx311.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-Q
ý
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the quarterly period ended March 31, 2016
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
 
For the transition period from            to           
COMMISSION FILE NO.: 001-35612
 Northern Tier Energy LP
(Exact name of registrant as specified in its charter)
 
 
 
Delaware
 
80-0763623
(State or other jurisdiction of incorporation or organization)
 
(I.R.S. Employer Identification No.)
1250 W. Washington Street, Suite 300
Tempe, Arizona
(Address of principal executive offices)
 
85281
(Zip Code)
(Registrant’s telephone number including area code)
(602) 302-5450
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ý  Yes    ¨  No
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ý  Yes    ¨  No
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large Accelerated Filer
 
ý
  
Accelerated Filer
 
¨
 
 
 
 
Non-Accelerated Filer
 
¨
  
Smaller Reporting Company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    ý  No
As of April 29, 2016, Northern Tier Energy LP had 93,058,480 common units outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “NTI.”





NORTHERN TIER ENERGY LP
FORM 10-Q FOR THE THREE MONTHS ENDED MARCH 31, 2016
TABLE OF CONTENTS
 
 
 
 
Page
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
 
 
 
 
PART I - FINANCIAL INFORMATION
 
ITEM 1.
Financial Statements (Unaudited)
 
 
Condensed Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015
 
 
Condensed Consolidated Statements of Operations and Comprehensive Income for the three months ended March 31, 2016 and 2015
 
 
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015
 
 
Notes to Condensed Consolidated Financial Statements
 
ITEM 2.
Management's Discussion and Analysis of Financial Condition and Results of Operations
 
ITEM 3.
Quantitative and Qualitative Disclosures about Market Risk
 
ITEM 4.
Controls and Procedures
PART II - OTHER INFORMATION
 
ITEM 1.
Legal Proceedings
 
ITEM 1A.
Risk Factors
 
ITEM 6.
Exhibits
SIGNATURES


2


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q (this “Report”) in particular under the sections entitled may constitute “forward-looking statements that represent management's beliefs and assumptions based on currently available information.” The words “believe,” “expect,” “anticipate,” “plan,” “intend,” “foresee,” “should,” “would,” “could” or other similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on our current expectations and beliefs concerning future developments and their potential effect on us. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues, future operating results and future capital expenditures are based on our forecasts for our existing operations and our current plans for our business and also do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include, but are not limited to, those summarized below:
the overall demand for hydrocarbon products, fuels and other refined products;
the possibility that the Merger (as defined below) with Western Refining, Inc. ("Western Refining") may not be consummated in a timely manner or at all;
the diversion of management's attention in connection with the proposed Merger and our ability to realize fully or at all the anticipated benefits of the proposed Merger;
our ability to produce products and fuels that meet our customers’ unique and precise specifications;
the impact of fluctuations and rapid increases or decreases in crude oil, refined products, fuel and utility services prices, renewable fuel credits and crack spreads, including the impact of these factors on our liquidity, reserves, distributions and/or financial performance;
changes in the spread between West Texas Intermediate ("WTI") crude oil and Western Canadian Select crude oil;
changes in the spread between WTI crude oil and Brent crude oil;
changes in the Group 3 6:3:2:1 crack spread;
fluctuations in refinery capacity;
accidents or other unscheduled shutdowns or disruptions affecting our refinery, machinery, or equipment, or those of our suppliers or customers;
changes in the cost or availability of transportation for feedstocks and refined products;
availability and costs of renewable fuels for blending and Renewable Identification Numbers ("RINs") to meet Renewable Fuel Standards ("RFS");
the results of our hedging and other risk management activities;
our ability to comply with covenants contained in our debt instruments;
labor relations;
relationships with our partners and franchisees;
successful integration and future performance of acquired assets, businesses or third-party product supply and processing relationships;
our access to capital in order to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;
environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;
dependence on one principal supplier for retail merchandise;
maintenance of our credit ratings and ability to receive open credit lines from our suppliers;
the effects of competition;
continued creditworthiness of, and performance by, counterparties;
the impact of current and future laws, rulings and governmental regulations;
shortages or cost increases of power supplies, natural gas, materials or labor;
weather interference with business operations;
seasonal trends in the industries in which we operate;
fluctuations in the debt markets;
rulings, judgments or settlements in litigation, tax or other legal or regulatory matters;
changes in economic conditions, generally, and in the markets we serve, consumer behavior, and travel and tourism trends;
execution of capital projects, cost overruns of such projects and failure to realize the expected benefits from such projects;
the price, availability and acceptance of alternative fuels and alternative fuel vehicles;

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operating hazards and natural disasters, casualty losses, acts of terrorism including cyberattacks and other matters beyond our control; and
changes in our treatment as a partnership for U.S. federal or state income tax purposes.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part I, “Item 1A. Risk Factors” elsewhere in this Report and (2) Part II, "Item 1A. Risk Factors" of our Annual Report on Form 10-K for the year ended December 31, 2015 (our "2015 Annual Report on Form 10-K").
Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I - FINANCIAL INFORMATION

ITEM 1. Financial Statements
NORTHERN TIER ENERGY LP
CONDENSED CONSOLIDATED BALANCE SHEETS
(in millions, except unit data, unaudited)
 
 
March 31, 2016
 
December 31, 2015
ASSETS
 
 
 
CURRENT ASSETS
 
 
 
Cash and cash equivalents
$
35.0

 
$
70.9

Accounts receivable, net
174.1

 
186.0

Inventories
273.7

 
241.2

Other current assets
25.5

 
21.3

Total current assets
508.3

 
519.4

NON-CURRENT ASSETS
 
 
 
Equity method investment
87.6

 
82.1

Property, plant and equipment, net
505.6

 
487.8

Intangible assets
33.8

 
33.8

Other assets
14.1

 
14.2

Total Assets
$
1,149.4

 
$
1,137.3

LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES
 
 
 
Accounts payable
$
310.1

 
$
301.4

Accrued liabilities
59.2

 
61.8

Total current liabilities
369.3

 
363.2

NON-CURRENT LIABILITIES
 
 
 
Long-term debt
365.0

 
342.0

Lease financing obligation
11.2

 
11.1

Other liabilities
27.6

 
27.9

Total liabilities
773.1

 
744.2

Commitments and contingencies

 

EQUITY
 
 
 
Partners' capital (93,070,821 and 92,833,486 units issued and outstanding at March 31, 2016 and December 31, 2015, respectively)
376.1

 
392.9

Accumulated other comprehensive income
0.2

 
0.2

Total equity
376.3

 
393.1

Total Liabilities and Equity
$
1,149.4

 
$
1,137.3

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


5


NORTHERN TIER ENERGY LP
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
AND COMPREHENSIVE INCOME
(in millions, except unit and per unit data, unaudited)
 
 
Three Months Ended
 
March 31, 2016

March 31, 2015
REVENUE (a)
$
604.4


$
793.8

COSTS, EXPENSES AND OTHER
 
 
 
Cost of sales (a)
474.2


576.5

Direct operating expenses
78.3


69.3

Turnaround and related expenses
0.4


0.4

Depreciation and amortization
11.3


10.8

Selling, general and administrative expenses
23.3


20.2

Merger-related expenses
0.4

 

Income from equity method investment
(5.5
)
 
(3.6
)
Other loss
0.2


0.7

OPERATING INCOME
21.8

 
119.5

Interest expense, net
(6.5
)
 
(7.5
)
INCOME BEFORE INCOME TAXES
15.3

 
112.0

Income tax provision
(0.6
)
 
(0.8
)
NET INCOME AND COMPREHENSIVE INCOME
$
14.7

 
$
111.2

 
 
 
 
EARNINGS PER UNIT INFORMATION:
 
 
 
Weighted average number of units outstanding:
 
 
 
Basic
92,850,830

 
92,459,063

Diluted
93,087,397

 
92,601,192

Earnings per unit:
 
 
 
Basic
$
0.16

 
$
1.20

Diluted
$
0.16

 
$
1.20

 
 
 
 
Cash distributions declared per common unit
$
0.38

 
$
0.49

 
 
 
 
SUPPLEMENTAL INFORMATION:
 
 
 
(a) Excise taxes included in revenues and cost of sales
$
107.0

 
$
96.0

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



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NORTHERN TIER ENERGY LP
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions, unaudited)
 
 
Three Months Ended
 
March 31, 2016
 
March 31, 2015
CASH FLOWS FROM OPERATING ACTIVITIES
 
 
 
Net income
$
14.7

 
$
111.2

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
Depreciation and amortization
11.3

 
10.8

Non-cash interest expense
0.5

 
0.5

Equity-based compensation expense
4.6

 
2.6

Gain from the change in fair value of outstanding derivatives
(3.7
)
 
(1.1
)
Equity investment earnings, net of dividends
(5.5
)
 
(3.6
)
Change in lower of cost or market inventory adjustment
(11.0
)
 
(10.8
)
Changes in assets and liabilities, net:
 
 
 
Accounts receivable
11.9

 
36.9

Inventories
(21.5
)
 
(15.2
)
Other current assets
(0.5
)
 
1.7

Accounts payable and accrued expenses
4.9

 
(49.2
)
Other, net
0.1

 
(0.9
)
Net cash provided by operating activities
5.8

 
82.9

CASH FLOWS FROM INVESTING ACTIVITIES
 
 
 
Capital expenditures
(27.9
)
 
(6.6
)
Net cash used in investing activities
(27.9
)
 
(6.6
)
CASH FLOWS FROM FINANCING ACTIVITIES
 
 
 
Borrowings from revolving credit arrangement
70.0

 

Repayments of revolving credit arrangement
(47.5
)
 

Equity distributions
(36.3
)
 
(45.9
)
Net cash used in financing activities
(13.8
)
 
(45.9
)
CASH AND CASH EQUIVALENTS
 
 
 
Change in cash and cash equivalents
(35.9
)
 
30.4

Cash and cash equivalents at beginning of period
70.9

 
87.9

Cash and cash equivalents at end of period
$
35.0

 
$
118.3

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

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NORTHERN TIER ENERGY LP
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION
Description of the Business
Northern Tier Energy LP ("NTE LP", "NTI" "Northern Tier" or the "Company") is an independent downstream energy company with refining, retail and logistics operations that serve the Petroleum Administration for Defense District II (“PADD II”) region of the United States. NTE LP holds 100% of the membership interest in Northern Tier Energy LLC (“NTE LLC”). NTE LP is a master limited partnership (“MLP”) for U.S. federal income tax purposes.
NTE LP includes the operations of NTE LLC, St. Paul Park Refining Co. LLC (“SPPR”), Northern Tier Retail Holdings LLC (“NTRH”) and Northern Tier Oil Transport LLC (“NTOT”). NTRH is the parent company of Northern Tier Retail LLC (“NTR”) and Northern Tier Bakery LLC (“NTB”). NTR is the parent company of SuperAmerica Franchising LLC (“SAF”). SPPR owns a 17% interest in MPL Investments Inc. (“MPLI”) and a 17% interest in Minnesota Pipe Line Company, LLC (“MPL”). MPLI owns 100% of the preferred interest in MPL, which owns and operates a 465,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 6). NTOT is a crude oil trucking business in North Dakota that collects crude oil directly from wellheads in the Bakken shale and transports it to regional pipeline and rail facilities.
Western Refining, Inc. (“Western Refining”) indirectly owns 100% of Northern Tier Energy GP LLC ("NTE GP"), the general partner of NTE LP, and 35,622,500 common units, or 38.3%, of NTE LP. The remaining balance of the NTE LP units are publicly traded. Western Refining, through its subsidiary NT InterHold Co LLC, a Deleware limited liability company ("NT InterHold Co") as the owner of the general partner of NTE LP, has the ability to appoint all of the members of the NTE GP's board of directors.
On December 21, 2015, Western Refining and NTE LP announced that they had entered into an Agreement and Plan of Merger dated as of December 21, 2015 ("the Merger Agreement") with NTE GP and Western Acquisition Co, LLC, a Delaware limited liability company and wholly-owned subsidiary of Western Refining ("MergerCo") whereby Western Refining will acquire all of Northern Tier's outstanding common units not already owned by Western Refining (the "Merger"). Under the terms of the Merger Agreement, each NTI common unit held by a Northern Tier unitholders other than Western Refining and its subsidiaries (“NTI Public Unitholders”) will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash and 0.2986 of a share of Western Refining common stock, (ii) $26.06 in cash without interest or (iii) 0.7036 of a share of Western Refining common stock. The election will be subject to proration to ensure that the aggregate cash paid and Western Refining common stock issued in the Merger will equal the total amount of cash and number of shares of Western Refining common stock that would have been paid and delivered if all NTI Public Unitholders received $15.00 in cash and 0.2986 of a share of Western Refining common stock per Northern Tier common unit. The transaction is expected to result in approximately 17.2 million additional shares of WNR common stock outstanding. Upon completion of the transaction, NTI will continue to exist as a limited partnership and will become a wholly-owned limited partnership subsidiary of WNR. The transaction is expected to close in the second quarter of 2016, pending the satisfaction of certain customary closing conditions and the approval of the Merger and other matters at a special meeting of the NTI unitholders currently scheduled to be held on June 23, 2016 (see Note 19).
As of March 31, 2016, the St. Paul Park refinery owned by SPPR, which is located in St. Paul Park, Minnesota, had total crude oil throughput capacity of 97,800 barrels per stream day. Refining operations include crude fractionation, catalytic cracking, hydrotreating, reforming, alkylation, sulfur recovery and a hydrogen plant. The refinery processes predominately North Dakota and Canadian crude oils into products such as gasoline, diesel, jet fuel, kerosene, asphalt, propane, propylene and sulfur. The refined products are sold primarily in the Upper Great Plains of the United States.
As of March 31, 2016, NTR operated 169 convenience stores under the SuperAmerica brand and SAF supported 114 franchised stores which also utilize the SuperAmerica brand. These 283 SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise and, in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items. NTB prepares and distributes food products under the SuperMom’s brand primarily to SuperAmerica branded retail outlets.
Basis of Presentation
The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) for interim financial information. Accordingly, they do not include all of the information and footnotes required by GAAP for complete financial statements. In the opinion of management, all adjustments (consisting of normal recurring accruals) considered necessary for a fair presentation of the results for the periods reported have been included. Operating results for the three months ended March 31, 2016 are not necessarily indicative of the

8


results that may be expected for the year ending December 31, 2016, or for any other period. The condensed consolidated balance sheet at December 31, 2015 has been derived from the audited financial statements of NTE LP at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying condensed consolidated financial statements should be read in conjunction with the Company’s 2015 Annual Report on Form 10-K.
2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES
The significant accounting policies set forth in Note 2 to the consolidated financial statements in the Company's 2015 Annual Report on Form 10-K, appropriately represent, in all material respects, the current status of accounting policies and are incorporated herein by reference.
Principles of Consolidation
NTE LP is a Delaware limited partnership which consolidates all accounts of NTE LLC and its subsidiaries, including SPPR, NTRH and NTOT. All intercompany accounts have been eliminated in these condensed consolidated financial statements.
The Company’s common equity interest in MPL is accounted for using the equity method of accounting. Equity income from MPL represents the Company’s proportionate share of net income available to common equity owners generated by MPL.
The equity method investment is assessed for impairment whenever changes in facts or circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in operating income. See Note 6 for further information on the Company’s equity method investment.
MPLI owns all of the preferred membership units of MPL. This investment in MPLI, which provides the Company no significant influence over MPLI, is accounted for as a cost method investment. The investment in MPLI is carried at a value of $6.8 million at both March 31, 2016 and December 31, 2015, and is included in other noncurrent assets within the condensed consolidated balance sheets.
Use of Estimates
The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the condensed consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates.
Operating Segments
The Company has two reportable operating segments; Refining and Retail (see Note 18 for further information on the Company’s operating segments). The Refining and Retail operating segments consist of the following: 
Refining – operates the St. Paul Park, Minnesota refinery, terminal and related assets, NTOT and includes the Company’s interest in MPL and MPLI, and
Retail – comprised of 169 Company operated convenience stores and 114 franchisee operated convenience stores as of March 31, 2016, primarily in Minnesota and Wisconsin. The retail segment also includes the operation of NTB.
Inventories
Crude oil, refined product and other feedstock and blendstock inventories are carried at the lower of cost or market ("LCM"). Cost is determined principally under the last-in, first-out (“LIFO”) valuation method to reflect a better matching of costs and revenues for refining inventories. Costs include both direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. Ending inventory costs in excess of market value are written down to net realizable market values and charged to cost of sales in the period recorded. In subsequent periods, a new LCM determination is made based upon current circumstances relative to, and not to exceed, the original LCM reserve that was established in fourth quarter 2014. The Company has LIFO pools for crude oil and other feedstocks and for refined products in its Refining segment and a LIFO pool for refined products inventory held by the retail stores in its Retail segment. Retail merchandise inventory is valued using the average cost method.
Property, Plant and Equipment
Property, plant and equipment is recorded at cost and depreciated on a straight-line basis over the estimated useful lives of the assets. Such assets are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If the sum of the expected undiscounted future cash flows from the use of the asset and its eventual disposition is less than the carrying amount of the asset, an impairment loss is recognized based on the fair value of the asset.

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When property, plant and equipment depreciated on an individual basis is sold or otherwise disposed of, any gains or losses are reported in the condensed consolidated statements of operations and comprehensive income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.
Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as “turnarounds.” Turnaround cycles vary from unit to unit but can be as short as one year for catalyst changes to as long as six years. Turnaround costs are expensed as incurred.
Derivative Financial Instruments
The Company is exposed to earnings and cash flow volatility due to fluctuations in crude oil, refined products, and natural gas prices. The timing of certain commodity purchases and sales also subject the Company to earnings and cash flow volatility. To manage these risks, the Company may use derivative instruments associated with the purchase or sale of crude oil, refined products, and natural gas to hedge volatility in our refining and operating margins. The Company may use futures, options, and swaps contracts to manage price risks associated with inventory quantities above or below target levels. Crack spread and crude differential futures and swaps contracts may also be used to hedge the volatility of refining margins.
All derivative instruments, except for those that meet the normal purchases and normal sales exception, are recorded in the condensed consolidated balance sheets at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of the Company's contracts are accounted for by marking them to market and recognizing any resulting gains or losses in the condensed consolidated statements of operations and comprehensive income. Gains and losses from derivative activity specific to managing price risk on inventory quantities both above and below target levels are included within cost of sales. Derivative gains and losses are reported as operating activities within the condensed consolidated statements of cash flows.
The Company enters into crude oil forward contracts to facilitate the supply of crude oil to the refinery. These contracts may qualify for the normal purchases and normal sales exception because the Company physically receives and delivers the crude oil under the contracts and when the Company enters into these contracts, the quantities are expected to be used or sold over a reasonable period of time in the normal course of business. These transactions are reflected in the period that delivery of the crude oil takes place. When forward contracts do not qualify for the normal purchases and sales exception, the contracts are marked to market each period through the settlement date, which is generally no longer than one to three months.
Renewable Identification Numbers
The Company is subject to obligations to generate or purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy its RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in accrued liabilities when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in other current assets when the amount of RINs earned and purchased is greater than the RINs liability.
In 2010 and 2011, the EPA issued partial waivers with conditions allowing a maximum of 15% ethanol to be used in certain vehicles. Future changes to existing laws and regulations could increase the minimum volumes of renewable fuels that must be blended with refined petroleum fuels. Because the Company does not produce renewable fuels, increasing the volume of renewable fuels that must be blended into its products could displace an increasing volume of the Company's refineries' product pool, potentially resulting in lower earnings and materially adversely affecting our ability to issue dividends to the Company's unitholders. The purchase price for RINs is volatile and may vary significantly from period to period. Historically, the cost of purchased RINs has not had a significant impact upon the Company's operating results. The Company anticipates 2016 will be consistent with this history.
Revenue Recognition
Revenues are recognized when products are shipped or services are provided to customers, title is transferred, the sales price is fixed or determinable and collectability is reasonably assured. Revenues are recorded net of discounts granted to customers. Shipping and other transportation costs billed to customers are presented on a gross basis in revenues and cost of sales.
Nonmonetary product exchanges and certain buy/sell crude oil transactions, which are entered into in contemplation one with another, are included on a net cost basis in cost of sales. The Company also enters into agreements to purchase and sell crude oil to third parties and certain of these activities are recorded on a gross basis.
Cost of Sales

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Cost of sales in the condensed consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the condensed consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.
Excise Taxes
The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the condensed consolidated statements of operations and comprehensive income. These taxes totaled $107.0 million and $96.0 million for the three months ended March 31, 2016 and 2015, respectively.
Accounting Developments
In May 2014, the FASB issued ASU No. 2014-09 “Revenue from Contracts with Customers,” which provides guidance for revenue recognition. The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. In August 2014, the FASB issued ASU No. 2015-14 which deferred the effective date of ASU 2014-09. This guidance will now be effective for the Company's financial statements in the annual period beginning after December 15, 2017. The Company is evaluating the effect of adopting this new accounting guidance and does not expect adoption will have a material impact on NTE's results of operations, cash flows or financial position.
In February 2016, the FASB issued ASU No. 2016-02 “Leases,” which replaces the existing guidance in Accounting Standards Codification (“ASC”) 840. This new guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2018 with early adoption permitted. The guidance requires a dual approach for lessee accounting under which a lessee would account for leases as finance leases or operating leases.  Both finance leases and operating leases will result in the lessee recognizing a right-of-use (ROU) asset and a corresponding lease liability.  For finance leases the lessee would recognize interest expense and amortization of the ROU asset and for operating leases the lessee would recognize a straight-line total lease expense.  The Company is currently assessing the impact that adoption of this guidance will have on its consolidated financial statements and footnote disclosures.
In March 2016, the FASB issued ASU No. 2016-04 "Liabilities – Extinguishment of Liabilities (Subtopic 405-20): Recognition of Breakage for Certain Prepaid Stored-Value Products," which aligns recognition of the financial liabilities related to prepaid stored-value products (for example, prepaid gift cards), with Topic 606, Revenues from Contracts with Customers, for non-financial liabilities. In general, certain of these liabilities may be extinguished proportionally in earnings as redemptions occur, or when redemption is remote if issuers are not entitled to the unredeemed stored value. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2017 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.
In March 2016, the FASB issued ASU No. 2016-06 "Derivatives and Hedging (Topic 815) – Contingent Put and Call Options in Debt Instruments" which will reduce diversity of practice in identifying embedded derivatives in debt instruments. ASU 2016-06 clarifies that the nature of an exercise contingency is not subject to the “clearly and closely” criteria for purposes of assessing whether the call or put option must be separated from the debt instrument and accounted for separately as a derivative. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.
In March 2016, the FASB issued ASU No. 2016-08 "Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net)," which clarifies the implementation guidance on principal versus agent considerations. The guidance includes indicators to assist an entity in determining whether it controls a specified good or service before it is transferred to the customers. The effective date and transition requirements for the amendments in this Update are the same as the effective date and transition requirements of ASU 2014-09. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.
In March 2016, the FASB issued ASU No. 2016-09 "Compensation – Stock Compensation," which identifies areas for simplification involving several aspects of accounting for equity-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, an option to recognize gross stock compensation expense with actual forfeitures recognized as they occur, as well as certain classifications on the statement of cash flows. This guidance is effective for fiscal years, and interim periods within those years, beginning after December 15, 2016 with early adoption permitted subject to certain requirements. The Company is currently assessing the impact that adopting this new accounting standard will have on its consolidated financial statements and footnote disclosures.

11


3. RELATED PARTY TRANSACTIONS
As of March 31, 2016, Western Refining owned 35,622,500 common units, or 38.3%, of NTE LP as well as 100% of NT InterHoldCo LLC, which owned 100% of NTE GP, the general partner of NTE LP. On December 21, 2015, Western Refining and NTE LP announced that they had entered into the Merger Agreement with MergerCo and NTE GP whereby Western Refining will acquire all of NTE LP's outstanding common units not already owned by Western Refining (see Note 19).
The Company has engaged in several types of transactions with Western Refining including crude and feedstock purchases, asphalt purchases, finished product purchases and railcar leases. Additionally, the Company is party to a shared services agreement with Western Refining and Western Refining Logistics, LP whereby the Company both receives and provides administrative support services. The shared services agreement was entered into with Western Refining as of September 1, 2014, and was approved by the Conflicts Committee of the board of directors of NTE GP. On May 4, 2015, Western Refining Logistics, LP joined as a party to this agreement. The services covered by the shared services agreement include assistance with treasury, risk management and commercial operations, environmental compliance, information technology support, internal audit and legal.
MPL is also a related party of the Company. Prior to September 30, 2014, the Company had a crude oil supply and logistics agreement with a third party and therefore had no direct supply transactions with MPL prior to that date. Beginning on September 30, 2014, the Company began paying MPL for transportation services at published tariff rates. Additionally, the Company owns a 17% interest in MPL (see Note 6) and generally receives quarterly cash distributions related to this investment.
The Company engaged in the following related party transactions with unconsolidated affiliates for the three months ended March 31, 2016 and 2015:
 
 
 
Three Months Ended
(in millions)
Location in Statement of Operations and Comprehensive Income
 
March 31, 2016
 
March 31, 2015
Western Refining:
 
 
 
 
 
Asphalt sales
Revenue
 
$
8.7

 
$
12.3

Railcar rental
Revenue
 
0.1

 

Shared services purchases
Selling, general and administrative expenses
 
0.8

 
0.7

Minnesota Pipe Line Company:
 
 
 
 
 
Pipeline transportation purchases
Cost of sales
 
14.0

 
12.7

The Company had the following outstanding receivables and payables with non-consolidated related parties at March 31, 2016 and December 31, 2015:
(in millions)
Balance Sheet Location
 
March 31, 2016
 
December 31, 2015
Net receivable (payable) with related party:
 
 
 
 
 
Western Refining
Accounts receivable, net
 
$
1.6

 
$
2.8

Minnesota Pipe Line Company
Accounts payable
 
2.4

 
2.7

4. INCOME TAXES
NTE LP is treated as a partnership for federal and state income tax purposes. However, NTRH, the parent company of NTR and NTB, is taxed as a corporation for federal and state income tax purposes. No provision for income tax is calculated on the earnings of the Company or its subsidiaries, other than NTRH, as these entities are pass-through entities for tax purposes.
The Company’s effective tax rate for the three months ended March 31, 2016 and 2015 was 3.9% and 0.7%, respectively. For the three months ended March 31, 2016 and 2015, the Company's consolidated federal and state expected statutory tax rates were 40.8% and 40.5%, respectively. The Company's effective tax rate for the three months ended March 31, 2016 and 2015 was lower than the statutory rate primarily due to the fact that only the retail operations of the Company are taxable entities.

12


5. INVENTORIES
 
 
March 31,
 
December 31,
(in millions)
2016
 
2015
Crude oil and refinery feedstocks
$
174.4

 
$
171.8

Refined products
179.1

 
162.0

Merchandise
22.3

 
22.8

Supplies and sundry items
21.3

 
19.0

 
397.1

 
375.6

Lower of cost or market inventory reserve
(123.4
)
 
(134.4
)
Total
$
273.7

 
$
241.2

Inventories accounted for under the LIFO method comprised 89% of the total inventory value at both March 31, 2016 and December 31, 2015, prior to the application of the lower of cost or market reserve.
In order to state the Company's inventories at market values that were lower than its LIFO costs, the Company reduced the carrying values of its inventory through LCM reserves of $123.4 million and $134.4 million, at March 31, 2016 and December 31, 2015, respectively.
6. EQUITY METHOD INVESTMENT
The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $87.6 million and $82.1 million at March 31, 2016 and December 31, 2015, respectively.
As of both March 31, 2016 and December 31, 2015, the carrying amount of the equity method investment was $5.9 million higher than the underlying net assets of the investee, respectively. The Company is amortizing this difference over the remaining life of MPL’s primary asset (the fixed asset life of the pipeline).
The Company recorded no distributions from MPL for the three months ended March 31, 2016 and $3.7 million in declared but unpaid distributions from MPL for the three months ended March 31, 2015. Equity income from MPL was $5.5 million and $3.6 million for the three months ended March 31, 2016 and 2015, respectively.
7. PROPERTY, PLANT AND EQUIPMENT
Major classes of property, plant and equipment (“PP&E”) consisted of the following: 
 
Estimated
 
March 31,
 
December 31,
(in millions)
 Useful Lives
 
2016
 
2015
Land
 
 
$
9.4

 
$
9.0

Retail stores and equipment
2 - 22 years
 
77.6

 
72.3

Refinery and equipment
5 - 24 years
 
458.2

 
457.2

Buildings and building improvements
25 years
 
11.7

 
11.7

Software
5 years
 
18.9

 
18.9

Vehicles
5 years
 
5.8

 
5.6

Other equipment
2 - 7 years
 
10.5

 
10.4

Precious metals
 
 
10.2

 
10.2

Assets under construction
 
 
95.1

 
73.3

 
 
 
697.4

 
668.6

Less: Accumulated depreciation
 
 
(191.8
)
 
(180.8
)
Property, plant and equipment, net
 
 
$
505.6

 
$
487.8

PP&E includes gross assets acquired under capital leases of $13.6 million and $13.3 million at March 31, 2016 and December 31, 2015, respectively, with related accumulated depreciation of $2.2 million and $2.0 million, respectively. The Company had depreciation expense related to capitalized software of $0.9 million for both the three months ended March 31, 2016 and 2015. The Company capitalized $1.3 million and zero of interest expense related to capital projects within the refining segment for the three months ended March 31, 2016 and 2015, respectively.

13


8. INTANGIBLE ASSETS
Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both March 31, 2016 and December 31, 2015. At both March 31, 2016 and December 31, 2015, the franchise rights and trade name intangible asset values were $12.4 million and $21.4 million, respectively. These assets have an indefinite life and are not amortized, but rather are tested for impairment annually or when events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. Based on the testing performed as of June 30, 2015, the Company noted no indications of impairment.
9. DERIVATIVES
The Company is exposed to market risks related to the volatility in the price of crude oil, refined products (primarily gasoline and distillate), and natural gas used in its operations. To reduce the impact of price volatility on its results of operations and cash flows, the Company uses commodity derivative instruments, including forwards, futures, swaps, and options. The Company uses the futures markets for the available liquidity, which provides greater flexibility in transacting in these instruments. The Company uses swaps primarily to manage its price and margin exposure. The positions in commodity derivative instruments are monitored and managed on a daily basis by a risk control group to ensure compliance with the Company's stated commercial risk management policy. The Company considers these transactions economic hedges of market risk but has elected not to designate these instruments as hedges for financial reporting purposes.
The Company recognizes all derivative instruments, except for those that qualify for the normal purchase and normal sales exception, as either assets or liabilities at fair value on the condensed consolidated balance sheets and any related net gain or loss is recorded as a gain or loss in the condensed consolidated statements of operations and comprehensive income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 12) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end.
Risk Management Activities by Type of Risk
The Company periodically uses futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. The Company also periodically uses crack spread and crude differential futures and swaps contracts to manage refining margins. Under the Company's risk mitigation strategy, it may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash.
The objective of the Company's economic hedges pertaining to crude oil and refined products is to hedge price volatility in certain refining inventories and firm commitments to purchase crude oil inventories. The level of activity for the Company's economic hedges is based on the level of operating inventories, and generally represents the amount by which inventories differ from established target inventory levels. The objective of the Company's economic hedges pertaining to natural gas is to lock in the price for a portion of the Company's forecasted natural gas requirements at existing market prices that are deemed favorable.
At March 31, 2016 and December 31, 2015, the Company had open commodity derivative instruments as follows:
 
March 31, 2016
 
December 31, 2015
Crude oil and refined products (thousands of barrels):
 
 
 
Futures - long

 
90

Futures - short
1,643

 
933

Swaps - long
7,017

 
5,155

Swaps - short
75

 
525

Forwards - long
5,282

 
4,445

Forwards - short
3,214

 
2,572

Natural gas (thousands of MMBTUs):
 
 
 
Swaps
1,148

 
1,554


14


The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at March 31, 2016:
 
Notional Contract Volumes by Year of Maturity
 
2016
 
2017
Crude oil and refined products (thousands of barrels):
 
 
 
Futures - short
1,643

 

Swaps - long
5,099

 
1,918

Swaps - short
75

 

Forwards - long
5,282

 

Forwards - short
3,214

 

Natural gas (thousands of MMBTUs):
 
 
 
Swaps
1,148

 

Fair Value of Derivative Instruments
The following tables provide information about the fair values of the Company's derivative instruments as of March 31, 2016 and December 31, 2015 and the line items in the condensed consolidated balance sheets in which the fair values are reflected. See Note 12 for additional information related to the fair values of derivative instruments.
The Company is required to post margin collateral with a counterparty in support of our hedging activities. Funds posted as collateral were $6.7 million and $6.0 million as of March 31, 2016 and December 31, 2015. The margin collateral posted is required by counterparties and cannot be offset against the fair value of open contracts except in the event of default. The Company nets fair value amounts recognized for multiple similar derivative contracts executed with the same counterparty under master netting arrangements, including cash collateral assets and obligations. The tables below, however, are presented on a gross asset and gross liability basis.
 
 
 
 
March 31, 2016
(in millions)
 
Balance Sheet Location
 
Assets
 
Liabilities
Commodity instruments:
 
 
 
 
 
 
Swaps
 
Other current assets
 
$
0.2

 
$
0.9

Swaps
 
Accrued liabilities
 
0.6

 
6.8

Swaps
 
Other assets
 
1.0

 
0.9

Futures
 
Other current assets
 
2.3

 
0.1

Forwards
 
Other current assets
 
4.1

 

Forwards
 
Accrued liabilities
 

 
3.3

Total
 
 
 
$
8.2

 
$
12.0

 
 
 
 
 
 
 
 
 
 
 
December 31, 2015
(in millions)
 
Balance Sheet Location
 
Assets
 
Liabilities
Commodity instruments:
 
 
 
 
 
 
Swaps
 
Accrued liabilities
 
$

 
$
7.9

Futures
 
Other current assets
 
0.4

 

Forwards
 
Other current assets
 
1.5

 

Forwards
 
Accrued liabilities
 

 
1.5

Total
 
 
 
$
1.9

 
$
9.4


15


Effect of Hedging Instruments on Income
All derivative contracts are marked to market at period end and the resulting gains and losses are recognized in earnings. The following tables provide information about the gain or loss recognized in income on the Company's derivative instruments and the line items in the financial statements in which such gains and losses are reflected.
Recognized gains and losses on derivatives were as follows:
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Gain (loss) on the change in fair value of outstanding derivatives
$
3.7

 
$
1.1

Settled derivative gains (losses)
(4.4
)
 
0.1

Total recognized gain (loss)
$
(0.7
)
 
$
1.2

 
 
 
 
Gain (loss) recognized in cost of sales
$
(0.1
)
 
$
1.4

Gain (loss) recognized in operating expenses
(0.6
)
 
(0.2
)
Total recognized net gain (loss) on derivatives
$
(0.7
)
 
$
1.2

Market and Counterparty Risk
The Company is exposed to credit risk in the event of nonperformance by counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with long-term credit ratings of at least BBB+ by Standard and Poor’s and A3 by Moody’s. In the event of default, the Company may be subject to losses on a derivative instrument’s mark-to-market gains. The Company does not expect nonperformance of the counterparties involved in its risk mitigation arrangements.
10. DEBT
ABL Facility
On September 29, 2014, NTE LLC and its subsidiaries entered into an amended and restated asset-based ABL Facility with JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as collateral agent for the other secured parties (the "ABL Facility"). The borrowers under the ABL Facility are SPPR, NTB, NTR and SAF, each of which is a wholly owned subsidiary of NTE LLC.
Lenders under the ABL Facility hold commitments totaling $500 million, which is subject to a borrowing base comprised of eligible accounts receivable and inventory. The ABL Facility matures on September 29, 2019. Borrowings under the ABL Facility can be either base rate loans plus a margin ranging from 0.50% to 1.00% or LIBOR loans plus a margin ranging from 1.50% to 2.00%, subject to adjustment based upon the average historical excess availability. The ABL Facility also provides for a quarterly commitment fee ranging from 0.25% to 0.375% per annum, subject to adjustment based upon the average utilization ratio, and letter of credit fees ranging from 1.50% to 2.00% per annum payable quarterly, subject to adjustment based upon the average historical excess availability. The ABL Facility may be used for general corporate purposes, including to fund working capital needs and letter of credit requirements. The Company incurred financing costs associated with the new ABL Facility of $3.0 million which will be amortized to Interest expense, net through the date of maturity.
The ABL Facility is guaranteed, on a joint and several basis, by NTE LLC and its subsidiaries and will be guaranteed by any newly acquired or formed subsidiaries, subject to certain limited exceptions. The ABL Facility and such guarantees are secured on a first priority basis by substantially all of NTE LLC's and such subsidiaries’ cash and cash equivalents, accounts receivable and inventory and on a second priority basis by NTE LLC's and such subsidiaries’ fixed assets (other than real property).
The ABL Facility contains certain covenants, including but not limited to limitations on debt, liens, investments, and dividends as well as the maintenance of a minimum fixed charge coverage ratio in certain circumstances.
As of March 31, 2016, the borrowing base under the ABL Facility was $186.6 million and availability under the ABL Facility was $134.7 million (which is net of $29.4 million outstanding letters of credit and $22.5 million in direct borrowings). The borrowers under the ABL Facility had $22.5 million borrowings under the ABL Facility at March 31, 2016, located in Long-term debt on the condensed consolidated balance sheet.
2020 Secured Notes
As of March 31, 2016 and December 31, 2015, the Company had $350.0 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). A portion of these notes were issued with an offering premium of $4.2 million, which is being amortized to Interest expense, net over the remaining term of the notes. Additionally, professional service costs were incurred in both the issuance of the 2020 Secured Notes and the establishment of the ABL

16


Facility which are presented within Long-term debt in the condensed consolidated balance sheets. The carrying value of these costs at March 31, 2016 and December 31, 2015 was $10.9 million and $11.6 million, respectively.
The 2020 Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future 100% direct and indirect subsidiaries on a full and unconditional basis; however, there are certain obligations not guaranteed on a full and unconditional basis as a result of subsidiaries being released as guarantors. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary being declared “unrestricted,” (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidated financial information is not included as the guarantor company, NTE LP, does not have independent assets or operations. The 2020 Secured Notes and the subsidiary note guarantees are secured on a pari passu basis with certain hedging agreements by a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of NTE LLC and each of the subsidiary guarantors and by a second-priority security interest in the inventory, accounts receivable, investment property, general intangibles, deposit accounts and cash and cash equivalents collateralized by a $500 million secured asset-based ABL Facility with a maturity date of September 29, 2019. Additionally, the 2020 Secured Notes are fully and unconditionally guaranteed on a senior unsecured basis by NTE LP. NTE LP's creditors have no recourse to the assets of Western Refining and its subsidiaries. Western Refining's creditors have no recourse to the assets of NTE LP and its subsidiaries. The Company is required to make interest payments on May 15 and November 15 of each year, which commenced on May 15, 2013. There are no scheduled principal payments required prior to the 2020 Secured Notes maturing on November 15, 2020. The outstanding $350.0 million in 2020 Secured Notes are registered with SEC through two separate registrations occurring in October 2013 and January 2015.
At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and, in certain cases, pay a redemption premium.
The 2020 Secured Notes contain certain covenants that, among other things, limit the ability, subject to certain exceptions, of the Company to incur additional debt or issue preferred equity interests, to purchase, redeem or otherwise acquire or retire its equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of its property or assets, to merge, consolidate, lease or sell substantially all of the Company’s assets, to suffer a change of control or to enter into new lines of business.
11. EQUITY
Western Refining indirectly owns 100% of Northern Tier Energy GP LLC and 35,622,500 common units, or 38.3%, of NTE LP. The balance of the limited partner units remain publicly traded.
Proposed Merger with Western Refining
On December 21, 2015, NTE LP and NTE GP entered into the Merger Agreement with Western Refining and MergerCo pursuant to which Western Refining will acquire all of Northern Tier's outstanding common units not already held by Western Refining. Each of the outstanding Northern Tier common units held by the NTI Public Unitholders will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of Western Refining common stock; or (ii) $26.06 in cash without interest; or (iii) 0.7036 of a share of Western Refining common stock. The election will be subject to proration to ensure that the aggregate cash paid and Western Refining common stock issued in the Merger will equal the total amount of cash and number of shares of Western Refining common stock that would have been paid and delivered if all NTI Public Unitholders received $15.00 in cash and 0.2986 of a share of Western Refining common stock per Northern Tier common unit. The Merger is expected to close in the second quarter of 2016, pending the satisfaction of certain customary conditions and the approval of the Merger and other matters at a special meeting of NTI unitholders by the affirmative vote of holders, as of May 19, 2016, the record date for the special meeting of a majority of the outstanding Northern Tier common units (including the Northern Tier common units held by Western Refining). The transaction is expected to result in approximately 17.2 million additional shares of Western Refining common stock outstanding. Upon completion of the transaction, NTI will continue to exist as a limited partnership and will become a wholly-owned limited partnership subsidiary of Western Refining (see Note 19).
Distribution Policy
The Company generally expects within 60 days after the end of each quarter to make distributions, if any, to unitholders of record as of the applicable record date. The board of directors of the Company's general partner adopted a policy pursuant to which distributions for each quarter, if any, will equal the amount of available cash the Company generates in such quarter, if any. Distributions on the Company's units will be in cash. Available cash for each quarter, if any, will be determined by the board of directors of the Company's general partner following the end of such quarter. Distributions are expected to be based on the amount of available cash generated in such quarter. Available cash for each quarter will generally equal the Company's cash

17


flow from operations for the quarter, excluding working capital changes, less cash required for maintenance and regulatory capital expenditures, reimbursement of expenses incurred by the Company's general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for turnaround and related expenses, working capital, and organic growth projects. 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 and capital expenditures for organic growth projects will be funded with cash reserves or borrowings under the ABL Facility. The Company may also choose to fund organic growth via issuance of debt or equity securities or borrowings under the ABL Facility. The Company does not intend to maintain excess distribution coverage or reserve cash for the purpose of maintaining stability or growth in our quarterly distribution. The Company does not intend to incur debt to pay quarterly distributions. The Company expects to finance substantially all of its external growth, either by issuances of debt or equity securities, or through borrowings under the ABL Facility.
Because Northern Tier's policy will be to distribute an amount equal to the available cash, if any, generated each quarter, unitholders will have direct exposure to fluctuations in the amount of cash generated by the Company's 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, including inventory fluctuations, (iv) maintenance and regulatory capital expenditures, (v) organic growth capital expenditures less any amounts Northern Tier may choose to fund with borrowings from the ABL Facility or by issuance of debt or equity securities and (vi) cash reserves deemed necessary or appropriate by the board of directors of our general partner, including amounts to replenish unfunded reserves from the calculation of first quarter 2016 cash available for distribution. Such variations in the amount of the quarterly distributions may be significant. Unlike most publicly traded partnerships, Northern Tier does not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of Northern Tier's general partner may change the foregoing distribution policy at any time. The Company's partnership agreement does not require the payment of distributions to Northern Tier unitholders on a quarterly or other basis.
The following table details the quarterly distributions paid to common unitholders for each of the quarters in the year ended December 31, 2015 and the three months ended March 31, 2016:
Date Declared
 
Date Paid
 
Common Units and equivalents at record date (in millions)
 
Distribution per common unit and equivalent
 
Total Distribution (in millions)
2015 Distributions:
 
 
 
 
 
 
 
 
February 5, 2015
 
February 27, 2015
 
93.7
 
$
0.49

 
$
45.9

May 5, 2015
 
May 29, 2015
 
93.7
 
1.08

 
100.8

August 4, 2015
 
August 28, 2015
 
93.7
 
1.19

 
111.3

November 3, 2015
 
November 25, 2015
 
93.7
 
1.04

 
97.3

Total distributions paid during 2015
 
 
 
$
3.80

 
$
355.3

2016 Distributions:
 
 
 
 
 
 
 
 
February 3, 2016
 
February 19, 2016
 
94.2
 
$
0.38

 
$
36.1

Total distributions paid during 2016
 
 
 
$
0.38

 
$
36.1

Cash available for distribution for the three months ended March 31, 2016, calculated in accordance with the Company's distribution policy, resulted in a deficit of $11.5 million. As a result, the board of directors of NTE GP did not approve a quarterly distribution for this period.
Consistent with the Company’s distribution policy, cash distributions with respect to the second quarter of 2016, if any, would normally be declared and paid in August 2016. However, pursuant to the terms of the Merger Agreement, with respect to the quarter in which the closing date of the Merger (the “Closing Date”) occurs, which is currently expected to be the second quarter of 2016, assuming all closing conditions are satisfied, the Company will, to the extent it generates available cash in such quarter, make a prorated quarterly distribution to unitholders of record as of immediately prior to the effective time of the Merger (the “Effective Time”) of any such available cash if the record date for the Western Refining quarterly cash dividend to be paid in that quarter occurs before the Closing Date. Accordingly, in the quarter that the Closing Date occurs, Northern Tier common unitholders who receive Western Refining common stock in the Merger will receive (i) a Northern Tier cash distribution in respect of the previous quarter, to the extent Northern Tier generates available cash in such quarter, and (ii) either a Northern Tier prorated cash distribution in respect of available cash generated by Northern Tier in the quarter in which the

18


Closing Date occurs or (assuming such unitholders continue to hold the shares of Western Refining common stock received in the Merger through the record date for such Western Refining dividend) the Western Refining quarterly cash dividend payable in the quarter in which the Closing Date occurs. The amount of any distribution will not have any effect on the merger consideration to be received by the Company’s unitholders.
Changes in Partners' Equity
(in millions)
Partners' Capital
 
Accumulated Other Comprehensive Income
 
Total Partners' Equity
Balance at December 31, 2015
$
392.9

 
$
0.2

 
$
393.1

Net income
14.7

 

 
14.7

Distributions
(36.1
)
 

 
(36.1
)
Equity-based compensation expense
4.6

 

 
4.6

Balance at March 31, 2016
$
376.1

 
$
0.2

 
$
376.3

During the three months ended March 31, 2016, the Company's common units issued and outstanding increased by 237,335, which was primarily attributable to the conversion of phantom units into common units upon vesting (see Note 14).
Earnings per Unit
The following table illustrates the computation of basic and diluted earnings per unit for the three months ended March 31, 2016 and 2015. The Company has outstanding restricted common units, phantom common units, and dividend equivalent rights under its 2012 Long-Term Incentive Plan ("LTIP") (see Note 14) that participate in distributions. Additionally, distributions paid on many of the restricted common units are non-forfeitable, which requires the Company to calculate earnings per unit under the two-class method. Under this method, distributed earnings and undistributed earnings are allocated between unrestricted common units and restricted common units. The Company applies the treasury stock method to determine the dilutive impact of the outstanding phantom common units.
 
Three Months Ended
(in millions, except unit and per-unit data)
March 31, 2016
 
March 31, 2015
Net income available to common unitholders
$
14.7

 
$
111.2

Less: income allocated to participating securities

 
(0.3
)
Net income attributable to unrestricted common units
$
14.7

 
$
110.9

 
 
 
 
Weighted average unrestricted common units - basic
92,850,830

 
92,459,063

Plus: dilutive potential common securities
236,567

 
142,129

Weighted average unrestricted common units - diluted
93,087,397

 
92,601,192

 
 
 
 
Basic earnings per unit
$
0.16

 
$
1.20

Diluted earnings per unit
$
0.16

 
$
1.20

12. FAIR VALUE MEASUREMENTS
As defined in GAAP, fair value is the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. GAAP describes three approaches to measuring the fair value of assets and liabilities: the market approach, the income approach and the cost approach, each of which includes multiple valuation techniques. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities. The income approach uses valuation techniques to measure fair value by converting future amounts, such as cash flows or earnings, into a single present value amount using current market expectations about those future amounts. The cost approach is based on the amount that would currently be required to replace the service capacity of an asset. This is often referred to as current replacement cost. The cost approach assumes that the fair value would not exceed what it would cost a market participant to acquire or construct a substitute asset of comparable utility, adjusted for obsolescence.
Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in

19


applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows: 
Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.
Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.
The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.
The Company’s current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company’s fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company’s historical incurrence of insignificant bad debt expense and the Company’s expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

20


The following table provides the assets and liabilities carried at fair value measured on a recurring basis at March 31, 2016 and December 31, 2015:
 
 
Balance at
 
Quoted prices in active markets
 
Significant other observable inputs
 
Unobservable inputs
(in millions)
 
March 31, 2016
 
(Level 1)
 
 (Level 2)
 
 (Level 3)
ASSETS
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
35.0

 
$
35.0

 
$

 
$

Other current assets
 
 
 
 
 
 
 
 
Derivative asset - current
 
5.6

 

 
5.6

 

Other assets
 
 
 
 
 
 
 
 
Derivative asset - long-term
 
0.1

 

 
0.1

 

 
 
$
40.7

 
$
35.0

 
$
5.7

 
$

LIABILITIES
 
 
 
 
 
 
 
 
Accrued liabilities
 
 
 
 
 
 
 
 
Derivative liability - current
 
$
9.5

 
$

 
$
9.5

 
$

 
 
$
9.5


$


$
9.5


$

 
 
Balance at
 
Quoted prices in active markets
 
Significant other observable inputs
 
Unobservable inputs
(in millions)
 
December 31, 2015
 
(Level 1)
 
 (Level 2)
 
 (Level 3)
ASSETS
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
70.9

 
$
70.9

 
$

 
$

Other current assets
 
 
 
 
 
 
 
 
Derivative asset - current
 
1.9

 

 
1.9

 

 
 
$
72.8


$
70.9


$
1.9


$

 
 
 
 
 
 
 
 
 
LIABILITIES
 
 
 
 
 
 
 
 
Accrued liabilities
 
 
 
 
 
 
 
 
Derivative liability - current
 
$
9.4

 
$

 
$
9.4

 
$

 
 
$
9.4

 
$

 
$
9.4

 
$

As of both March 31, 2016 and December 31, 2015, the Company had no Level 3 fair value assets or liabilities.
The Company’s policy is to recognize transfers in and transfers out as of the actual date of the event or of the change in circumstances that caused the transfer. For the three months ended March 31, 2016 and 2015, there were no transfers in or out of Levels 1, 2 or 3.
Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments, are recognized at fair value when they are impaired. During the three months ended March 31, 2016 and 2015, there were no impairments of such assets.
The carrying value of debt, which is reported on the Company’s condensed consolidated balance sheets, reflects the cash proceeds received upon issuance, net of subsequent repayments. The fair value of the 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1). 
 
 
March 31, 2016
 
December 31, 2015
(in millions)
 
Carrying Amount
 
Fair Value
 
Carrying Amount
 
Fair Value
2020 Secured Notes
 
$
342.5

 
$
344.8

 
$
342.0

 
$
360.5


21


13. ASSET RETIREMENT OBLIGATIONS
The following table summarizes the changes in asset retirement obligations: 
 
 
Three Months Ended
(in millions)
 
March 31, 2016
 
March 31, 2015
Asset retirement obligation balance at beginning of period
 
$
2.4

 
$
2.4

Costs incurred to remediate
 
(0.1
)
 
(0.2
)
Accretion expense
 
0.1

 
0.1

Asset retirement obligation balance at end of period
 
$
2.4

 
$
2.3

14. EQUITY-BASED COMPENSATION
The Company maintains an equity-based compensation plan designed to encourage employees and directors of the Company to achieve superior performance. The current plan is maintained by the general partner of NTE LP and is referred to as the LTIP. The Company recognized equity-based compensation expense of $4.6 million and $2.6 million for the three months ended March 31, 2016, and 2015, respectively, related to these plans. This expense is included in selling, general and administrative expenses in the condensed consolidated statements of operations and comprehensive income.
LTIP
Approximately 6.7 million NTE LP common units are reserved for issuance under the LTIP as of March 31, 2016. The LTIP permits the award of unit options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights and other awards that derive their value from the market price of NTE LP’s common units. As of March 31, 2016, approximately 1.5 million units were outstanding under the LTIP. The Company recognizes the expense on all LTIP awards ratably from the grant date until all units become unrestricted or vest. Service-based awards generally vest ratably over a three-year period beginning on the award's first anniversary date and performance-based awards generally vest following the end of the measurement period which, for the performance-based phantom awards, has traditionally been three years after the commencement of the measurement period. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, the Company estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.
As of March 31, 2016, the total unrecognized compensation cost for units awarded under the LTIP was $26.3 million.
Restricted Common Units
As of March 31, 2016, the Company had 0.2 million restricted common units outstanding. Upon vesting, these common units will no longer be restricted. All restricted common units participate in distributions on an equal basis with common units and must be paid no later than 30 days after the distribution date to common unitholders. For restricted common unit awards outstanding at March 31, 2016, the forfeiture rates on LTIP awards ranged from zero to 30%, depending on the employee classification and the length of the award's vesting period. The Company has one restricted common unit award which contains a clause that distributions are to be accrued until the underlying units vest at which time the accrued distributions applicable to those units will be paid to the award holder. The accrued distributions on that award at March 31, 2016 and December 31, 2015 were $0.8 million and $0.7 million, respectively.

22


A summary of the restricted common unit activity is set forth below: 
 
 
Number of
 
Weighted
 
Weighted
 
 
restricted common units
 
Average Grant
 
Average Term
 
 
(in thousands)
 
Date Value
 
Until Maturity
Nonvested at December 31, 2015
 
191.5

 
$
24.75

 
1.0

Vested
 
(34.1
)
 
26.84

 

Nonvested at March 31, 2016
 
157.4

 
$
24.30

 
0.8

Phantom Common Units
Service-based Phantom Common Units
In 2014, the Company began awarding service-based phantom common units to certain employees. As of March 31, 2016, the Company had 0.7 million service-based phantom common units outstanding. Upon vesting, the Company may settle these units in common units or cash, or a combination of both, in the discretion of the board of directors of NTE GP or its Compensation Committee. Like the restricted common units, the phantom common units participate in distributions on an equal basis with common units. However, distributions on phantom common units are accrued until the underlying units vest at which time the distributions are paid in cash. In the event that unvested phantom common units are forfeited or canceled, any accrued distributions on the underlying units are forfeited by the grantee. As of March 31, 2016 and December 31, 2015, the Company had $1.7 million and $2.5 million, respectively, in accrued service-based phantom common unit distributions included in both accrued liabilities and other liabilities in the condensed consolidated balance sheets. For phantom common unit awards outstanding at March 31, 2016, the forfeiture rates on LTIP awards ranged from zero to 20%, depending on the employee classification.
Performance-based Phantom Common Units
As of March 31, 2016, the Company had 0.7 million outstanding Performance-based Phantom Common Units, or Performance LTIPs, under the LTIP. Assuming a threshold EBITDA is achieved, participants are entitled to an award under the Performance LTIPs based on the Company’s achievement of two criteria compared to the performance peer group selected by the Compensation Committee over the performance period: (a) return on capital employed, referred to as a performance condition, and (b) total unitholder return, referred to as a market condition. The Company accounts for the performance conditions and market conditions in each Performance LTIPs as separate awards. Each of the performance condition awards and market condition awards represent the right to receive common units or cash, or a combination of both, in the discretion of the board of directors of NTE GP or its Compensation Committee at the end of a three-year performance period in an amount ranging from 0% to 200% of the original number of units granted, depending upon the Company’s achievement of the performance conditions and market conditions, respectively.
Performance Condition Awards. The 0.7 million Performance LTIPs include 0.3 million performance condition awards. The fair value of performance condition awards is estimated using the market price of the Company's common units on the grant date and management's assessment of the probability of the number of performance condition awards that will ultimately be awarded. The estimated fair value of these performance condition awards is amortized over a three-year vesting period using the straight-line method. On a quarterly basis, the Company estimates the ultimate payout percentage, relative to target, and adjusts compensation expense accordingly. At March 31, 2016, the Company estimates that a weighted average of 200% of the target unit count will be achieved at the end of the vesting term.
Market Condition Awards. The 0.7 million Performance LTIPs include 0.3 million market condition awards. The estimated fair value for market condition awards is estimated using a Monte Carlo simulation model as of the grant date and the related expense is amortized over a three-year vesting period using the straight-line method. The compensation expense relating to the market condition awards are determined at the award's grant date and expensed ratably at a fixed rate over the vesting term. However, for purposes of the Company's earnings per unit calculation (see Note 11) and the phantom common unit activity table below, the Company estimates that at March 31, 2016, a weighted average of 181% of the target unit count will be achieved at the end of the vesting term.

23


Expected volatilities are based on the historical volatility over the most recent three-year period. The risk-free rate is based on the U.S. Treasury yield curve in effect at the date of valuation. The assumptions used in the Monte Carlo simulation used to value our market condition awards as of March 31, 2016 are presented below:
 
 
2016 Awards
 
2015 Awards
Expected volatility
 
29.80
%
 
34.10
%
Risk-free interest rate
 
1.08
%
 
0.84
%
As of March 31, 2016 and December 31, 2015, the Company had $1.5 million and $1.0 million, respectively, in accrued performance-based phantom common unit distributions included in accrued liabilities in the condensed consolidated balance sheets.
A summary of all phantom common unit activity is set forth below: 
 
 
Number of phantom common units
 
Weighted
 
Weighted
 
 
(in thousands)
 
Average Grant
 
Average Term
 
 
Service-Based
 
Performance-Based
 
Total
 
Date Value
 
Until Maturity
Nonvested at December 31, 2015
 
581.9

 
260.7

 
842.6

 
$
24.00

 
1.5

Awarded
 
381.0

 
163.6

 
544.6

 
30.27

 
2.7

Incremental performance units
 

 
231.8

 
231.8

 
38.17

 
2.2

Forfeited
 
(0.5
)
 
(1.5
)
 
(2.0
)
 
24.01

 

Vested
 
(235.5
)
 
(1.8
)
 
(237.3
)
 
24.05

 

Nonvested at March 31, 2016
 
726.9

 
652.8

 
1,379.7

 
$
28.90

 
1.7

15. EMPLOYEE BENEFIT PLANS
Defined Contribution Plans
The Company sponsors one qualified defined contribution plan for eligible employees. Eligibility is based upon a minimum age requirement and a minimum level of service. Participants may make contributions of a percentage of their annual compensation subject to Internal Revenue Service limits. In 2016 the Company provides a non-matching contribution of 3.0% of eligible compensation and a matching contribution at the rate of 100% of a participant’s contribution up to 6.0%. Total Company contributions to the Retirement Savings Plans were $2.6 million and $2.2 million for the three months ended March 31, 2016 and 2015, respectively.
Cash Balance Plan
The Company sponsors a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Company contributions are made to the cash account of the participants equal to 5.0% of eligible compensation. Participants’ cash accounts also receive interest credits each year based upon the average thirty-year United States Treasury bond rate published in September preceding the respective plan year. Participants become fully-vested in their accounts after three years of service. The net periodic benefit cost related to the Cash Balance Plan for both the three months ended March 31, 2016 and 2015 was $0.6 million, related primarily to current period service costs.
16. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information is as follows: 
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Net cash from operating activities included:
 
 
 
Interest paid
$
0.8

 
$
0.6

 
 
 
 
Noncash investing and financing activities include:
 
 
 
Capital expenditures included in accounts payable
$
14.5

 
$
2.4

PP&E additions resulting from a capital lease
0.3

 

Distributions accrued on unvested equity awards
4.0

 
3.7


24


17. COMMITMENTS AND CONTINGENCIES
The Company is the subject of, or party to, contingencies and commitments involving a variety of matters. Certain of these matters are discussed below. While the results of these commitments and contingencies cannot be predicted with certainty, the Company believes that the final resolution of the foregoing would not, individually or in the aggregate, have a material adverse effect on the Company’s consolidated financial statements as a whole.
Legal Matters
On February 20, 2015, a customer served a complaint in the United States District Court for the District of Minnesota alleging violations of the Telephone Consumer Protection Act. The plaintiff purports to bring the action also on behalf of others similarly situated and seeks statutory penalties, injunctive relief, and other remedies. The Company is vigorously defending itself. This action is in its preliminary stages.
Environmental Matters
The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At March 31, 2016 and December 31, 2015, accruals for remediation and closure obligations totaled $8.5 million and $8.6 million, respectively. Of the $8.5 million and $8.6 million accrued, $2.5 million and $2.6 million are recorded on a discounted basis at March 31, 2016 and December 31, 2015, respectively. These discounted liabilities are expected to be settled over at least the next 22 years. At March 31, 2016, the estimated future cash flows to settle these discounted liabilities totaled $3.0 million, and are discounted at a rate of 2.27%. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.1 million and $0.2 million at March 31, 2016 and December 31, 2015, respectively. Costs associated with environmental remediation are recorded in direct operating expenses in the statement of operations.
On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency ("MPCA") relating to its upgraded wastewater treatment plant at its St. Paul Park refinery. This permit required the refinery to conduct additional testing of its remaining lagoon. The testing was completed in the fourth quarter of 2014 and following the Company's review of the test results and additional discussions with the MPCA, the Company plans to close the remaining lagoon. The MPCA accepted the Company's remediation plan in the four quarter of 2015. At both March 31, 2016 and December 31, 2015, the Company estimates the remaining remediation costs to be approximately $6.0 million, subject to receiving final bids from contractors. In connection with the Company's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon Petroleum Company LP ("Marathon"), the Company entered into an agreement with Marathon which required Marathon to share in the future remediation costs of this Lagoon, should they be required. During the three months ended September 30, 2015, the Company entered into a settlement and release agreement with Marathon and received $3.5 million pursuant to this settlement which was recorded as a reduction of direct operating expenses.
Franchise Agreements
In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.
18. SEGMENT INFORMATION
The Company has two reportable operating segments: Refining and Retail. Each of these segments is organized and managed based upon the nature of the products and services they offer. The segment disclosures reflect management’s current organizational structure.
Refining – operates the St. Paul Park, Minnesota refinery, terminal, NTOT and related assets, and includes the Company’s interest in MPL and MPLI, and
Retail – operates 169 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

25


Operating results for the Company’s operating segments are as follows:
 
 
Three Months Ended March 31, 2016
(in millions)
 
Refining
 
Retail
 
Other
 
Total
Revenues
 
 
 
 
 
 
 
 
Customer
 
$
381.6

 
$
222.8

 
$

 
$
604.4

Intersegment
 
113.7

 

 

 
113.7

Segment revenues
 
495.3

 
222.8

 

 
718.1

Elimination of intersegment revenues
 

 

 
(113.7
)
 
(113.7
)
Total revenues
 
$
495.3

 
$
222.8

 
$
(113.7
)
 
$
604.4

 
 
 
 
 
 
 
 
 
Income (loss) from operations
 
$
28.1

 
$
1.7

 
$
(8.0
)
 
$
21.8

Income from equity method investment
 
$
5.5

 
$

 
$

 
$
5.5

Depreciation and amortization
 
$
9.0

 
$
2.2

 
$
0.1

 
$
11.3

Capital expenditures
 
$
26.4

 
$
1.5

 
$

 
$
27.9

 
 
Three Months Ended March 31, 2015
(in millions)
 
Refining
 
Retail
 
Other
 
Total
Revenues
 
 
 
 
 
 
 
 
Customer
 
$
545.1

 
$
248.7

 
$

 
$
793.8

Intersegment
 
144.5

 

 

 
144.5

Segment revenues
 
689.6

 
248.7

 

 
938.3

Elimination of intersegment revenues
 

 

 
(144.5
)
 
(144.5
)
Total revenues
 
$
689.6

 
$
248.7

 
$
(144.5
)
 
$
793.8

 
 
 
 
 
 
 
 
 
Income (loss) from operations
 
$
123.1

 
$
2.7

 
$
(6.3
)
 
$
119.5

Income from equity method investment
 
$
3.6

 
$

 
$

 
$
3.6

Depreciation and amortization
 
$
8.7

 
$
1.8

 
$
0.3

 
$
10.8

Capital expenditures
 
$
4.6

 
$
1.9

 
$
0.1

 
$
6.6


Intersegment sales from the refining segment to the retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market-based. Revenues from external customers are nearly all in the United States.
Total assets by segment were as follows: 
(in millions)
 
Refining
 
Retail
 
Other
 
Total
At March 31, 2016
 
$
970.0

 
$
135.4

 
$
44.0

 
$
1,149.4

 
 
 
 
 
 
 
 
 
At December 31, 2015
 
$
917.4

 
$
138.7

 
$
81.2

 
$
1,137.3

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included in Other. All property, plant and equipment are located in the United States.
19. PROPOSED MERGER TRANSACTION
On December 21, 2015, NTI entered into the Merger Agreement, by and among Western Refining MergerCo, NTI and NTE GP. Upon the terms and subject to the conditions set forth in the Merger Agreement, MergerCo will merge with and into NTI, the separate limited liability company existence of MergerCo will cease and NTI will continue to exist as a limited partnership under Delaware law as the surviving entity in the Merger.
NT InterHoldCo owns 100% of the membership interests in NTE GP and approximately 38.3% of NTI’s outstanding common units representing limited partner interests in NTI (“NTI Common Units”). NT InterHoldCo also owns 100% of the

26


membership interests in Western Acquisition Holdings, LLC, a Delaware limited liability company and holder of 100% of the membership interests in MergerCo (“MergerCo HoldCo”). Following the Merger, NTE GP will remain the sole general partner of NTI, the NTI Common Units held by Western Refining and its subsidiaries will be unchanged and remain issued and outstanding, and, by virtue of the Merger, all of the membership interests in MergerCo will automatically be converted into the number of NTI Common Units (excluding any NTI Common Units held by Western Refining and its subsidiaries) issued and outstanding immediately prior to the Effective Time. Consequently, NT InterHoldCo and its wholly-owned subsidiary, MergerCo HoldCo, will become the sole limited partners of NTI. At the Effective Time, each of the outstanding NTI Common Units held by the NTI Public Unitholders will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of Western Refining’s common stock, par value $0.01 per share (“Western Refining Common Stock”) (the “Standard Mix of Consideration”), (ii) $26.06 in cash without interest (the “Cash Election”), or (iii) 0.7036 of a share of Western Common Stock (the “Stock Election”). The Cash and Stock Elections will be subject to proration to ensure that the total amount of cash paid and the total number of shares of Western Refining Common Stock issued and delivered (which may include shares of Western Refining Common Stock held in treasury by Western Refining and reissued) in the Merger to NTI Public Unitholders as a whole are equal to the total amount of cash and number of shares of Western Refining Common Stock that would have been paid and issued if all NTI Public Unitholders received the Standard Mix of Consideration. The transaction is expected to result in the payment and delivery of approximately $862.3 million in cash and 17.2 million shares of Western Refining Common Stock to the NTI Public Unitholders.
The parties anticipate that the Merger will close in the second quarter of 2016, pending the satisfaction of certain customary conditions thereto. Pursuant to the terms of the Merger Agreement, with respect to the quarter in which the Closing Date occurs NTI will, to the extent it generates available cash in such quarter, make a prorated quarterly cash distribution to all NTI common unitholders, including NT InterHoldCo, for the portion of the quarter that NTI Public Unitholders own NTI Common Units prior to the Closing Date, in the event that NTI Public Unitholders who receive Western Refining Common Stock in the Merger would not receive a dividend with respect to the Western Refining Common Stock received in the Merger, due to the record date for such dividend occurring before the Closing Date. Any prorated quarterly distribution for the quarter in which the Closing Date occurs would be paid to NTI Public Unitholders as of the Effective Time for the Merger, together with the merger consideration payable with respect to the Merger.
The Merger Agreement contains customary representations, warranties, covenants and agreements by each of the parties. Completion of the Merger is conditioned upon, among other things: (1) approval of the Merger Agreement and the transactions contemplated by the Merger Agreement, including the Merger (the “Merger Transactions”), by the affirmative vote of NTI common unitholders holding a majority of the outstanding NTI Common Units as of the close of business on the May 19, 2016, record date, at a special meeting of NTI common unitholders currently scheduled to take place at 9:00 AM Tempe, Arizona time on June 23, 2016; (2) any waiting period applicable to the Merger Transactions under the Hart-Scott-Rodino Antitrust Act of 1976, as amended (the “HSR Act”) having been terminated or expired; (3) all filings, consents, approvals, permits and authorizations required to be made or obtained prior to the Effective Time in connection with the Merger Transactions having been made or obtained; (4) the absence of legal injunctions or impediments prohibiting the Merger Transactions; (5) the effectiveness of a registration statement on Form S-4 (the “Registration Statement”) with respect to the issuance of new shares of Western Refining Common Stock in the Merger; and (6) approval of the listing on the New York Stock Exchange, subject to official notice of issuance, of the new shares of Western Refining Common Stock to be issued and delivered (or, to the extent held in treasury by Western Refining, delivered but not issued) in the Merger. On January 29, 2016, the United States Federal Trade Commission granted early termination of the waiting periods applicable to the Merger Transactions under the HSR Act.
The NTE GP Conflicts Committee, acting for NTE GP in its capacity as the general partner of NTI, approved the Merger Agreement and the Merger Transactions, and determined that the Merger Agreement and the Merger Transactions are fair and reasonable to NTI and the NTI Public Unitholders and are not adverse to the interests of NTI or the interests of the NTI Public Unitholders. The Board of Directors of Western Refining has also approved the Merger Agreement and the Merger Transactions.
On January 19, 2016, Western Refining filed with the Securities and Exchange Commission (the “SEC”) a preliminary registration statement on Form S-4 (the “Preliminary S-4”) to register the shares of Western Refining Common Stock to be issued and delivered (or, to the extent held in treasury by Western Refining, delivered but not issued) in the Merger, and subsequently filed with the SEC Amendments No. 1 and No. 2 to the Preliminary S-4 on March 18, 2016 and April 19, 2016, respectively. On each respective filing date, the parties to the Merger Agreement jointly filed with the SEC a transaction statement on Schedule 13E-3 which discloses the material terms of the Merger Transactions (the “Schedule 13E-3”). Both the Preliminary S-4 and the Schedule 13E-3 are currently under review by the SEC and subject to future amendments.

ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

27


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 Report. 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. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements.”
Overview
We are an independent downstream energy limited partnership with refining, retail and logistics operations that serves the PADD II region of the United States. We operate our assets in two business segments: the refining business and the retail business. For the three months ended March 31, 2016, we had total revenues of $604.4 million, operating income of $21.8 million, net income of $14.7 million and Adjusted EBITDA of $28.2 million. Adjusted EBITDA is a non-GAAP financial measure. A definition and reconciliation of Adjusted EBITDA to net income, the most directly comparable GAAP measure, is included herein under the caption “Adjusted EBITDA.”
Proposed Merger with Western Refining
On December 21, 2015, we and our general partner entered into the Merger Agreement with Western Refining and MergerCo, pursuant to which Western Refining will acquire all of NTI’s outstanding common units not already held by Western Refining. Each of the outstanding NTI common units held by the NTI Public Unitholders will be converted into the right to receive, subject to election by the NTI Public Unitholders and proration, (i) $15.00 in cash without interest and 0.2986 of a share of Western Refining common stock; (ii) $26.06 in cash without interest; or (iii) 0.7036 of a share of Western Refining common stock. The election will be subject to proration to ensure that the aggregate cash paid and Western Refining common stock issued in the Merger will equal the total amount of cash and number of shares of Western Refining common stock that would have been paid and delivered if all NTI Public Unitholders received $15.00 in cash and 0.2986 of a share of Western Refining common stock per Northern Tier common unit. The Merger is expected to close in the second quarter of 2016, pending the satisfaction of certain customary conditions and the approval of the Merger at a special meeting of NTI unitholders that has been called by NTI to be held on June 23, 2016. The transaction is expected to result in approximately 17.2 million additional shares of WNR common stock outstanding. Upon completion of the transaction, NTI will continue to exist as a limited partnership and will become a wholly-owned limited partnership subsidiary of WNR. See Note 19, Proposed Merger Transaction, in the Notes to Consolidated Financial Statements included in this quarterly report for additional information on this transaction.
Refining Business
Our refining business primarily consists of a refinery located in St. Paul Park, Minnesota with total crude oil throughput capacity of 97,800 barrels per stream day. We are one of five 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 often 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.
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. We operate a crude oil transportation business in North Dakota that allows us to purchase crude oil at the wellhead in the Bakken Shale area. Our refining business also includes our 17% interest in MPL and MPLI, which own and operate the Minnesota Pipeline, a 465,000 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. We assumed operational responsibility for an 8.6 mile eight-inch refined products pipeline, referred to as the Aranco Pipeline, in March 2016.
Retail Business
As of March 31, 2016, our retail business operated 169 convenience stores under the SuperAmerica brand and also supported 114 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

28


refinery supplies a majority of the gasoline and diesel sold in our company-operated stores and franchised convenience stores within our distribution area.
We also own and operate SuperMom’s bakery and commissary, 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.
Results of 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.
Consolidated Financial Data
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Revenue
$
604.4

 
$
793.8

Costs, expenses and other:
 
 
 
Cost of sales
474.2

 
576.5

Direct operating expenses
78.3

 
69.3

Turnaround and related expenses
0.4

 
0.4

Depreciation and amortization
11.3

 
10.8

Selling, general and administrative expenses
23.3

 
20.2

Merger-related expenses
0.4

 

Income from equity method investment
(5.5
)
 
(3.6
)
Other loss
0.2

 
0.7

Operating income
21.8

 
119.5

Interest expense, net
(6.5
)
 
(7.5
)
Income before income taxes
15.3


112.0

Income tax provision
(0.6
)
 
(0.8
)
Net income
$
14.7

 
$
111.2

Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Revenue. Revenue for the three months ended March 31, 2016 was $604.4 million compared to $793.8 million for the three months ended March 31, 2015, a decrease of 23.9%. Refining segment revenue decreased 28.2% and retail segment revenue decreased 10.4% compared to the three months ended March 31, 2015. Refining revenue decreased primarily due to lower refined product prices due to market conditions, partially offset by increased sales volumes of 0.6% in the 2016 period. Retail revenue decreased primarily due to lower fuel prices due to market conditions, partially offset by an increase in fuel gallons sold of 1.7%. Additionally, the overall decrease in retail sales was partially offset by $3.4 million higher merchandise and other revenue. Excise taxes included in revenue increased by $11.0 million for the 2016 period over the 2015 period.
Cost of sales. Cost of sales totaled $474.2 million for the three months ended March 31, 2016 compared to $576.5 million for the three months ended March 31, 2015, a decrease of 17.7%. Refining segment cost of sales decreased 20.1% and retail segment cost of sales decreased 14.3% compared to the three months ended March 31, 2015. The decrease in the refining segment was primarily due to lower crude oil costs and a $11.0 million benefit from a lower of cost or market inventory adjustment, partially offset by an increase of 0.6% in refining sales volumes. The decreased cost of sales in the retail segment was primarily due to lower costs of fuel products. Lastly, excise taxes included in cost of sales increased by $11.0 million for the 2016 period over the 2015 period.
Direct operating expenses. Direct operating expenses totaled $78.3 million for the three months ended March 31, 2016 compared to $69.3 million for the three months ended March 31, 2015, an increase of 13.0%, due primarily to higher spending on refinery maintenance projects due to the more temperate weather experienced in the 2016 period compared to the 2015 period. The higher direct operating expenses were also driven by higher personnel costs in our retail segment in the 2016 period. These increases in costs were partially offset by reduced utilization of third party trucking firms in North Dakota due primarily to a shift in 2016 whereby we are purchasing more crude oil from barrels already on the pipeline or at storage facilities as opposed to at the wellhead.

29


Turnaround and related expenses. Turnaround and related expenses totaled $0.4 million for the three months ended March 31, 2016 compared to $0.4 million for the three months ended March 31, 2015. The turnaround costs in the three months ended March 31, 2016 include turnaround and related costs incurred in the refining segment on planning for the anticipated fall 2016 turnaround of our No. 2 crude unit. Such costs in the corresponding 2015 period relate to planning costs for a third quarter 2015 turnaround on our sulfur recovery unit.
Depreciation and amortization. Depreciation and amortization was $11.3 million for the three months ended March 31, 2016 compared to $10.8 million for the three months ended March 31, 2015, an increase of 4.6%. This increase was due primarily to increased refining assets placed in service since March 31, 2015, the most significant of which were improvements to a firewater system, truck loading terminal and parking facilities, all within the refining segment, along with retail stores acquired under capital leases within our retail segment.
Selling, general and administrative expenses. Selling, general and administrative expenses were $23.3 million for the three months ended March 31, 2016 compared to $20.2 million for the three months ended March 31, 2015. This increase of 15.3% relates primarily to higher equity-based compensation expense resulting from new grants and performance award adjustments.
Merger-related expenses. Legal and advisory costs of $0.4 million were incurred during the three months ended March 31, 2016 as a result of the Merger Agreement with Western Refining. No such costs were incurred during the 2015 period.
Income from equity method investment. Income from equity method investment was $5.5 million for the three months ended March 31, 2016 compared to $3.6 million for the three months ended March 31, 2015. This increase was driven by higher equity income from MPL due to reduced spending on maintenance projects on the pipeline in the 2016 period.
Other loss. Other loss was a $0.2 million loss for the three months ended March 31, 2016 compared to $0.7 million loss for the three months ended March 31, 2015, driven primarily by losses resulting from unfavorable fluctuations in the exchange rate between our reporting currency, the U.S. dollar and the Canadian dollar in the 2015 period.
Interest expense, net. Interest expense, net was $6.5 million for the three months ended March 31, 2016 and $7.5 million for the three months ended March 31, 2015. This decrease relates primarily to the $1.3 million higher capitalization of interest expense on several large capital projects within the refining segment, partially offset by higher interest costs on borrowings under our ABL Facility in the 2016 period.
Income tax provision. The income tax provision for the three months ended March 31, 2016 was $0.6 million compared to $0.8 million for the three months ended March 31, 2015. This decrease was due primarily to lower income generated by our retail segment.
Net income. Our net income was $14.7 million for the three months ended March 31, 2016 compared to $111.2 million for the three months ended March 31, 2015. This decrease in net income is primarily attributable to a $87.1 million decrease in gross profit, a $9.0 million increase in direct operating expenses and a $3.1 million increase selling, general and administrative expenses. These unfavorable factors were partially offset by $1.9 million higher income from our equity method investment in MPL and other cost savings.
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.
 
 
Three Months Ended March 31, 2016
(in millions)
 
Refining
 
Retail
 
Other/Elim
 
Consolidated
Revenue:
 
 
 
 
 
 
 
 
Sales and other revenue
 
$
381.6

 
$
222.8

 
$

 
$
604.4

Intersegment sales
 
113.7

 

 
(113.7
)
 

Segment revenue
 
$
495.3

 
$
222.8

 
$
(113.7
)
 
$
604.4

Cost of sales:
 
 
 
 
 
 
 
 
Cost of sales
 
$
410.3

 
$
63.9

 
$

 
$
474.2

Intersegment purchases
 

 
113.7

 
(113.7
)
 

Segment cost of sales
 
$
410.3

 
$
177.6

 
$
(113.7
)
 
$
474.2


30


 
 
Three Months Ended March 31, 2015
(in millions)
 
Refining
 
Retail
 
Other/Elim
 
Consolidated
Revenue:
 
 
 
 
 
 
 
 
Sales and other revenue
 
$
545.1

 
$
248.7

 
$

 
$
793.8

Intersegment sales
 
144.5

 

 
(144.5
)
 

Segment revenue
 
$
689.6

 
$
248.7

 
$
(144.5
)
 
$
793.8

Cost of sales:
 
 
 
 
 
 
 
 
Cost of sales
 
$
513.7

 
$
62.8

 
$

 
$
576.5

Intersegment purchases
 

 
144.5

 
(144.5
)
 

Segment cost of sales
 
$
513.7

 
$
207.3

 
$
(144.5
)
 
$
576.5



31


Refining Segment
 
Three Months Ended
(in millions)
March 31, 2016

March 31, 2015
Revenue
$
495.3

 
$
689.6

Costs, expenses and other:
 
 
 
Cost of sales
410.3

 
513.7

Direct operating expenses
44.4

 
38.9

Turnaround and related expenses
0.4

 
0.4

Depreciation and amortization
9.0

 
8.7

Selling, general and administrative expenses
8.7

 
8.0

Income from equity method investment
(5.5
)
 
(3.6
)
Other (gain) loss
(0.1
)
 
0.4

Operating income
$
28.1

 
$
123.1

Key Operating Statistics
 
 
 
Refining gross margin (in millions)(3)
$
85.0

 
$
175.9

Total refinery production (bpd)(1)
100,793

 
94,312

Total refinery throughput (bpd)
100,609

 
94,108

Refined products sold (bpd)(2)
99,094

 
98,481

Per barrel of throughput:
 
 
 
Refining gross margin(3)
$
9.28

 
$
20.77

Refining gross margin excluding lower of cost or market inventory adjustment(4)
$
8.08

 
$
19.53

Direct operating expenses(5)
$
4.85

 
$
4.59

Per barrel of refined products sold:
 
 
 
Refining gross margin(3)
$
9.43

 
$
19.85

Direct operating expenses(5)
$
4.92

 
$
4.39

Refinery product yields (bpd):
 
 
 
Gasoline
49,707

 
44,958

Distillate(6)
33,639

 
33,257

Asphalt
11,662

 
10,093

Other(7)
5,785

 
6,004

Total
100,793

 
94,312

Refinery throughput (bpd):
 
 
 
Crude oil
96,349

 
91,540

Other feedstocks(8)
4,260

 
2,568

Total
100,609

 
94,108

 
(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 margin is calculated by subtracting refining costs of sales from total refining revenues. Refining gross 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 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 margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.” Refining gross margin per barrel is a per barrel measurement calculated by dividing refining gross margin by the total throughput or total refined products sold for the respective periods presented.

32


(4)
Represents refining gross margin calculated as described in footnote (3), except that refining cost of sales excludes the non-cash adjustment to record inventory at the lower of cost or market ("LCM") where cost is determined using the last-in, first-out ("LIFO") methodology. Our LCM reserve within the refining segment was $121.3 million and $132.3 million as of March 31, 2016 and December 31, 2015, respectively, resulting in non-cash gain of $11.0 million, recorded within cost of sales for the three months ended March 31, 2016. As of March 31, 2015 and December 31, 2014, our LCM reserve within the refining segment was $61.7 million and $72.2 million, respectively, resulting in a non-cash gain of $10.5 million for the three months ended March 31, 2015.
(5)
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.
(6)
Distillate includes diesel, jet fuel, light cycle oil and kerosene.
(7)
Other refinery products include propane, propylene, liquid sulfur and No. 6 fuel oil, among others. None of these products, by itself, contributes significantly to overall refinery product yields.
(8)
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.
Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Refining gross margin. Refining gross margin for the three months ended March 31, 2016 was $85.0 million compared to $175.9 million for the three months ended March 31, 2015, a decrease of 51.7%. This decrease in gross margin was caused primarily by lower crack spreads on our barrels sold in the 2016 period. This decrease was partially offset by an $11.0 million benefit from a decrease in our LCM reserve and 0.6% higher sales volumes during the three months ended March 31, 2016.
Direct operating expenses. Direct operating expenses totaled $44.4 million for the three months ended March 31, 2016 compared to $38.9 million for the three months ended March 31, 2015, a 14.1% increase. This increase was due primarily to higher spending on refinery maintenance projects due to the more temperate weather experienced in the 2016 period compared to the 2015 period. These increases in costs were partially offset by reduced utilization of third party trucking firms in North Dakota due primarily to a shift in 2016 whereby we are making more of our crude purchases from barrels already on the pipeline or at storage facilities as opposed to at the wellhead.
Turnaround and related expenses. Turnaround and related expenses totaled $0.4 million for the three months ended March 31, 2016 compared to $0.4 million for the three months ended March 31, 2015. The turnaround costs in the three months ended March 31, 2016 include turnaround and related costs incurred in the refining segment on planning for the anticipated fall 2016 turnaround of our No. 2 crude unit. Such costs in the corresponding 2015 period relate to planning costs for a third quarter 2015 turnaround on our sulfur recovery unit.
Depreciation and amortization. Depreciation and amortization was $9.0 million for the three months ended March 31, 2016 compared to $8.7 million for the three months ended March 31, 2015, an increase of 3.4%. This increase was due primarily to increased refining assets placed in service since March 31, 2015, the most significant of which were improvements to a firewater system, truck loading terminal and parking facilities, all of which are at our refinery.
Selling, general and administrative expenses. Selling, general and administrative expenses were $8.7 million and $8.0 million for the three months ended March 31, 2016 and 2015, respectively. This increase was driven primarily by higher equity-based compensation expense.
Income from equity method investment. Income from equity method investment was $5.5 million for the three months ended March 31, 2016 compared to $3.6 million for the three months ended March 31, 2015. This increase was driven by higher equity income from MPL due to reduced spending on maintenance projects on the pipeline in the 2016 period.
Other (gain) loss. Other (gain) loss was $0.1 million gain for the three months ended March 31, 2016 compared to $0.4 million loss for the three months ended March 31, 2015 driven primarily by losses resulting from unfavorable fluctuations in the exchange rate between our reporting currency, the U.S. dollar and the Canadian dollar in the 2015 period.
Operating income. Income from operations was $28.1 million for the three months ended March 31, 2016 compared to $123.1 million for the three months ended March 31, 2015. This decrease from the prior-year period of $95.0 million is primarily due to lower refinery gross margin of $90.9 million and $1.9 million higher income from our equity method investment in MPL, partially offset by higher direct operating expenses of $5.5 million.

33


Retail Segment
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Revenue
$
222.8

 
$
248.7

Costs, expenses and other:
 
 
 
Cost of sales
177.6

 
207.3

Direct operating expenses
33.9

 
30.4

Depreciation and amortization
2.2

 
1.8

Selling, general and administrative expenses
7.4

 
6.5

Operating income
$
1.7

 
$
2.7

Operating data:
 
 
 
Retail gross margin(1)
$
45.2

 
$
41.4

Company-operated stores:
 
 
 
Fuel gallons sold (in millions)
73.1

 
71.9

Fuel margin per gallon excluding lower of cost or market inventory adjustment(3)
$
0.24

 
$
0.21

Fuel margin per gallon(2)
$
0.24

 
$
0.21

Merchandise sales
$
84.2

 
$
82.6

Merchandise margin %(4)
26.1
%
 
25.9
%
Number of stores at period end
169

 
165

Franchise stores:
 
 
 
Fuel gallons sold (in millions)(5)
28.8

 
23.3

Royalty income
$
1.0

 
$
0.8

Number of stores at period end
114

 
95

(1)
Retail gross margin is calculated by subtracting retail costs of sales from total retail revenues. Retail gross 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 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 margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures."
(2)
Fuel margin per gallon is calculated by dividing fuel margin by the fuel gallons sold at company-operated stores. Fuel margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of fuel margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of fuel margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.”
(3)
Represents retail gross margin calculated as described in footnote (1), except that retail cost of sales excludes the non-cash adjustment to record inventory at LCM where cost is determined using the LIFO methodology. As of March 31, 2015 and December 31, 2014, our LCM reserve within the retail segment was $1.1 million and $1.4 million, respectively, resulting in a non-cash gain of $0.3 million for the three months ended March 31, 2015. Our LCM reserve within the retail segment did not change during the three months ended March 31, 2016.
(4)
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.”
(5)
Represents fuel gallons sold to franchised stores by our St. Paul Park refinery.

34


Three Months Ended March 31, 2016 Compared to the Three Months Ended March 31, 2015
Retail gross margin. Retail gross margin for the three months ended March 31, 2016 was $45.2 million compared to $41.4 million for the three months ended March 31, 2015, an increase of 9.2%. This increase was primarily due to $0.03 higher fuel margins per gallon at our company-operated stores and higher non-fuel margin of $1.8 million. Additionally, fuel volumes at both our company-operated stores and franchised stores, increased 7.0% as we expanded our company-operated locations by four stores and our franchised locations by 19 stores.
Direct operating expenses. Direct operating expenses totaled $33.9 million and $30.4 million for the three months ended March 31, 2016 and 2015, respectively. This increase was due primarily to higher personnel costs due to a Minnesota state mandated increase in the minimum wage in mid-2015. Additionally, the retail segment incurred higher store lease expense during the 2016 period due to both additional company-operated stores and lease renewals at higher monthly rates.
Depreciation and amortization. Depreciation and amortization was $2.2 million and $1.8 million for the three months ended March 31, 2016 and 2015, respectively. This increase was primarily due new assets placed in service since March 31, 2015 such as stores acquired under capital leases and facility improvements at existing stores.
Selling, general and administrative expenses. Selling, general and administrative expenses were $7.4 million and $6.5 million for the three months ended March 31, 2016 and 2015, respectively, an increase of 13.8%. The increase relates primarily to higher personnel costs and equity-based compensation expense in the three months ended March 31, 2016.
Operating income. Operating income was $1.7 million for the three months ended March 31, 2016 compared to $2.7 million for the three months ended March 31, 2015, a decrease of $1.0 million. The decrease is primarily attributable to higher gross margins of $3.8 million during the three months ended March 31, 2016, partially offset by higher direct operating expenses of $3.5 million and higher selling, general administrative expenses of $0.9 million.
Adjusted EBITDA
Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with the board of directors of our general partner, creditors, analysts and investors concerning our financial performance. We also believe Adjusted EBITDA may be used by some investors to assess the ability of our assets to generate sufficient cash flow to make distributions to our unitholders. The ABL Facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.
Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our secured notes and the ABL Facility. Adjusted EBITDA should not be considered as an alternative to operating earnings or net earnings as measures of operating performance. In addition, Adjusted EBITDA is not presented as and should not be considered an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before turnaround and related expenses, lower of cost or market inventory adjustments, equity-based compensation expense, merger-related expenses, losses on extinguishment of debt 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 turnaround and other related expenses that other companies in our industry capitalize and amortize over the related turnaround interval period;
does not reflect certain other non-cash income and expenses including inventory lower of cost or market adjustments, if applicable and equity-based compensation expense; and
excludes income taxes that may represent a reduction in available cash.

35


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:
 
 
Three Months Ended March 31, 2016
(in millions)
 
Refining  
 
Retail  
 
Other  
 
Total  
Net income (loss)
 
$
28.1

 
$
1.1

 
$
(14.5
)
 
$
14.7

Adjustments:
 
 
 
 
 
 
 
 
Interest expense
 

 

 
6.5

 
6.5

Income tax provision
 

 
0.6

 

 
0.6

Depreciation and amortization
 
9.0

 
2.2

 
0.1

 
11.3

EBITDA subtotal
 
37.1

 
3.9

 
(7.9
)
 
33.1

Lower of cost or market inventory adjustment (a)
 
(11.0
)
 

 

 
(11.0
)
MPL proportionate depreciation expense
 
0.7

 

 

 
0.7

Turnaround and related expenses
 
0.4

 

 

 
0.4

Equity-based compensation expense
 
1.3

 
0.3

 
3.0

 
4.6

Merger-related expenses
 

 

 
0.4

 
0.4

Adjusted EBITDA
 
$
28.5

 
$
4.2

 
$
(4.5
)
 
$
28.2

 
 
Three Months Ended March 31, 2015
(in millions)
 
Refining  
 
Retail  
 
Other  
 
Total  
Net income (loss)
 
$
123.1

 
$
1.9

 
$
(13.8
)
 
$
111.2

Adjustments:
 
 
 
 
 
 
 
 
Interest expense
 

 

 
7.5

 
7.5

Income tax provision
 

 
0.8

 

 
0.8

Depreciation and amortization
 
8.7

 
1.8

 
0.3

 
10.8

EBITDA subtotal
 
131.8

 
4.5

 
(6.0
)
 
130.3

Lower of cost or market inventory adjustment (a)
 
(10.5
)
 
(0.3
)
 

 
(10.8
)
MPL proportionate depreciation expense
 
0.7

 

 

 
0.7

Turnaround and related expenses
 
0.4

 

 

 
0.4

Equity-based compensation expense
 
0.6

 
0.1

 
1.9

 
2.6

Adjusted EBITDA
 
$
123.0

 
$
4.3

 
$
(4.1
)
 
$
123.2

 
 
 
 
 
 
 
 
 
(a) Represents the non-cash adjustment to record inventory at the lower of cost or market, where cost is determined using the last-in, first-out cost flow method.
Other Non-GAAP Performance Measures
Refining gross 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 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 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 margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

36


The following table shows the reconciliation of refining gross 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 condensed consolidated statements of operations and comprehensive income is included above in “Segment Financial Data.”
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Refining revenue
$
495.3

 
$
689.6

Refining cost of sales
410.3

 
513.7

Refining gross margin
$
85.0

 
$
175.9

Retail fuel margin and merchandise margin are non-GAAP measures that we believe are important to investors in evaluating our retail segment’s operating results as these measures provide an indication of our performance on significant product categories within the segment. Our calculation of fuel margin and merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.
The following table shows the reconciliations of fuel margin and merchandise margin to retail revenue and retail cost of sales for the periods indicated. A reconciliation of retail revenue and retail cost of sales to consolidated revenue and cost of sales in our condensed consolidated statements of operations and comprehensive income is included above in “Segment Financial Data.”
 
Three Months Ended
(in millions)
March 31, 2016
 
March 31, 2015
Retail revenue:
 
 
 
Fuel revenue
$
133.0

 
$
161.5

Merchandise revenue
84.2

 
82.6

Other revenue
10.7

 
8.9

Intercompany eliminations
(5.1
)
 
(4.3
)
Retail revenue
222.8

 
248.7

 
 
 
 
Retail cost of sales:
 
 
 
Fuel cost of sales
115.8

 
146.3

Merchandise cost of sales
62.2

 
61.2

Other cost of sales
4.7

 
4.1

Intercompany eliminations
(5.1
)
 
(4.3
)
Retail cost of sales
177.6

 
207.3

 
 
 
 
Retail gross margin:
 
 
 
Fuel margin
17.2

 
15.2

Merchandise margin
22.0

 
21.4

Other margin
6.0

 
4.8

Intercompany eliminations

 

Retail gross margin
$
45.2

 
$
41.4

Liquidity and Capital Resources
Our primary sources of liquidity have traditionally been cash generated from our operating activities and availability under our ABL Facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing and selling sufficient quantities of refined products and merchandise at margins sufficient to cover fixed and variable expenses. We may make strategic investments with the objective of increasing cash available for distribution to our unitholders. These strategic investments would be financed via debt or equity issuances or the sale of certain assets. Our ability to make these investments in the future will depend largely on the availability of debt financing, our ability to periodically use equity financing through the issuance of new common units or the ability to sell certain assets. Future financing will depend on various factors, including prevailing market conditions, interest rates and our

37


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 ABL Facility, see “Description of Our Indebtedness—Senior Secured Asset-Based Revolving Credit Facility.”
On September 29, 2014, we entered into an amended and restated ABL Facility with JPMorgan Chase Bank, N.A., as administrative agent for the lenders and as collateral agent for the other secured parties. The borrowers under the ABL Facility are SPPR, NTB, NTR and SAF, each of which is one of our wholly owned subsidiaries. Lenders under the ABL Facility hold commitments totaling $500.0 million, all of which mature on September 29, 2019. Borrowing availability under the ABL Facility is tied to a borrowing base dependent upon the amount of eligible accounts receivable and inventory. As of March 31, 2016, the borrowers under the ABL Facility had $22.5 million in outstanding balance under the ABL Facility. The borrowing base under the ABL Facility was $186.6 million and availability under the ABL Facility was $134.7 million (which is net of $29.4 million in outstanding letters of credit and $22.5 million in direct borrowings).
As of March 31, 2016, we had $350.0 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). A portion of these notes were issued with an offering premium of $4.2 million, which is being amortized to Interest expense, net over the remaining term of the notes. Additionally, professional service costs were incurred in the both the issuance of the 2020 Secured Notes and the establishment of the ABL Facility which are presented within Long-term debt in the Consolidated Balance Sheets. The carrying value of these costs at March 31, 2016 was $10.9 million.
Based on current and anticipated levels of operations and conditions in our industry and markets, we believe that cash on hand, together with cash flows from operations and borrowings available to us under the ABL Facility, will be adequate to meet our ordinary course working capital, capital expenditures, debt service and other cash requirements for at least the next twelve months. However, we may increase future liquidity via the sale of additional common units, the issuance of additional debt securities, or obtaining new or expanded borrowing capacity.
Cash Flows
The following table sets forth our cash flows for the periods indicated:
  
 
Three Months Ended
(in millions)
 
March 31, 2016
 
March 31, 2015
Net cash provided by operating activities
 
$
5.8

 
$
82.9

Net cash used in investing activities
 
(27.9
)
 
(6.6
)
Net cash used in financing activities
 
(13.8
)
 
(45.9
)
Net increase (decrease) in cash and cash equivalents
 
(35.9
)
 
30.4

Cash and cash equivalents at beginning of period
 
70.9

 
87.9

Cash and cash equivalents at end of period
 
$
35.0

 
$
118.3

Net Cash Provided By Operating Activities. Net cash provided by operating activities for the three months ended March 31, 2016 was $5.8 million. The most significant sources of cash were our net income ($14.7 million) adjusted for non-cash expenses, such as depreciation and amortization expense ($11.3 million), a favorable change in unrealized hedging positions of $5.5 million and equity-based compensation ($4.6 million). We also recognized a non-cash benefit of $11.0 million as a result of a reduction in the lower of cost or market inventory reserve originally established at December 31, 2014. Lastly, cash was negatively impacted by a net investment in working capital of $5.1 million, primarily attributable to higher refined product inventory volumes at March 31, 2016 compared to December 31, 2015.
Net cash provided by operating activities for the three months ended March 31, 2015 was $82.9 million. The most significant sources of cash were our net income ($111.2 million) adjusted for non-cash expenses, such as depreciation and amortization expense ($10.8 million) and equity-based compensation ($2.6 million). We also recognized a non-cash change of $10.8 million in the lower of cost or market inventory reserve due to the reduction of such reserve originally established at December 31, 2014. Additionally, cash was negatively impacted by a net working capital increase of $26.7 million.
The decrease in cash provided by operating activities of $77.1 million versus the prior year is primarily due to lower net income of $96.5 million, partially offset by a decrease in the change in feedstock payables in the 2016 period resulting primarily from a decline in crude oil prices in the 2015 period versus a relatively flat 2016 period.
Net Cash Used In Investing Activities. Net cash used in investing activities for the three months ended March 31, 2016 of $27.9 million primarily related to capital expenditures on the solvent deasphalting unit, the desalter and a firewater tank and other maintenance and regulatory capital, all within our refining segment.

38


Net cash used in investing activities for the three months ended March 31, 2015 of $6.6 million was primarily related to capital expenditures including the desalter project, crude unit capacity improvements and the flare instrumentation project, and other maintenance and regulatory capital, all within our refining segment.
The increase in cash used in investing activities of $21.3 million versus the prior year is primarily due to the continued investment in several significant organic growth projects in 2016.
Net Cash Used In Financing Activities. Net cash used in financing activities for the three months ended March 31, 2016 was $13.8 million. During the first quarter of 2016, we received $70.0 million from borrowings on the ABL Facility and repaid $47.5 million, resulting in a net increase in borrowings of $22.5 million. Additionally, cash decreased by $36.3 million related to our quarterly distribution to unitholders.
Net cash used in financing activities for the three months ended March 31, 2015 of $45.9 million was related to our quarterly distribution to unitholders.
The decrease in cash used in financing activities of $32.1 million versus the prior year period was primarily due to an increase in net borrowings from our ABL Facility of $22.5 million and lower cash distributions of $9.6 million in the three months ended March 31, 2016 versus the same period in the prior year. We distribute cash to our unitholders one quarter in arrears of when it was earned.
Working Capital
Working capital at March 31, 2016 was $139.0 million, consisting of $508.3 million in total current assets and $369.3 million in total current liabilities. Working capital at December 31, 2015 was $156.2 million, consisting of $519.4 million in total current assets and $363.2 million in total current liabilities. The decrease in working capital as of March 31, 2016 was primarily due to a reduction in cash resulting from capital spending on organic growth projects and the payment of distributions to our unitholders for cash generated in the fourth quarter of 2015. These factors were partially offset by higher refined product inventory levels at March 31, 2016 and a $22.5 million cash increase resulting from borrowings from the ABL Facility.
Capital Spending
Capital spending for the three months ended March 31, 2016 of $27.9 million primarily included expenditures related to the solvent deasphalting unit, the desalter project, the construction of a firewater tank, sour water capacity expansion and a capacity enhancement project on one of our crude units at our refinery (approximately $20.5 million in total) as well as facility improvements at the refinery and retail store locations.
Capital spending for the three months ended March 31, 2015 of $6.6 million primarily included expenditures related to the desalter project, a capacity enhancement project on one of our crude units and flare instrumentation at our refinery(approximately $3.0 million in total) as well as safety related enhancements and facility improvements at the refinery and retail store locations.
We currently expect to spend between $26 million and $31 million in the second quarter of 2016, for annual capital spending total of between $95 million and $110 million. Second quarter 2016 capital spending is expected to be comprised of between $16.0 million and $19.0 million in organic growth capital spending consisting of the new desalter equipment, spending related to a crude unit revamp project and our solvent deasphalting unit project. The remaining maintenance, regulatory and other discretionary projects totaling approximately $10.0 million to $12.0 million primarily relate to safety/security, environmental, a firewater tank, sour water capacity expansion and ongoing replacement spending also referred to as maintenance and regulatory capital. Beginning in the third quarter of 2015, the board of directors of our general partner approved a quarterly cash reserve of $7.5 million for approved organic growth projects. Since spending may be significant in any given quarter, reserves are made over several quarters in order to mitigate the impact on cash available for distribution. To the extent actual spending on organic growth projects exceeds the cash reserve, we may consider borrowing on our ABL Facility to fund the difference. Subsequent quarterly cash reserves for organic growth projects may be used to repay any outstanding borrowing under the ABL Facility that were made for the purpose of funding organic growth projects.
Our Distribution Policy
We generally expect within 60 days after the end of each quarter to make distributions, if any, 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, if any, will equal the amount of available cash we generate in such quarter, if any. Distributions on our units will be in cash. Available cash for each quarter, if any, will be determined by the board of directors of our general partner following the end of such quarter. Distributions are expected to 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 and regulatory 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

39


related expenses, working capital, and organic growth projects. 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 and capital expenditures for organic growth projects will be funded with cash reserves or borrowings under the ABL Facility. We may also choose to fund organic growth via issuance of debt or equity securities or borrowings under the ABL Facility. We do not intend to maintain excess distribution coverage or reserve cash for the purpose of maintaining stability or growth in our quarterly distribution. We do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our external growth, either by issuances of debt or equity securities, or through borrowings under the ABL Facility.
Because our policy will be to distribute an amount equal to the available cash, if any, 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, including inventory fluctuations, (iv) maintenance and regulatory capital expenditures, (v) reserves for organic growth capital expenditures and (vi) cash reserves deemed necessary or appropriate by the board of directors of our general partner, including amounts to replenish unfunded reserves from the calculation of first quarter 2016 cash available for distribution. 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 during each quarter in the year ended December 31, 2015 and during the three months ended March 31, 2016:
Date Declared
 
Date Paid
 
Common Units and equivalents at record date (in millions)
 
Distribution per common unit and equivalent
 
Total Distribution (in millions)
2015 Distributions:
 
 
 
 
 
 
 
 
February 5, 2015
 
February 27, 2015
 
93.7
 
$
0.49

 
$
45.9

May 5, 2015
 
May 29, 2015
 
93.7
 
1.08

 
100.8

August 4, 2015
 
August 28, 2015
 
93.7
 
1.19

 
111.3

November 3, 2015
 
November 25, 2015
 
93.7
 
1.04

 
97.3

Total distributions paid during 2015
 
 
 
 
 
$
3.80

 
$
355.3

2016 Distributions:
 
 
 
 
 
 
 
 
February 3, 2016
 
February 19, 2016
 
94.2
 
$
0.38

 
$
36.1

Total distributions paid during 2016
 
 
 
 
 
$
0.38


$
36.1

Notwithstanding our distribution policy, certain provisions of the indenture governing the 2020 Secured Notes and the ABL Facility may restrict the ability of NTE LLC, our operating subsidiary, to distribute cash to us.
Consistent with our distribution policy, cash distributions with respect to the second quarter of 2016, if any, would normally be declared and paid in August 2016. However, pursuant to the terms of the Merger Agreement, with respect to the quarter in which the Closing Date of the Merger occurs, which is currently expected to be the second quarter of 2016 subject to the satisfaction of all closing conditions, we will, to the extent we generate available cash in such quarter, make a prorated quarterly distribution to unitholders of record as of immediately prior to the Effective Time of the Merger of any such available cash if the record date for the Western Refining quarterly cash dividend to be paid in that quarter occurs before the Closing Date. Accordingly, in the quarter that the Closing Date occurs, Northern Tier common unitholders who receive Western Refining common stock in the Merger will receive (i) a Northern Tier cash distribution in respect of the previous quarter, to the extent we generate available cash in such quarter, and (ii) either a Northern Tier prorated cash distribution in respect of available cash generated by us in the quarter in which the Closing Date occurs or (assuming such unitholders continue to hold the shares of Western Refining common stock received in the Merger through the record date for such Western Refining dividend) the Western Refining quarterly cash dividend payable in the quarter in which the Closing Date occurs. The amount of any distribution will not have any effect on the merger consideration payable in the Merger.


40


The following table details our calculation of cash available for distribution for the three months ended March 31, 2016:
(in millions)
Three Months Ended March 31, 2016
Net income
$
14.7

Adjustments:
 
Interest expense
6.5

Income tax provision
0.6

Depreciation and amortization
11.3

EBITDA subtotal
33.1

Lower of cost or market inventory adjustment (2)
(11.0
)
MPL proportionate depreciation expense
0.7

Turnaround and related expenses
0.4

Equity-based compensation impacts
4.6

Merger-related expenses
0.4

 Adjusted EBITDA (1)
28.2

Cash interest expense
(7.3
)
Cash income taxes paid

MPL proportionate depreciation expense
(0.7
)
Increase in working capital reserve (3)
(6.0
)
Capital expenditures (4)
(10.7
)
Reserve for turnaround and related expenses (5)(8)
(7.5
)
Reserve for organic growth projects (6)(8)
(7.5
)
Cash Available for Distribution Deficit (7)
$
(11.5
)
(1)
Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in calculating the components of various covenants in the agreements governing our 2020 Secured Notes and the ABL Facility. We believe the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. The calculation of Adjusted EBITDA generally eliminates the effects of financings, income taxes and the accounting effects of significant turnaround activities which many of our peers capitalize and therefore exclude from Adjusted EBITDA. Adjusted EBITDA should not be considered as an alternative to operating income or net income as measures of operating performance. In addition, Adjusted EBITDA is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes and depreciation and amortization, adjusted for depreciation from the Minnesota Pipe Line operations, lower of cost or market inventory adjustments, turnaround and related expenses, equity-based compensation expense and merger-related expenses. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP. 
(2)
Includes adjustments to reserves to state inventory at the lower of cost or market as of period end. Quarterly non-cash lower of cost or market inventory reserve adjustments are excluded from Adjusted EBITDA.
(3)
Represents an increase in the working capital reserve established in the fourth quarter 2014. Changes in crude oil prices can impact cash generated from operations due to the timing of crude oil payables. During the first quarter 2016, crude oil prices decreased, resulting in an estimated $6.0 million reduction in our cash earnings from operations and a reduction in working capital. As a result, our general partner's board of directors increased the working capital reserve accordingly.
(4)
Capital expenditures include maintenance, replacement and regulatory capital projects on an accrual basis.
(5)
Cash reserves are determined by the board of directors of our general partner primarily for the purposes of funding our turnaround and discretionary capital projects. Since spending may be significant in any given quarter, reserves are made over several quarters in order to mitigate the impact on cash available for distribution.

41


(6)
The cash reserve for organic growth projects of $7.5 million is used to fund approved organic growth projects. Since spending may be significant in any given quarter, reserves are made over several quarters in order to mitigate the impact on cash available for distribution. To the extent actual spending on organic growth projects exceeds the cash reserve, we may borrow on our ABL Facility to fund the difference. Subsequent quarterly cash reserves for organic growth projects may be used to repay any outstanding borrowings under the ABL Facility that were made for the purpose of funding organic growth projects.
(7)
Cash available for distribution is a non-GAAP performance measure that we believe is important to investors in evaluating our overall cash generation performance. Cash available for distribution should not be considered as an alternative to operating income or net income as measures of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. As shown in the table above, we have reconciled cash available for distribution to Adjusted EBITDA and in addition reconciled Adjusted EBITDA to net income. Cash available for distribution has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP. Our calculation of cash available for distribution may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Cash available for distribution for each quarter will be determined by the board of directors of our general partner following the end of such quarter.
(8)
Since Northern Tier had a cash available for distribution deficit of $11.5 million for the three months ended March 31, 2016, Northern Tier did not generate sufficient cash during the three months ended March 31, 2016 to fully fund the reserves taken in connection with the calculation of cash available for distribution for the period. Northern Tier expects to consider the amount of these unfunded reserves when determining the appropriate reserves to be taken when calculating the amount of cash available for distribution with respect to the second quarter of 2016 or any portion of such period, which Northern Tier expects would adversely impact the amount of available cash for such period.

42


ITEM 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to various market risks, including changes in commodity prices and interest rates and credit risks. We may use financial instruments such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of the identified risks. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements.
Commodity Price Risk
As a refiner of petroleum products, we have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, we must achieve a positive spread between the cost of raw materials and the value of finished products (i.e., refinery gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The timing, direction and overall change in refined product prices versus crude oil prices will impact profit margins and could have a significant impact on our earnings and cash flows. Assuming all other factors remained constant, a $1 per barrel change in our average refinery gross margin, based on our average refinery throughput for the three months ended March 31, 2016 of 100,609 bpd, would result in a change of $9.2 million in our overall annual gross margin.
The prices of crude oil, refined products and other commodities are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are beyond our control. We monitor these risks and, where appropriate under our risk mitigation policy, we will seek to reduce the volatility of our cash flows by hedging an operationally reasonable volume of our gasoline and diesel production. We may enter into derivative transactions designed to mitigate the impact of commodity price fluctuations on our business by locking in or fixing a percentage of the anticipated or planned gross margin in future periods. We may also enter into derivative transactions to manage price risks associated with inventory quantities above or below target levels. We will not enter into financial instruments for purposes of speculating on commodity prices. However, we may execute derivative financial instruments pursuant to our hedging policy that are not considered to be hedges within the applicable accounting guidelines.
We carry inventories of crude oil, intermediates and refined products (“hydrocarbon inventories”) on our balance sheet, the values of which are subject to fluctuations in market prices. Our crude oil inventories totaled approximately 2.6 million barrels and 2.5 million barrels at March 31, 2016 and December 31, 2015. The average cost of these crude oil inventories was approximately $67.67 and $68.52 per barrel on a LIFO basis at March 31, 2016 and December 31, 2015, respectively, excluding the impact of the lower of cost or market reserve of $61.3 million and $66.3 million at March 31, 2016 and December 31, 2015, respectively. Our refined and intermediate products totaled approximately 2.5 million and 2.0 million barrels and at March 31, 2016 and December 31, 2015, respectively. The average cost of our refined and intermediate inventories was approximately $70.78 and $81.71 per barrel on a LIFO basis at March 31, 2016 and December 31, 2015, respectively, excluding the impact of the lower of cost of market reserve of $62.1 million and $68.1 million at March 31, 2016 and December 31, 2015, respectively.
Basis Risk
The effectiveness of our risk mitigation strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors, for example the location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure. In hedging NYMEX or U.S. Gulf Coast (or any other relevant benchmark) crack spreads, we experience location basis as the settlement price of NYMEX refined products (related more to New York Harbor cash markets) or U.S. Gulf Coast refined products (related more to U.S. Gulf Coast cash markets) that may be different than the prices of refined products in our Upper Great Plains pricing area. The risk associated with not hedging the basis when using NYMEX or U.S. Gulf Coast forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX or U.S. Gulf Coast while pricing in our market remains flat or decreases, then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the pricing in our market. When appropriate we may use a series of hedging instruments to mitigate basis risk exposure. For example, we may hedge the direct NYMEX basis risk and then layer a Group 3 product basis hedge to NYMEX. Assuming all other factors remained constant, a $1 per barrel change in our gasoline and distillate basis would result in an annual change of $4.5 million and $3.1 million in our annual gross margin on gasoline and distillate sales, respectively, based on our average refinery production of these products for the three months ended March 31, 2016 of 49,707 bpd and 33,639 bpd, respectively.

43


Commodities Price and Basis Risk Management Activities
We have entered into agreements that govern all cash-settled commodity transactions that we enter into with various counterparties for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined petroleum products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. Under the agreements, as market conditions permit, we have the capacity to mitigate our crack spread risk with respect to reasonable percentages of the refinery’s projected monthly production of some or all of these refined products.
We periodically use futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. Under our risk mitigation strategy, we may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash. The contracts are not being accounted for as hedges for financial reporting purposes. We recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheet and any related net gain or loss is recorded as a gain or loss in the derivative activity captions on our consolidated statements of operations. Observable quoted prices for similar assets or liabilities in active markets are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end.
Interest Rate Risk
Borrowings, if any, under our ABL Facility bear interest, at our election, at either an alternative base rate, plus an applicable margin (which ranges between 0.50% and 1.00% pursuant to a grid based on average excess availability) or a LIBOR rate plus an applicable margin (which ranges between 1.50% and 2.00% pursuant to a grid based on average excess availability). See “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Credit Risk
We are subject to risk of losses resulting from nonpayment or nonperformance by our wholesale refining customers. We will continue to closely monitor the creditworthiness of customers to whom we grant credit and establish credit limits in accordance with our credit policy.
We are exposed to credit risk in the event of nonperformance by our counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with long-term credit ratings of at least BBB+ by Standard and Poor’s and A3 by Moody’s. In the event of default, we would potentially be subject to losses on a derivative instrument’s mark-to-market gains. We do not expect nonperformance of the counterparties involved in our risk mitigation arrangements.



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ITEM 4. Controls and Procedures
Evaluation of disclosure controls and procedures
NTE LP maintains a set of disclosure controls and procedures designed to ensure that information required to be disclosed in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in SEC rules and forms. In addition, the disclosure controls and procedures ensure that information required to be disclosed is accumulated and communicated to management, including the Chief Executive Officer and Chief Financial Officer, allowing timely decisions regarding required disclosure. Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer, we evaluated the effectiveness of our disclosure controls and procedures, as defined in Rules 13a-15(e) and 15d-15(e) of the Securities Exchange Act of 1934, as of March 31, 2016. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016.
Changes in internal control over financial reporting
There were no changes in our internal control over financial reporting that occurred during the quarter ended March 31, 2016, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II - OTHER INFORMATION

ITEM 1. Legal Proceedings
There were no material developments during the quarter in any of the legal proceedings identified in Part I. - Item 3. “Legal Proceedings” of our 2015 Annual Report on Form 10-K. The Company is party to various other claims and legal actions arising in the normal course of business. See Part I Item I. Note 17 to our condensed consolidated financial statements for the three months ended March 31, 2016, for a description of certain current commitments and contingencies, which is incorporated by reference herein. While the results of these claims and legal actions cannot be predicted with certainty, the Company believes that the final resolution of these matters, individually or in the aggregate, would not have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
ITEM 1A. Risk Factors
In addition to the other information set forth in this report, you should carefully consider the risks under the heading “Risk Factors” in Item 1A of our 2015 Annual Report on Form 10-K, which risks could materially affect our business, financial condition or future results. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.
ITEM 6. Exhibits
The exhibits listed in the accompanying Exhibit Index are filed or incorporated by reference as part of this report and such Exhibit Index is incorporated herein by reference.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
Northern Tier Energy LP
 
 
 
By:
 
 
 
Northern Tier Energy GP LLC,
 
 
 
 
its general partner
Date May 3, 2016
 
By:
 
/s/ David L. Lamp
 
 
Name:
 
David L. Lamp
 
 
Title:
 
President and Chief Executive Officer of Northern Tier Energy GP LLC (Principal Executive Officer)
Date May 3, 2016
 
By:
 
/s/ Karen B. Davis
 
 
Name:
 
Karen B. Davis
 
 
Title:
 
Executive Vice President and Chief Financial Officer of Northern Tier Energy GP LLC (Principal Financial Officer and Principal Accounting Officer)


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EXHIBIT INDEX*
The exhibits below are numbered in accordance with the Exhibit Table of Item 601 of Regulation S-K. 
Exhibit
Number
 
Description
 
 
 
31.1(a)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
31.2(a)
 
Certification of Karen B. Davis, Executive Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
 
 
 
32.1(b)
 
Certification of David L. Lamp, President and Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
32.2(b)
 
Certification of Karen B. Davis, Executive Vice President and Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP, pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
 
 
101.INS
 
XBRL Instance Document.
 
 
101.SCH
 
XBRL Taxonomy Extension Schema Document.
 
 
101.CAL
 
XBRL Taxonomy Extension Calculation Linkbase Document.
 
 
101.DEF
 
XBRL Taxonomy Extension Definition Linkbase Document.
 
 
101.LAB
 
XBRL Taxonomy Extension Label Linkbase Document.
 
 
101.PRE
 
XBRL Taxonomy Extension Presentation Linkbase Document.
(a)
Filed herewith.
(b)
Furnished herewith.
(c)
Denotes management contract, compensatory plan or arrangement
*
Reports filed under the Securities Exchange Act (Form 10-K, Form 10-Q and Form 8-K) are under File No. 001-35612.


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