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 June 30, 2015
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 August 4, 2015, Northern Tier Energy LP had 92,833,486 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 AND SIX MONTHS ENDED JUNE 30, 2015

TABLE OF CONTENTS

			Page
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS			3
PART I - FINANCIAL INFORMATION			5
	ITEM 1.	Financial Statements (Unaudited)	5
		Condensed Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014	5
		Condensed Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2015 and 2014	6
		Condensed Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014	7
		Notes to Condensed Consolidated Financial Statements	8
	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	28
	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	46
	ITEM 4.	Controls and Procedures	48
PART II - OTHER INFORMATION			48
	ITEM 1.	Legal Proceedings	48
	ITEM 1A.	Risk Factors	48
	ITEM 6.	Exhibits	48
SIGNATURES			49

2

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q (this “Report”) may constitute “forward-looking statements.” 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;

• 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;

• 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.

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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, 2014 (our "2014 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)

	June 30, 2015			December 31, 2014
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	127.9		$	87.9
Receivables, less allowance for doubtful accounts	263.1			236.0
Inventories	312.1			252.1
Other current assets	18.6			15.2
Total current assets	721.7			591.2
NON-CURRENT ASSETS
Equity method investment	82.6			80.7
Property, plant and equipment, net	443.1			445.8
Intangible assets	33.8			33.8
Other assets	27.4			28.9
Total Assets	$	1,308.6		$	1,180.4
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	369.7		$	334.3
Accrued liabilities	49.2			52.6
Total current liabilities	418.9			386.9
NON-CURRENT LIABILITIES
Long-term debt	353.9			354.2
Lease financing obligation	6.8			8.6
Other liabilities	26.3			27.0
Total liabilities	805.9			776.7
Commitments and contingencies
EQUITY
Partners' capital (92,832,210 and 92,712,744 units issued and outstanding at June 30, 2015 and December 31, 2014, respectively)	505.8			406.9
Accumulated other comprehensive loss	(3.1		)	(3.2		)
Total equity	502.7			403.7
Total Liabilities and Equity	$	1,308.6		$	1,180.4

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 OPERATIONS

AND COMPREHENSIVE INCOME

(in millions, except unit and per unit data, unaudited)

	Three Months Ended						Six Months Ended
	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
REVENUE (a)	$	959.8		$	1,602.5		$	1,753.6		$	2,948.8
COSTS, EXPENSES AND OTHER
Cost of sales (a)	714.6			1,432.0			1,291.1			2,588.3
Direct operating expenses	76.3			65.4			145.6			131.8
Turnaround and related expenses	1.2			0.9			1.6			1.4
Depreciation and amortization	10.8			10.2			21.6			20.1
Selling, general and administrative expenses	22.2			22.7			42.4			49.7
Reorganization and related costs	—			3.5			—			12.9
(Income) loss from equity method investment	(4.2		)	2.4			(7.8		)	0.9
Other (gain) loss, net	(0.4		)	(0.2		)	0.3			0.3
OPERATING INCOME	139.3			65.6			258.8			143.4
Interest expense, net	(7.5		)	(6.2		)	(15.0		)	(12.4		)
INCOME BEFORE INCOME TAXES	131.8			59.4			243.8			131.0
Income tax provision	(2.9		)	(1.5		)	(3.7		)	(1.6		)
NET INCOME	128.9			57.9			240.1			129.4
Other comprehensive income, net of tax	0.1			—			0.1			0.1
COMPREHENSIVE INCOME	$	129.0		$	57.9		$	240.2		$	129.5
EARNINGS PER UNIT INFORMATION:
Weighted average number of units outstanding:
Basic	92,500,750			92,427,069			92,479,790			92,296,346
Diluted	92,779,679			92,454,923			92,707,738			92,306,861
Earnings per unit:
Basic	$	1.39		$	0.62		$	2.59		$	1.40
Diluted	$	1.39		$	0.62		$	2.58		$	1.40
Cash distributions declared per common unit	$	1.08		$	0.77		$	1.57		$	1.18
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenues and cost of sales	$	107.0		$	103.2		$	203.0		$	192.1

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)

	Six Months Ended
	June 30, 2015			June 30, 2014
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	240.1		$	129.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21.6			20.1
Non-cash interest expense	1.1			1.2
Equity-based compensation expense	5.5			10.3
Gain from the change in fair value of outstanding derivatives	(1.6		)	(0.3		)
Equity investment earnings, net of dividends	(2.0		)	0.9
Change in lower of cost or market inventory adjustment	(49.0		)	—
Changes in assets and liabilities, net:
Accounts receivable	(28.2		)	(59.6		)
Inventories	(11.0		)	(25.7		)
Other current assets	(2.9		)	6.0
Accounts payable and accrued expenses	29.4			70.3
Other, net	0.2			1.7
Net cash provided by operating activities	203.2			154.3
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(17.7		)	(25.1		)
Return of capital from investments	—			1.4
Net cash used in investing activities	(17.7		)	(23.7		)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity distributions	(145.5		)	(109.5		)
Net cash used in financing activities	(145.5		)	(109.5		)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents	40.0			21.1
Cash and cash equivalents at beginning of period	87.9			85.8
Cash and cash equivalents at end of period	$	127.9		$	106.9

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

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LP (“NTE LP” or the “Company”) is an independent downstream energy company with refining, retail and logisitics 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 38.4%, of NTE LP at June 30, 2015. The remaining balance of the NTE LP units are publicly traded.

As of June 30, 2015, 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 June 30, 2015, NTR operated 165 convenience stores under the SuperAmerica brand and SAF supported 99 franchised stores which also utilize the SuperAmerica brand. These 264 SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise and, in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items. NTB prepares and distributes food products under the SuperMom’s Bakery brand primarily to SuperAmerica branded retail outlets.

Basis of Presentation

The accompanying 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 six months ended June 30, 2015 are not necessarily indicative of the results that may be expected for the year ending December 31, 2015, or for any other period. The condensed consolidated balance sheet at December 31, 2014 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 2014 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 2014 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

8

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 June 30, 2015 and December 31, 2014, 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 165 Company operated convenience stores and 99 franchisee operated convenience stores as of June 30, 2015, 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 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.

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.” The required frequency of the maintenance varies, but generally is every two to six years depending on the processing unit involved. 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 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 purchase 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

9

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.

The EPA has not established the final renewable blending volume levels for 2014 and 2015. To the extent the Company is unable to blend at the rate necessary to satisfy the EPA mandated volume, the Company will purchase RINs. 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 2014 and 2015 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.

Prior to October 1, 2014, the Company maintained a crude oil supply and logistics agreement with J.P. Morgan Commodities Canada Corporation (“JPM CCC”) pursuant to which JPM CCC assisted the Company in the purchase of substantially all of its crude oil needs for the refinery. As discussed in Note 5, JPM CCC and the Company mutually agreed to terminate this agreement. In the fourth quarter of 2014, subsequent to the termination of this agreement, the Company significantly increased its crude procurement activities and related exchange and buy/sell activity to manage the volumes, grade, timing, and locations of such crude. Such activities are similar to the buy/sell crude oil transactions noted above and are recorded net in cost of sales.

Cost of Sales

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 $103.2 million for the three months ended June 30, 2015 and 2014, respectively, and $203.0 million and $192.1 million for the six months ended June 30, 2015 and 2014, respectively.

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Reclassification

A reclassification has been made to the prior-year financial information in order to conform to the Company’s current presentation. Income from the Company's equity method investment in MPL has been reclassified from Other (gain) loss, net to a separate line titled income from equity method investment. The amount of this reclassification were losses of $2.4 million and $0.9 million for the three and six months ended June 30, 2014, respectively.

Accounting Developments

In January 2015, the FASB issued ASU 2015-01, Income Statement - Extraordinary and Unusual Items, which eliminates the concept of extraordinary items from GAAP, which required certain classification and presentation of extraordinary items in the income statement and disclosures. The guidance is effective for fiscal years, and interim periods within those fiscal years, beginning after December 15, 2015. A reporting entity may apply the amendments prospectively. A reporting entity may also apply the amendments retrospectively to all prior periods presented in the financial statements. Early adoption is permitted. The Company adopted this guidance on January 1, 2015. The adoption of this guidance did not impact our condensed consolidated financial statements and disclosures.

On February 18, 2015, the FASB issued ASU 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which amends the consolidation requirements in ASC 810 and significantly changes the consolidation analysis required under GAAP. Among other changes, the standards update results in limited partnerships being treated as variable interest entities ("VIEs"), unless the limited partners have either substantive kick-out or participating rights. The ASU also changes the effect that fees paid to a decision maker or service provider have on the consolidation analysis. The guidance in the ASU is effective for annual periods, and interim periods within those annual periods, beginning after December 15, 2015. Early adoption is permitted provided the guidance is applied as of the beginning of the annual period containing the adoption date. The Company believes the adoption of this guidance will not have a material effect on our condensed consolidated financial statements and disclosures.

On April 7, 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs, which requires debt issuance costs related directly to notes payable be deducted from the face amount of that note and the amortization of such costs be classified as interest expense. This guidance is effective for fiscal years beginning after December 15, 2015, and interim periods beginning after December 15, 2016, with early adoption permitted. Upon adoption, an entity must retrospectively apply the guidance. The Company believes the adoption of this ASU will result in the reclassification of the deferred financing costs associated with our 2020 Secured Notes (see Note 10) from other assets to long-term debt. The unamortized amount of these deferred financing costs were $6.7 million and $7.3 million at June 30, 2015 and December 31, 2014, respectively.

In May 2014, the FASB issued ASU No. 2014-09 Revenue from Contracts with Customers, which provides guidance for revenue recognition. The standard’s core principle is that a company should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. This guidance will be effective for our financial statements in the annual period beginning after December 15, 2017. Under this proposal, early adoption will be allowed, but not earlier than the original effective date. The Company is evaluating the effect of adopting this new accounting guidance. The Company does not expect adoption will have a material impact on the Company's results of operations, cash flows or financial position.

3. RELATED PARTY TRANSACTIONS

As described in Note 1, Western Refining owned 35,622,500 common units, or 38.4%, of NTE LP as well as 100% of NT InterHoldCo LLC, which owned 100% of NTE GP, the general partner of NTE LP, as of June 30, 2015. The Company has engaged in several types of transactions with Western Refining including crude and feedstock purchases, asphalt purchases, and railcar leases. Additionally, the Company is party to a shared services agreement with Western Refining whereby the Company receives administrative support services. The shared services agreement was effective as of September 1, 2014, and was approved by the Conflicts Committee of the board of directors of NTE LP's general partner. These services include assistance with treasury, risk management and commercial operations, environmental compliance, information technology support 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.

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The Company engaged in the following related party transactions with unconsolidated affiliates for the three and six months ended June 30, 2015 and 2014:

		Three Months Ended				Six Months Ended
(in millions)	Location in Statement of Operations and Comprehensive Income	June 30, 2015		June 30, 2014		June 30, 2015		June 30, 2014
Western Refining:
Crude and feedstock purchases	Cost of sales	$	—	$	—	$	—	$	6.3
Asphalt sales	Revenue	15.5		3.8		27.8		4.8
Feedstock sales	Revenue	0.5		—		0.5		—
Railcar lease sales	Revenue	0.2		—		0.2		0.1
Shared services purchases	Selling, general and administrative expenses	0.9		—		1.6		—
Minnesota Pipeline Company:
Pipeline transportation purchases	Cost of sales	14.7		—		27.4		—
Equity distributions	Equity method investment	2.1		1.4		5.8		1.4

The Company had the following outstanding receivables and payables with non-consolidated related parties at June 30, 2015 and December 31, 2014:

(in millions)	Balance Sheet Location	June 30, 2015			December 31, 2014
Net receivable (payable) with related party:
Western Refining	Receivables, less allowance for doubtful accounts	$	5.8		$	5.1
Minnesota Pipeline Company	Accounts payable	(2.7		)	(2.1		)

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 June 30, 2015 and 2014 was 2.2% and 2.5%, respectively. For the six months ended June 30, 2015 and 2014, the effective tax rate was 1.5% and 1.2%, respectively. For the six months ended June 30, 2015 and 2014, the Company's consolidated federal and state expected statutory tax rates were 41.7% and 41.5%, respectively. The Company's effective tax rate for the six months ended June 30, 2015 and 2014 was lower than the statutory rate primarily due to the fact that only the retail operations of the Company are taxable entities.

5. INVENTORIES

	June 30,			December 31,
(in millions)	2015			2014
Crude oil and refinery feedstocks	$	139.6		$	137.5
Refined products	153.9			150.0
Merchandise	24.0			22.3
Supplies and sundry items	19.2			15.9
	336.7			325.7
Lower of cost or market inventory reserve	(24.6		)	(73.6		)
Total	$	312.1		$	252.1

Inventories accounted for under the LIFO method comprised 87% and 88% of the total inventory value at June 30, 2015 and December 31, 2014, respectively.

Historically, the Company maintained a crude oil supply and logistics agreement with JPM CCC (the "Crude Intermediation Agreement") pursuant to which JPM CCC assisted the Company in the purchase of the crude oil for its storage tanks at Cottage

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Grove, Minnesota, which are approximately two miles from the refinery. Upon delivery of the crude oil to the Company, the Company paid JPM CCC the price of the crude oil plus certain agreed-upon fees and expenses. JPMorgan Chase & Co. announced its intention to sell the physical portions of its commodities business (which included JPM CCC) to a third party during the fourth quarter of 2014. In advance of this sale, JPM CCC and the Company mutually agreed to terminate the Crude Intermediation Agreement. This resulted in the Company's acquisition of approximately 1.2 million barrels of crude oil inventory from JPM CCC as of September 30, 2014. This purchase of crude oil from JPM CCC in September 2014 resulted in an additional layer of inventory subject to the LIFO valuation method.

Since the third quarter of 2014, market prices of crude oil and refined products have decreased significantly. As a result, the Company reduced the carrying value of its crude oil and refined products inventory at June 30, 2015 and December 31, 2014 by $24.6 million and $73.6 million, respectively, in order to state the value at market prices, which were lower than the Company's LIFO cost.

6. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $82.6 million and $80.7 million at June 30, 2015 and December 31, 2014, respectively.

As of June 30, 2015 and December 31, 2014, the carrying amount of the equity method investment was $6.1 million higher and $6.2 million higher, respectively, 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 received $2.1 million and $1.4 million in distributions from MPL in the three months ended June 30, 2015 and 2014, respectively. For the six months ended June 30, 2015 and 2014, respectively, the Company recorded $5.8 million and $1.4 million in distributions from MPL. Equity (income) loss from MPL was $(4.2) million and $2.4 million for the three months ended June 30, 2015 and 2014, respectively, and $(7.8) million and $0.9 million for the six months ended June 30, 2015 and 2014, respectively.

7. PROPERTY, PLANT AND EQUIPMENT

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

	Estimated	June 30,			December 31,
(in millions)	Useful Lives	2015			2014
Land		$	9.0		$	9.0
Retail stores and equipment	2 - 22 years	65.9			65.7
Refinery and equipment	5 - 24 years	449.9			444.6
Buildings and building improvements	25 years	10.1			10.2
Software	5 years	18.9			18.8
Vehicles	5 years	4.8			4.7
Other equipment	2 - 7 years	9.8			9.1
Precious metals		10.2			10.2
Assets under construction		23.9			12.6
		602.5			584.9
Less: Accumulated depreciation		(159.4		)	(139.1		)
Property, plant and equipment, net		$	443.1		$	445.8

PP&E includes gross assets acquired under capital leases of $8.8 million and $10.8 million at June 30, 2015 and December 31, 2014, respectively, with related accumulated depreciation of $1.8 million and $1.7 million, respectively. The Company had depreciation expense related to capitalized software of $0.9 million for both the three months ended June 30, 2015 and 2014, and $1.8 million for both the six months ended June 30, 2015 and 2014.

8. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both June 30, 2015 and December 31, 2014. At both June 30, 2015 and December 31, 2014, 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 has concluded that no impairment is present at this time.

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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 use 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 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 June 30, 2015 and December 31, 2014, the Company had open commodity derivative instruments as follows:

	June 30, 2015	December 31, 2014
Crude oil and refined products (thousands of barrels):
Futures - long	35	60
Futures - short	432	184
Swaps	900	—
Forwards - long	3,377	3,868
Forwards - short	2,454	924
Natural gas (thousands of MMBTUs):
Swaps	2,642	3,424

The information below presents the notional volume of outstanding contracts by type of instrument and year of maturity at June 30, 2015:

	Notional Contract Volumes by Year of Maturity
	2015	2016
Crude oil and refined products (thousands of barrels):
Futures - long	35	—
Futures - short	432	—
Swaps	900	—
Forwards - long	3,377	—
Forwards - short	2,454	—
Natural gas (thousands of MMBTUs):
Swaps	1,814	828

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Fair Value of Derivative Instruments

The following tables provide information about the fair values of the Company's derivative instruments as of June 30, 2015 and December 31, 2014 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.

We are required to post margin collateral with a counterparty in support of our hedging activities. Funds posted as collateral were $2.3 million and $0.6 million as of June 30, 2015 and December 31, 2014. 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.

		June 30, 2015
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Accrued liabilities	$	0.1	$	1.2
Swaps	Other liabilities	—		0.4
Futures	Accrued liabilities	1.9		2.0
Forwards	Other current assets	2.2		—
Forwards	Accrued liabilities	—		1.8
Total		$	4.2	$	5.4
		December 31, 2014
(in millions)	Balance Sheet Location	Assets		Liabilities
Commodity instruments:
Swaps	Other current assets	$	1.3	$	—
Swaps	Accrued liabilities	—		2.9
Swaps	Other liabilities	—		0.4
Futures	Other current assets	0.4		—
Futures	Accrued liabilities	—		1.2
Total		$	1.7	$	4.5

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						Six Months Ended
(in millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Gain (loss) on the change in fair value of outstanding derivatives	$	0.5		$	0.5		$	1.6		$	0.3
Settled derivative gains (losses)	(2.9		)	(2.4		)	(2.8		)	(3.1		)
Total recognized gain (loss)	$	(2.4	)	$	(1.9	)	$	(1.2	)	$	(2.8	)
Gain (loss) recognized in cost of sales	$	(1.5	)	$	(1.9	)	$	(0.1	)	$	(2.8	)
Gain (loss) recognized in operating expenses	(0.9		)	—			(1.1		)	—
Total recognized net gain (loss) on derivatives	$	(2.4	)	$	(1.9	)	$	(1.2	)	$	(2.8	)

Market and Counterparty Risk

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The Company is exposed to credit risk in the event of nonperformance by our counterparties on its risk mitigating arrangements. The counterparties are large financial institutions with credit ratings of at least A- by Standard and Poor’s and 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 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 June 30, 2015, the borrowing base under the ABL Facility was $284.1 million and availability under the ABL Facility was $253.5 million (which is net of $30.6 million outstanding letters of credit). The borrower under the ABL Facility had no borrowings under the ABL Facility at June 30, 2015.

2020 Secured Notes

At June 30, 2015 and December 31, 2014, NTE LLC had outstanding $353.9 million and $354.2 million, respectively, in aggregate principal amount of 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering will both be amortized as a net reduction to interest expense over the remaining life of the 2020 Secured Notes.

The 2020 Secured Notes are guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future 100% direct and indirect subsidiaries on a full and unconditional basis; however, there are certain obligations not guaranteed on a full and unconditional basis as a result of subsidiaries being released as guarantors. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary being declared “unrestricted,” (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. Separate condensed consolidated financial information is not included as the guarantor company, NTE LP, does not have independent assets or operations. The 2020 Secured Notes and the subsidiary note guarantees are secured on a pari passu basis with certain hedging agreements by a first-priority security interest in substantially all present and hereinafter acquired tangible and intangible assets of NTE LLC and each of the subsidiary guarantors and by a second-priority security interest in the inventory, accounts receivable, investment property, general intangibles, deposit accounts and cash and cash equivalents collateralized by the ABL Facility which has 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.

At any time prior to the maturity date of the 2020 Secured Notes, the Company may, at its option, redeem all or any portion of the 2020 Secured Notes for the outstanding principal amount plus unpaid interest and a call premium as defined in the

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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 2020 Secured 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

Distribution Policy

The Company generally expects to make cash distributions to unitholders of record on the applicable record date within 60 days after the end of each quarter. Distributions will be equal to the amount of available cash generated in such quarter. Available cash for each quarter will generally equal the Company’s cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance and regulatory capital expenditures, reimbursement of expenses incurred by the general partner of NTE LP and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the general partner of NTE LP deems necessary or appropriate, including reserves for turnaround and related expenses. The amount of quarterly distributions, if any, will vary based on operating cash flow during such quarter. As a result, quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements including inventory fluctuations, (iv) maintenance and regulatory capital expenditures, (v) organic growth capital expenditures less any amounts the Company may choose to fund with borrowings from its ABL Facility or by issuance of debt or equity securities and (vi) cash reserves deemed necessary or appropriate by the board of directors of NTE LP’s general partner. Such variations in the amount of the quarterly distributions may be significant. The Company’s general partner has no incentive distribution rights.

The following table details the quarterly distributions paid to common unitholders for each of the quarters in the year ended December 31, 2014 and the six months ended June 30, 2015:

Date Declared	Date Paid	Common Units and equivalents at record date (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2014 Distributions:
February 7, 2014	February 28, 2014	92.7	$	0.41	$	38.0
May 6, 2014	May 30, 2014	93.0	0.77		71.6
August 5, 2014	August 29, 2014	93.0	0.53		49.3
November 4, 2014	November 25, 2014	93.1	1.00		92.9
Total distributions paid during 2014			$	2.71	$	251.8
2015 Distributions:
February 5, 2015	February 27, 2015	93.7	$	0.49	$	45.9
May 5, 2015	May 29, 2015	93.7	1.08		100.8
Total distributions paid during 2015			$	1.57	$	146.7

Effective August 4, 2015, the board of directors of NTE LP's general partner declared a quarterly distribution of $1.19 per unit to common unitholders, restricted common unitholders and phantom common unitholders (see Note 14) as of August 17, 2015, payable on August 28, 2015. This distribution of approximately $111.3 million in aggregate is based on available cash generated during the three months ended June 30, 2015.

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Changes in Partners' Equity

(in millions)	Partners' Capital			Accumulated Other Comprehensive Income			Total Partners' Equity
Balance at December 31, 2014	$	406.9		$	(3.2	)	$	403.7
Net income	240.1			—			240.1
Distributions	(146.7		)	—			(146.7		)
Equity-based compensation expense	5.5			—			5.5
Amortization of net prior service cost and deferred loss on defined benefit plans	—			0.1			0.1
Balance at June 30, 2015	$	505.8		$	(3.1	)	$	502.7

During the six months ended June 30, 2015, the Company's common units issued and outstanding increased by 119,466, 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 and six months ended June 30, 2015 and 2014. 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						Six Months Ended
(in millions, except unit and per-unit data)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Net income available to common unitholders	$	128.9		$	57.9		$	240.1		$	129.4
Less: income allocated to participating securities	(0.3		)	(0.4		)	(0.6		)	(0.5		)
Net income attributable to unrestricted common units	$	128.6		$	57.5		$	239.5		$	128.9
Weighted average unrestricted common units - basic	92,500,750			92,427,069			92,479,790			92,296,346
Plus: dilutive potential common securities	278,929			27,854			227,948			10,515
Weighted average unrestricted common units - diluted	92,779,679			92,454,923			92,707,738			92,306,861
Basic earnings per unit	$	1.39		$	0.62		$	2.59		$	1.40
Diluted earnings per unit	$	1.39		$	0.62		$	2.58		$	1.40

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.

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Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in applying the various valuation techniques. Inputs broadly refer to the assumptions that market participants use to make pricing decisions, including assumptions about risk. Level 1 inputs are given the highest priority in the fair value hierarchy while Level 3 inputs are given the lowest priority. The three levels of the fair value hierarchy are as follows:

• Level 1 – Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

• Level 2 – Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date.

• Level 3 – Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

The Company uses a market or income approach for recurring fair value measurements and endeavors to use the best information available. Accordingly, valuation techniques that maximize the use of observable inputs are favored. The assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the placement of assets and liabilities within the levels of the fair value hierarchy.

The Company’s current asset and liability accounts contain certain financial instruments, the most significant of which are trade accounts receivables and trade payables. The Company believes the carrying values of its current assets and liabilities approximate fair value. The Company’s fair value assessment incorporates a variety of considerations, including the short-term duration of the instruments, the Company’s historical incurrence of insignificant bad debt expense and the Company’s expectation of future insignificant bad debt expense, which includes an evaluation of counterparty credit risk.

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The following table provides the assets and liabilities carried at fair value measured on a recurring basis at June 30, 2015 and December 31, 2014:

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	June 30, 2015		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	127.9	$	127.9	$	—	$	—
Other current assets
Derivative asset - current	2.2		—		2.2		—
	$	130.1	$	127.9	$	2.2	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	3.0	$	—	$	3.0	$	—
Other liabilities
Derivative liability - long-term	0.4		—		0.4		—
	$	3.4	$	—	$	3.4	$	—

	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2014		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	87.9	$	87.9	$	—	$	—
Other current assets
Derivative asset - current	1.7		—		1.7		—
	$	89.6	$	87.9	$	1.7	$	—
LIABILITIES
Accrued liabilities
Derivative liability - current	$	4.1	$	—	$	4.1	$	—
Other liabilities
Derivative liability - long-term	0.4		—		0.4		—
	$	4.5	$	—	$	4.5	$	—

As of both June 30, 2015 and December 31, 2014, 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 six months ended June 30, 2015 and 2014, 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 six months ended June 30, 2015 and 2014, there were no adjustments to the fair value 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). 

	June 30, 2015				December 31, 2014
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	353.9	$	365.8	$	354.2	$	351.3

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13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

	Six Months Ended
(in millions)	June 30, 2015			June 30, 2014
Asset retirement obligation balance at beginning of period	$	2.4		$	2.2
Costs incurred to remediate	(0.2		)	(0.2		)
Accretion expense	0.1			0.2
Asset retirement obligation balance at end of period	$	2.3		$	2.2

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 Company's general partner of NTE LP and is referred to as the LTIP. The Company recognized equity-based compensation expense of $2.9 million for each of the three months ended June 30, 2015 and 2014, and $5.5 million and $10.3 million for the six months ended June 30, 2015, and 2014, respectively, related to these plans. For the six months ended June 30, 2015, this expense is included in selling, general and administrative expenses in the condensed consolidated statements of operations and comprehensive income. For the three and six months ended June 30, 2014, this expense is included in both selling, general and administrative expenses ($1.2 million and $5.5 million, respectively) and reorganization and related costs ($1.7 million and $4.8 million, respectively) (see Note 19).

LTIP

Approximately 7.5 million NTE LP common units are reserved for issuance under the LTIP. The LTIP was created concurrent with the IPO and permits the award of unit options, restricted units, phantom units, distribution equivalent rights, unit appreciation rights and other awards that derive their value from the market price of NTE LP’s common units. As of June 30, 2015, approximately 1.1 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. Awards generally vest ratably over a three-year period beginning on the award's first anniversary date. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, the Company estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.

As of June 30, 2015, the total unrecognized compensation cost for units awarded under the LTIP was $18.2 million.

Restricted Common Units

As of June 30, 2015, the Company had 0.3 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 June 30, 2015, 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 June 30, 2015 and December 31, 2014 were $0.8 million and $0.4 million, respectively.

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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, 2014	396.2		$	24.73	1.3
Awarded	1.0		24.90		2.5
Vested	(66.3	)	25.82		—
Nonvested at June 30, 2015	330.9		$	24.51	1.5

Phantom Common Units

Service-based Phantom Common Units

During 2014, the Company began awarding service-based phantom common units to key employees. As of June 30, 2015, the Company had 0.6 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 June 30, 2015 and December 31, 2014, the Company had $1.2 million and $0.8 million, respectively, in accrued service-based phantom common unit distributions included in accrued liabilities in the condensed consolidated balance sheets. For phantom common unit awards outstanding at June 30, 2015, the forfeiture rates on LTIP awards ranged from zero to 20%, depending on the employee classification.

Performance-based Phantom Common Units

In January 2015, the Company granted 0.3 million 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 0.3 million Performance LTIPs include 0.2 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 June 30, 2015, the Company estimates that 200% of the target unit count will be achieved at the end of the vesting term.

Market Condition Awards. The 0.3 million Performance LTIPs include less than 0.1 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 June 30, 2015, 75% of the target unit count will be achieved at the end of the vesting term.

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 June 30, 2015 are presented below:

Expected volatility	34.10	%
Risk-free interest rate	0.84	%

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As of June 30, 2015, the Company had $0.4 million 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, 2014	337.7		—	337.7		$	26.99	2.0
Awarded	419.1		181.0	600.1		23.27		2.4
Incremental performance units	—		67.9	67.9		23.44		2.2
Forfeited	(80.6	)	—	(80.6	)	26.56		—
Vested	(111.2	)	—	(111.2	)	27.01		—
Nonvested at June 30, 2015	565.0		248.9	813.9		$	24.04	2.2

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 2015 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 $1.8 million and $1.4 million for the three months ended June 30, 2015 and 2014, respectively, and $4.0 million and $3.8 million for the six months ended June 30, 2015 and 2014, 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 June 30, 2015 and 2014 was $0.7 million and $0.6 million, respectively, and for the six months ended June 30, 2015 and 2014 was $1.3 million and $1.1 million, respectively, related primarily to current period service costs.

Retiree Medical Plan

The Company also sponsors a plan to provide retirees with health care benefits prior to age 65 (the “Retiree Medical Plan”) for eligible employees. Eligible employees may participate in the Company’s retiree health care benefits after retirement subject to cost-sharing features. To be eligible for the Retiree Medical Plan, employees must have completed at least 10 years of service with the Company or its predecessor and be between the ages of 55 and 65 years old. The net periodic benefit cost related to the Retiree Medical Plan for the three months ended June 30, 2015 and 2014 was $0.2 million and $0.1 million, respectively, and for both the six months ended June 30, 2015 and 2014 was $0.3 million, related primarily to current period and prior service costs.

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16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

	Six Months Ended
(in millions)	June 30, 2015		June 30, 2014
Net cash from operating activities included:
Interest paid	$	13.6	$	11.3
Income taxes paid	0.9		—
Noncash investing and financing activities include:
Capital expenditures included in accounts payable	$	5.5	$	3.3
PP&E derecognized from sale leaseback continuing involvement release	1.8		—
Distributions accrued on unvested equity awards	1.2		—

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 has filed a motion to dismiss the case and is vigorously defending itself. This action is in its preliminary stages and the Company is unable to predict the possible loss or range of loss, if any.

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 June 30, 2015 and December 31, 2014, accruals for remediation and closure obligations totaled $10.2 million and $8.7 million, respectively. Of the $10.2 million and $8.7 million accrued, $2.6 million and $2.9 million are recorded on a discounted basis at June 30, 2015 and December 31, 2014, respectively. These discounted liabilities are expected to be settled over at least the next 22 years. At June 30, 2015, the estimated future cash flows to settle these discounted liabilities totaled $3.3 million, and are discounted at a rate of of 2.90%. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.2 million at both June 30, 2015 and December 31, 2014. 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 now regards the likelihood of future remediation costs related to the lagoon as probable. At June 30, 2015, the Company estimates the remaining remediation costs to be approximately $7.6 million subject to further engineering and methodology studies. Some or all of this cost may be recoverable from Marathon Petroleum under an agreement entered into in connection with the Company's December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon. However, at June 30, 2015 it is unclear how much, if any, of the Company's future costs may be reimbursed by Marathon, and as such, the Company has not recognized any receivable pertaining to this matter at this time.

It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred by the Company or the penalties, if any, that may be imposed. Furthermore, environmental remediation costs may vary from estimates for which a liability has been recorded either in accrued liabilities or other liabilities in the balance sheet because of changes in laws,

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regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology.

Franchise Agreements

In the normal course of its business, SAF enters into ten-year license agreements with the operators of franchised SuperAmerica brand retail outlets. These agreements obligate SAF or its affiliates to provide certain services including information technology support, maintenance, credit card processing and signage for specified monthly fees.

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 165 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

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

	Three Months Ended June 30, 2015
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	660.6	$	299.2	$	—		$	959.8
Intersegment	179.2		—		—			179.2
Segment revenues	839.8		299.2		—			1,139.0
Elimination of intersegment revenues	—		—		(179.2		)	(179.2		)
Total revenues	$	839.8	$	299.2	$	(179.2	)	$	959.8
Income (loss) from operations	$	140.5	$	5.6	$	(6.8	)	$	139.3
Income from equity method investment	$	4.2	$	—	$	—		$	4.2
Depreciation and amortization	$	8.8	$	1.9	$	0.1		$	10.8
Capital expenditures	$	9.7	$	1.2	$	0.2		$	11.1

	Three Months Ended June 30, 2014
(in millions)	Refining			Retail		Other			Total
Revenues
Customer	$	1,231.6		$	370.9	$	—		$	1,602.5
Intersegment	255.1			—		—			255.1
Segment revenues	1,486.7			370.9		—			1,857.6
Elimination of intersegment revenues	—			—		(255.1		)	(255.1		)
Total revenues	$	1,486.7		$	370.9	$	(255.1	)	$	1,602.5
Income (loss) from operations	$	72.8		$	5.0	$	(12.2	)	$	65.6
Income from equity method investment	$	(2.4	)	$	—	$	—		$	(2.4	)
Depreciation and amortization	$	8.3		$	1.7	$	0.2		$	10.2
Capital expenditures	$	11.9		$	3.2	$	—		$	15.1

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	Six Months Ended June 30, 2015
(in millions)	Refining		Retail		Other			Total
Revenues
Customer	$	1,205.7	$	547.9	$	—		$	1,753.6
Intersegment	323.7		—		—			323.7
Segment revenues	1,529.4		547.9		—			2,077.3
Elimination of intersegment revenues	—		—		(323.7		)	(323.7		)
Total revenues	$	1,529.4	$	547.9	$	(323.7	)	$	1,753.6
Income (loss) from operations	$	263.6	$	8.3	$	(13.1	)	$	258.8
Income from equity method investment	$	7.8	$	—	$	—		$	7.8
Depreciation and amortization	$	17.5	$	3.7	$	0.4		$	21.6
Capital expenditures	$	14.3	$	3.1	$	0.3		$	17.7

	Six Months Ended June 30, 2014
(in millions)	Refining			Retail		Other			Total
Revenues
Customer	$	2,242.8		$	706.0	$	—		$	2,948.8
Intersegment	487.5			—		—			487.5
Segment revenues	2,730.3			706.0		—			3,436.3
Elimination of intersegment revenues	—			—		(487.5		)	(487.5		)
Total revenues	$	2,730.3		$	706.0	$	(487.5	)	$	2,948.8
Income (loss) from operations	$	170.6		$	6.7	$	(33.9	)	$	143.4
Income (loss) from equity method investment	$	(0.9	)	$	—	$	—		$	(0.9	)
Depreciation and amortization	$	16.3		$	3.4	$	0.4		$	20.1
Capital expenditures	$	20.7		$	4.3	$	0.1		$	25.1

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 June 30, 2015	$	1,022.4	$	136.8	$	149.4	$	1,308.6
At December 31, 2014	$	932.9	$	134.0	$	113.5	$	1,180.4

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.

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19. REORGANIZATION AND RELATED COSTS

During the first quarter of 2014, the Company initiated a plan that included a planned relocation of its corporate offices from Ridgefield, Connecticut to Tempe, Arizona and the reorganization of various positions within the Company, primarily among senior management. In relation to this reorganization plan, it was determined during the six months ended June 30, 2014 that certain employees of the Company would be terminated. The Company recognized $12.9 million of expense during the six months ended June 30, 2014, which included compensation related to the severance of employment and the acceleration of unvested equity-based compensation. These costs are recognized in the reorganization and related costs line within the condensed consolidated statements of operations and comprehensive income. All reorganization and related costs are recognized in the Other segment. As of June 30, 2015, the Company had $0.5 million in unpaid reorganization expenses included in the accrued liabilities line item of the condensed consolidated balance sheets, which will be paid through 2016.

	Six Months Ended
(in millions)	June 30, 2015			June 30, 2014
Unpaid restructuring costs at beginning of period	$	0.8		$	—
Reorganization and related costs incurred during period	—			12.9
Less: non-cash equity-based awards with accelerated vesting	—			(4.8		)
Cash payments made to severed employees	(0.3		)	(6.2		)
Ending liability for cash portion of reorganization costs	$	0.5		$	1.9

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our financial statements and related notes included elsewhere in this 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 six months ended June 30, 2015, we had total revenues of $1,753.6 million, operating income of $258.8 million, net income of $240.1 million and Adjusted EBITDA of $239.9 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.”

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 only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the PADD II region. Our refinery processes a variety of light, heavy, sweet and sour crudes, many of which have historically priced at a discount to the NYMEX WTI price benchmark. We are able to 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 operates 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.

Retail Business

As of June 30, 2015, our retail business operated 165 convenience stores under the SuperAmerica brand and also supported 99 franchised convenience stores, which are also operated under the SuperAmerica brand. These convenience stores are located primarily in Minnesota and Wisconsin and sell various grades of gasoline and diesel, tobacco products and immediately consumable items such as beverages, prepared food and a large variety of snacks and prepackaged items. Our refinery 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, 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.

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Consolidated Financial Data

	Three Months Ended						Six Months Ended
(in millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Revenue	$	959.8		$	1,602.5		$	1,753.6		$	2,948.8
Costs, expenses and other:
Cost of sales	714.6			1,432.0			1,291.1			2,588.3
Direct operating expenses	76.3			65.4			145.6			131.8
Turnaround and related expenses	1.2			0.9			1.6			1.4
Depreciation and amortization	10.8			10.2			21.6			20.1
Selling, general and administrative expenses	22.2			22.7			42.4			49.7
Reorganization and related costs	—			3.5			—			12.9
(Income) loss from equity method investment	(4.2		)	2.4			(7.8		)	0.9
Other (gain) loss, net	(0.4		)	(0.2		)	0.3			0.3
Operating income	139.3			65.6			258.8			143.4
Interest expense, net	(7.5		)	(6.2		)	(15.0		)	(12.4		)
Income before income taxes	131.8			59.4			243.8			131.0
Income tax provision	(2.9		)	(1.5		)	(3.7		)	(1.6		)
Net income	$	128.9		$	57.9		$	240.1		$	129.4

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Revenue. Revenue for the three months ended June 30, 2015 was $959.8 million compared to $1,602.5 million for the three months ended June 30, 2014, a decrease of 40.1%. Refining segment revenue decreased43.5% and retail segment revenue decreased19.3% compared to the three months ended June 30, 2014. Refining revenue decreased primarily due to lower refined product prices due to market conditions, partially offset by higher sales volumes of 1.3% in the 2015 period. Retail revenue decreased primarily due to lower fuel prices due to market conditions, partially offset by $5.9 million higher merchandise revenue. Excise taxes included in revenue increased by $3.8 million for the 2015 period over the 2014 period driven primarily by higher sales volumes in the refining segment.

Cost of sales. Cost of sales totaled $714.6 million for the three months ended June 30, 2015 compared to $1,432.0 million for the three months ended June 30, 2014, a decrease of 50.1%. Refining segment cost of sales decreased52.8% and retail segment cost of sales decreased23.1% compared to the three months ended June 30, 2014. The decreased cost in the refining segment was primarily due to lower crude oil costs, including a $37.2 million benefit from a lower of cost or market inventory adjustment in the 2015 period, partially offset by an increase of 1.3% in refining sales volumes. Likewise, retail segment cost of sales decreased due to lower costs of fuel products. Lastly, excise taxes included in cost of sales increased by $3.8 million for the 2015 period over the 2014 period driven primarily by higher sales volumes in the refining segment.

Direct operating expenses. Direct operating expenses totaled $76.3 million for the three months ended June 30, 2015 compared to $65.4 million for the three months ended June 30, 2014, an increase of 16.7%, due primarily to higher personnel costs as a result of higher throughput levels in 2015, higher contractor costs and material costs related to our flare emission reduction plan, all within the refining segment. These increases were partially offset by lower natural gas costs, also within our refining segment, during the three months ended June 30, 2015.

Turnaround and related expenses. Turnaround and related expenses totaled $1.2 million for the three months ended June 30, 2015 compared to $0.9 million for the three months ended June 30, 2014. The turnaround costs in the three months ended June 30, 2015 include planning costs for a third quarter 2015 turnaround and related costs on one of our reformers and our distillate hydrotreater unit. Such costs in the corresponding 2014 period relates to a partial turnaround of our hydrogen unit.

Depreciation and amortization. Depreciation and amortization was $10.8 million for the three months ended June 30, 2015 compared to $10.2 million for the three months ended June 30, 2014, an increase of 5.9%. This increase was primarily due to increased refining assets placed in service since June 30, 2014, the most significant of which was our updated waste water treatment plant.

Selling, general and administrative expenses. Selling, general and administrative expenses were $22.2 million for the three months ended June 30, 2015 compared to $22.7 million for the three months ended June 30, 2014. This decrease of 2.2% relates primarily to lower insurance and professional service costs. This overall decrease was partially offset by higher equity-based compensation expense.

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Reorganization and related costs. Reorganization and related costs for the three months ended June 30, 2014 was $3.5 million. There were no reorganization and related costs for the three months ended June 30, 2015. The decrease was due to costs incurred in connection with the relocation of our corporate office and reorganization of various positions within the Company in the second quarter of 2014. We believe substantially all costs related to this corporate reorganization were fully recognized as of June 30, 2014.

(Income) loss from equity method investment. (Income) loss from equity method investment was $(4.2) million for the three months ended June 30, 2015 compared to $2.4 million for the three months ended June 30, 2014. This increase was driven by an increase in the equity income of MPL due to non-routine maintenance expense projects on the pipeline in the 2014 period.

Other (gain) loss, net. Other (gain) loss, net was a $0.4 million net gain for the three months ended June 30, 2015 compared to a $0.2 million net gain for the three months ended June 30, 2014.

Interest expense, net. Interest expense, net was $7.5 million for the three months ended June 30, 2015 and $6.2 million for the three months ended June 30, 2014. This increase relates primarily to higher interest expense from the additional debt issued in the Company's $75.0 million secured note offering in September 2014 as well as higher commitment fees on our expanded ABL Facility, which we completed in September 2014. Interest charges for both periods relate primarily to our senior secured notes, commitment fees, interest on the ABL Facility and the amortization of deferred financing costs.

Income tax provision. The income tax provision for the three months ended June 30, 2015 was $2.9 million compared to $1.5 million for the three months ended June 30, 2014. This increase was due primarily to higher income generated by our retail segment.

Net income. Our net income was $128.9 million for the three months ended June 30, 2015 compared to $57.9 million for the three months ended June 30, 2014. This increase in net income is primarily attributable to a $74.7 millionincrease in gross profit and a $6.6 millionincrease in income from our equity method investment. This overall increase was partially offset by $10.9 million higher direct operating expenses.

Six Months EndedJune 30, 2015 Compared to the Six Months EndedJune 30, 2014

Revenue. Revenue for the six months ended June 30, 2015 was $1,753.6 million compared to $2,948.8 million for the six months ended June 30, 2014, a decrease of 40.5%. Refining segment revenue decreased44.0% and retail segment revenue decreased22.4% compared to the six months ended June 30, 2014. Refining revenue decreased primarily due to lower refined product prices due to market conditions, partially offset by increased sales volumes of 5.6% in the 2015 period. Retail revenue decreased primarily due to lower fuel prices due to market conditions, partially offset by $10.0 million higher merchandise revenue. Excise taxes included in revenue increased by $10.9 million for the 2015 period over the 2014 period driven primarily by higher sales volumes in our refining segment.

Cost of sales. Cost of sales totaled $1,291.1 million for the six months ended June 30, 2015 compared to $2,588.3 million for the six months ended June 30, 2014, a decrease of 50.1%. Refining segment cost of sales decreased52.9% and retail segment cost of sales decreased26.3% compared to the six months ended June 30, 2014. The decreased cost in the refining segment was primarily due to lower crude oil costs, including a $47.7 million benefit from a lower of cost or market inventory adjustment in the 2015 period, partially offset by an increase of 5.6% in refining sales volumes. Lastly, excise taxes included in cost of sales increased by $10.9 million for the 2015 period over the 2014 period driven primarily by higher sales volumes in the refining segment.

Direct operating expenses. Direct operating expenses totaled $145.6 million for the six months ended June 30, 2015 compared to $131.8 million for the six months ended June 30, 2014, an increase of 10.5%, due primarily to the impact of higher personnel costs and chemical costs as a result of higher throughput levels in 2015, higher material costs and contractor labor costs in 2015 due primarily to our flare emissions reduction plan, all within our refining segment. These increases were partially offset by lower natural gas costs, also within our refining segment, during the six months ended June 30, 2015.

Turnaround and related expenses. Turnaround and related expenses totaled $1.6 million for the six months ended June 30, 2015 compared to $1.4 million for the six months ended June 30, 2014. The turnaround costs in the six months ended June 30, 2015 included planning costs for a third quarter 2015 turnaround and related costs on one of our reformers and our distillate hydrotreater unit. The 2014 periods included costs for a partial turnaround of our hydrogen unit, which occurred in the second quarter of 2014.

Depreciation and amortization. Depreciation and amortization was $21.6 million for the six months ended June 30, 2015 compared to $20.1 million for the six months ended June 30, 2014, an increase of 7.5%. This increase was due primarily to increased refining assets placed in service since June 30, 2014, the most significant of which was our updated waste water treatment plant.

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Selling, general and administrative expenses. Selling, general and administrative expenses were $42.4 million for the six months ended June 30, 2015 compared to $49.7 million for the six months ended June 30, 2014. This decrease of 14.7% relates primarily to lower variable compensation expense, insurance and professional service costs.

Reorganization and related costs. Reorganization and related costs for the six months ended June 30, 2014 was $12.9 million. There were no reorganization and related costs for the six months ended June 30, 2015. The decrease was due to costs incurred in connection with the relocation of our corporate office and reorganization of various positions within the Company in the first and second quarters of 2014. We believe substantially all costs related to this corporate reorganization were fully recognized as of June 30, 2014.

(Income) loss from equity method investment. (Income) loss from equity method investment was $(7.8) million for the six months ended June 30, 2015 compared to $0.9 million for the six months ended June 30, 2014. This increase was driven by an increase in the equity income of MPL due to non-routine maintenance expense projects on the pipeline in the 2014 period.

Other (gain) loss, net. Other (gain) loss, net was a $0.3 million loss for both the six months ended June 30, 2015 and 2014.

Interest expense, net. Interest expense, net was $15.0 million for the six months ended June 30, 2015 and $12.4 million for the six months ended June 30, 2014. This increase relates primarily to higher interest expense from the Company's $75.0 million secured note offering in September 2014 as well as higher commitment fees on our expanded ABL Facility, which we completed in September 2014. Interest charges for both periods relate primarily to our senior secured notes, commitment fees, interest on the ABL Facility and the amortization of deferred financing costs.

Income tax provision. The income tax provision for the six months ended June 30, 2015 was $3.7 million compared to $1.6 million for the six months ended June 30, 2014. This increase was due primarily to higher income generated by our retail segment.

Net income. Our net income was $240.1 million for the six months ended June 30, 2015 compared to $129.4 million for the six months ended June 30, 2014. This increase in net income is primarily attributable to a $102.0 millionincrease in gross profit, a $12.9 million reduction in costs associated with our reorganization and an $8.7 millionincrease in income from our equity method investment. This overall increase was partially offset by higher direct operating expenses of $13.8 million.

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 June 30, 2015
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	660.6	$	299.2	$	—		$	959.8
Intersegment sales	179.2		—		(179.2		)	—
Segment revenue	$	839.8	$	299.2	$	(179.2	)	$	959.8
Cost of sales:
Cost of sales	$	641.9	$	72.7	$	—		$	714.6
Intersegment purchases	—		179.2		(179.2		)	—
Segment cost of sales	$	641.9	$	251.9	$	(179.2	)	$	714.6

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	Three Months Ended June 30, 2014
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	1,231.6	$	370.9	$	—		$	1,602.5
Intersegment sales	255.1		—		(255.1		)	—
Segment revenue	$	1,486.7	$	370.9	$	(255.1	)	$	1,602.5
Cost of sales:
Cost of sales	$	1,359.5	$	72.5	$	—		$	1,432.0
Intersegment purchases	—		255.1		(255.1		)	—
Segment cost of sales	$	1,359.5	$	327.6	$	(255.1	)	$	1,432.0

	Six Months Ended June 30, 2015
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	1,205.7	$	547.9	$	—		$	1,753.6
Intersegment sales	323.7		—		(323.7		)	—
Segment revenue	$	1,529.4	$	547.9	$	(323.7	)	$	1,753.6
Cost of sales:
Cost of sales	$	1,155.6	$	135.5	$	—		$	1,291.1
Intersegment purchases	—		323.7		(323.7		)	—
Segment cost of sales	$	1,155.6	$	459.2	$	(323.7	)	$	1,291.1

	Six Months Ended June 30, 2014
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	2,242.8	$	706.0	$	—		$	2,948.8
Intersegment sales	487.5		—		(487.5		)	—
Segment revenue	$	2,730.3	$	706.0	$	(487.5	)	$	2,948.8
Cost of sales:
Cost of sales	$	2,452.4	$	135.9	$	—		$	2,588.3
Intersegment purchases	—		487.5		(487.5		)	—
Segment cost of sales	$	2,452.4	$	623.4	$	(487.5	)	$	2,588.3

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Refining Segment

	Three Months Ended						Six Months Ended
(in millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Revenue	$	839.8		$	1,486.7		$	1,529.4		$	2,730.3
Costs, expenses and other:
Cost of sales	641.9			1,359.5			1,155.6			2,452.4
Direct operating expenses	43.2			35.3			82.1			72.7
Turnaround and related expenses	1.2			0.9			1.6			1.4
Depreciation and amortization	8.8			8.3			17.5			16.3
Selling, general and administrative expenses	8.9			8.0			16.9			16.2
(Income) loss from equity method investment	(4.2		)	2.4			(7.8		)	0.9
Other gain	(0.5		)	(0.5		)	(0.1		)	(0.2		)
Operating income	$	140.5		$	72.8		$	263.6		$	170.6
Key Operating Statistics
Refining gross margin (in millions)(3)	$	197.9		$	127.2		$	373.8		$	277.9
Total refinery production (bpd)(1)	98,722			93,342			96,529			93,139
Total refinery throughput (bpd)	98,954			93,022			96,544			92,826
Refined products sold (bpd)(2)	103,778			102,409			101,144			95,822
Per barrel of throughput:
Refining gross margin(3)	$	21.98		$	15.03		$	21.39		$	16.54
Direct operating expenses(4)	$	4.80		$	4.17		$	4.70		$	4.33
Per barrel of refined products sold:
Refining gross margin(3)	$	20.96		$	13.65		$	20.42		$	16.02
Direct operating expenses(4)	$	4.57		$	3.79		$	4.48		$	4.19
Refinery product yields (bpd):
Gasoline	46,605			46,747			45,786			44,859
Distillate(5)	34,744			34,483			34,005			35,063
Asphalt	12,040			5,494			11,072			6,663
Other(6)	5,333			6,618			5,666			6,554
Total	98,722			93,342			96,529			93,139
Refinery throughput (bpd):
Crude oil	97,027			91,853			94,299			91,964
Other feedstocks(7)	1,927			1,169			2,245			862
Total	98,954			93,022			96,544			92,826

(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.

(4) Direct operating expenses per barrel is calculated by dividing direct operating expenses by the total barrels of throughput or total barrels of refined products sold for the respective periods presented.

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

(6) Other refinery products include propane, propylene, liquid sulfur and No. 6 fuel oil, among others. None of these products, by itself, contributes significantly to overall refinery product yields.

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(7) Other feedstocks include gas oil, natural gasoline, normal butane and isobutane, among others. None of these feedstocks, by itself, contributes significantly to overall refinery throughput.

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

Refining gross margin. Refining gross margin for the three months ended June 30, 2015 was $197.9 million compared to $127.2 million for the three months ended June 30, 2014, an increase of 55.6%, primarily due to a 53.6%increase in gross margin per barrel sold and a volume increase of 1.3% in barrels sold as a result of higher throughput in the three months ended June 30, 2015. Additionally, the Company realized a benefit of $37.2 million in the three months ended June 30, 2015 from a lower of cost or market inventory adjustment.

Direct operating expenses. Direct operating expenses totaled $43.2 million for the three months ended June 30, 2015 compared to $35.3 million for the three months ended June 30, 2014, a 22.4%increase. This increase was due primarily to higher personnel costs as a result of higher throughput levels in 2015, higher contractor costs and material costs related to our flare emission reduction plan. These increases were partially offset by lower natural gas cost during the three months ended June 30, 2015.

Turnaround and related expenses. Turnaround and related expenses totaled $1.2 million for the three months ended June 30, 2015 compared to $0.9 million for the three months ended June 30, 2014. The turnaround costs in the three months ended June 30, 2015 include planning costs for a third quarter 2015 turnaround on one of our reformers and our distillate hydrotreater unit. Cost in the 2014 period relates to a partial turnaround of our hydrogen unit.

Depreciation and amortization. Depreciation and amortization was $8.8 million for the three months ended June 30, 2015 compared to $8.3 million for the three months ended June 30, 2014, an increase of 6.0%. This increase was due primarily to increased assets placed in service since June 30, 2014, the most significant of which was our updated waste water treatment plant.

Selling, general and administrative expenses. Selling, general and administrative expenses were $8.9 million and $8.0 million for the three months ended June 30, 2015 and 2014, respectively. This increase was due primarily to higher equity-based compensation expense partially offset by lower insurance costs.

(Income) loss from equity method investment. (Income) loss from equity method investment was $(4.2) million for the three months ended June 30, 2015 compared to $2.4 million for the three months ended June 30, 2014. This increase was driven by an increase in the equity income of MPL due to non-routine maintenance expense projects on the pipeline in the 2014 period.

Other gain. Other gain was $0.5 million for both the three months ended June 30, 2015 and 2014.

Operating income. Income from operations was $140.5 million for the three months ended June 30, 2015 compared to $72.8 million for the three months ended June 30, 2014. This increase from the prior-year period of $67.7 million is primarily due to higher refinery gross margin of $70.7 million and higher income from equity method investments of $6.6 million. The overall increase in operating income was partially offset by higher direct operating expenses of $7.9 million.

Six Months EndedJune 30, 2015 Compared to the Six Months EndedJune 30, 2014

Refining gross margin. Refining gross margin for the six months ended June 30, 2015 was $373.8 million compared to $277.9 million for the six months ended June 30, 2014, an increase of 34.5%, primarily due to a 27.5%increase in gross margin per barrel sold. Additionally, gross margin increased due to 5.6% higher sales volumes as a result of higher throughput in the six months ended June 30, 2015. Additionally, the Company realized a benefit of $47.7 million in the six months ended June 30, 2015 from a lower of cost or market inventory adjustment.

Direct operating expenses. Direct operating expenses totaled $82.1 million for the six months ended June 30, 2015 compared to $72.7 million for the six months ended June 30, 2014, a 12.9%increase. This increase was due primarily to the impact of higher personnel costs and chemical costs as a result of higher throughput levels in 2015, higher material costs and contractor labor costs in 2015 due primarily to our flare emissions reduction plan and a tank freeze. These increases were partially offset by lower natural gas costs in the 2015 period.

Turnaround and related expenses. Turnaround and related expenses totaled $1.6 million for the six months ended June 30, 2015 compared to $1.4 million for the six months ended June 30, 2014. The turnaround costs in the six months ended June 30, 2015 include planning costs for a third quarter 2015 turnaround on one of our reformers and our distillate hydrotreater unit. The 2014 period included costs for a partial turnaround of our hydrogen unit, which occurred in the second quarter of 2014.

Depreciation and amortization. Depreciation and amortization was $17.5 million for the six months ended June 30, 2015 compared to $16.3 million for the six months ended June 30, 2014, an increase of 7.4%. This increase was due primarily

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to increased assets placed in service since June 30, 2014, the most significant of which was our updated waste water treatment plant.

Selling, general and administrative expenses. Selling, general and administrative expenses were $16.9 million and $16.2 million for the six months ended June 30, 2015 and 2014, respectively. This increase was driven primarily by higher equity-based compensation expense, partially offset by lower insurance costs.

(Income) loss from equity method investment. (Income) loss from equity method investment was $(7.8) million for the six months ended June 30, 2015 compared to $0.9 million for the six months ended June 30, 2014. This increase was driven by an increase in the equity income of MPL due to non-routine maintenance expense projects on the pipeline in the 2014 period.

Other gain. Other gain was $0.1 million for the six months ended June 30, 2015 compared to $0.2 million for the six months ended June 30, 2014.

Operating income. Income from operations was $263.6 million for the six months ended June 30, 2015 compared to $170.6 million for the six months ended June 30, 2014. This increase from the prior-year period of $93.0 million is primarily due to higher refinery gross margin of $95.9 million and higher income from equity method investments of $8.7 million. The overall increase in operating income was partially offset by higher direct operating expenses of $9.4 million.

Retail Segment

	Three Months Ended						Six Months Ended
(in millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Revenue	$	299.2		$	370.9		$	547.9		$	706.0
Costs, expenses and other:
Cost of sales	251.9			327.6			459.2			623.4
Direct operating expenses	33.1			30.1			63.5			59.1
Depreciation and amortization	1.9			1.7			3.7			3.4
Selling, general and administrative expenses	6.7			6.5			13.2			13.4
Operating income	$	5.6		$	5.0		$	8.3		$	6.7
Operating data:
Retail gross margin(1)	$	47.3		$	43.3		$	88.7		$	82.6
Company-operated stores:
Fuel gallons sold (in millions)	77.4			76.8			149.3			149.8
Fuel margin per gallon(2)	$	0.22		$	0.19		$	0.21		$	0.19
Merchandise sales	$	95.8		$	89.9		$	178.4		$	168.4
Merchandise margin %(3)	25.9		%	26.5		%	25.9		%	26.2		%
Number of stores at period end	165			164			165			164
Franchise stores:
Fuel gallons sold (in millions)(4)	28.1			18.3			51.4			32.5
Royalty income	$	0.9		$	0.7		$	1.7		$	1.3
Number of stores at period end	99			81			99			81

(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) 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.

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Merchandise margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. Merchandise margin includes all non-fuel sales at our company-operated stores including items like cigarettes, beer, milk, food, general merchandise, car wash and other commission-based revenue. For a reconciliation of merchandise margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.”

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

Three Months Ended June 30, 2015 Compared to the Three Months Ended June 30, 2014

    Retail gross margin. Retail gross margin for the three months ended June 30, 2015 was $47.3 million compared to $43.3 million for the three months ended June 30, 2014, an increase of 9.2%. This increase was primarily due to $0.03 higher fuel margins per gallon at our company-operated stores. Our fuel volumes sold at company-operated stores increased by 0.8% and our merchandise margin increased by 4.2%. Additionally, the Company realized a $1.0 million benefit from a lower of cost or market inventory adjustment during the three months ended June 30, 2015. When combining gallons sold at our company-operated stores and gallons sold by refinery to our franchised stores, volumes increased10.9%.

Direct operating expenses. Direct operating expenses totaled $33.1 million and $30.1 million for the three months ended June 30, 2015 and 2014, respectively. This increase was due primarily to higher personnel costs and property tax costs during the 2015 period, which was partially offset by lower fees on debit and credit card transactions.

Depreciation and amortization. Depreciation and amortization was $1.9 million and $1.7 million for the three months ended June 30, 2015 and 2014, respectively. This increase was primarily due to increased retail assets placed in service since June 30, 2014.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.7 million and $6.5 million for the three months ended June 30, 2015 and 2014, respectively, an increase of 3.1%. The increase relates primarily to higher non equity-based personnel costs and information technology costs, partially offset by lower costs for insurance in the three months ended June 30, 2015.

Operating income. Operating income was $5.6 million for the three months ended June 30, 2015 compared to $5.0 million for the three months ended June 30, 2014, an increase of $0.6 million. The increase is primarily attributable to higher gross margins of $4.0 million during the three months ended June 30, 2015, partially offset by higher direct operating expenses of $3.0 million.

Six Months EndedJune 30, 2015 Compared to the Six Months EndedJune 30, 2014

Retail gross margin. Retail gross margin for the six months ended June 30, 2015 was $88.7 million compared to $82.6 million for the six months ended June 30, 2014, an increase of 7.4%. This increase was primarily due to $0.02 higher fuel margins per gallon at our company-operated stores and higher non-fuel margin of $2.7 million. Additionally, the Company realized a $1.3 million benefit from a lower of cost or market inventory adjustment during the six months ended June 30, 2015. These increases were partially offset by lower fuel volumes at our company-operated stores although total fuel gallons sold, including both company-operated and franchised stores, increased 10.1%.

Direct operating expenses. Direct operating expenses totaled $63.5 million and $59.1 million for the six months ended June 30, 2015 and 2014, respectively. This increase was due to higher personnel costs and property tax costs during the 2015 period, which was partially offset by lower fees on debit and credit card transactions.

Depreciation and amortization. Depreciation and amortization was $3.7 million and $3.4 million for the six months ended June 30, 2015 and 2014, respectively. This increase was primarily due to increased retail assets placed in service since June 30, 2014.

Selling, general and administrative expenses. Selling, general and administrative expenses were $13.2 million and $13.4 million for the six months ended June 30, 2015 and 2014, respectively, a decrease of 1.5%. The decrease relates primarily to lower costs for insurance in the six months ended June 30, 2015, partially offset by higher non equity-based personnel costs.

Operating income. Operating income was $8.3 million for the six months ended June 30, 2015 compared to $6.7 million for the six months ended June 30, 2014, an increase of $1.6 million. The increase is primarily attributable to higher gross margins of $6.1 million during the six months ended June 30, 2015, partially offset by higher direct operating expenses of $4.4 million.

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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, 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.

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 June 30, 2015
(in millions)	Refining			Retail			Other			Total
Net income (loss)	$	140.5		$	2.7		$	(14.3	)	$	128.9
Adjustments:
Interest expense	—			—			7.5			7.5
Income tax provision	—			2.9			—			2.9
Depreciation and amortization	8.8			1.9			0.1			10.8
EBITDA subtotal	149.3			7.5			(6.7		)	150.1
Lower of cost or market inventory adjustment (a)	(37.2		)	(1.0		)	—			(38.2		)
MPL proportionate depreciation expense	0.7			—			—			0.7
Turnaround and related expenses	1.2			—			—			1.2
Equity-based compensation expense	0.7			0.1			2.1			2.9
Adjusted EBITDA	$	114.7		$	6.6		$	(4.6	)	$	116.7
(a) represents an adjustment to reduce an inventory reserve established at December 31, 2014, which adjusted cost on a LIFO basis to its lower market value.

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	Three Months Ended June 30, 2014
(in millions)	Refining		Retail		Other			Total
Net income (loss)	$	72.8	$	3.5	$	(18.4	)	$	57.9
Adjustments:
Interest expense	—		—		6.2			6.2
Income tax provision	—		1.5		—			1.5
Depreciation and amortization	8.3		1.7		0.2			10.2
EBITDA subtotal	81.1		6.7		(12.0		)	75.8
MPL proportionate depreciation expense	0.7		—		—			0.7
Turnaround and related expenses	0.9		—		—			0.9
Equity-based compensation expense, including the effect of award accelerations from reorganization	—		—		2.9			2.9
Reorganization and related costs, excluding equity based compensation	—		—		1.8			1.8
Adjusted EBITDA	$	82.7	$	6.7	$	(7.3	)	$	82.1

	Six Months Ended June 30, 2015
(in millions)	Refining			Retail			Other			Total
Net income (loss)	$	263.6		$	4.6		$	(28.1	)	$	240.1
Adjustments:
Interest expense	—			—			15.0			15.0
Income tax provision	—			3.7			—			3.7
Depreciation and amortization	17.5			3.7			0.4			21.6
EBITDA subtotal	281.1			12.0			(12.7		)	280.4
Lower of cost or market inventory adjustment (a)	(47.7		)	(1.3		)	—			(49.0		)
MPL proportionate depreciation expense	1.4			—			—			1.4
Turnaround and related expenses	1.6			—			—			1.6
Equity-based compensation expense	1.3			0.2			4.0			5.5
Adjusted EBITDA	$	237.7		$	10.9		$	(8.7	)	$	239.9
(a) represents an adjustment to reduce an inventory reserve established at December 31, 2014, which adjusted cost on a LIFO basis to its lower market value.

	Six Months Ended June 30, 2014
(in millions)	Refining		Retail		Other			Total
Net income (loss)	$	170.6	$	5.1	$	(46.3	)	$	129.4
Adjustments:
Interest expense	—		—		12.4			12.4
Income tax provision	—		1.6		—			1.6
Depreciation and amortization	16.3		3.4		0.4			20.1
EBITDA subtotal	186.9		10.1		(33.5		)	163.5
MPL proportionate depreciation expense	1.4		—		—			1.4
Turnaround and related expenses	1.4		—		—			1.4
Equity-based compensation expense, including the effect of award accelerations from reorganization	—		—		10.3			10.3
Reorganization and related costs, excluding equity based compensation	—		—		8.1			8.1
Adjusted EBITDA	$	189.7	$	10.1	$	(15.1	)	$	184.7

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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.

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				Six Months Ended
(in millions)	June 30, 2015		June 30, 2014		June 30, 2015		June 30, 2014
Refining revenue	$	839.8	$	1,486.7	$	1,529.4	$	2,730.3
Refining cost of sales	641.9		1,359.5		1,155.6		2,452.4
Refining gross margin	$	197.9	$	127.2	$	373.8	$	277.9

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.”

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	Three Months Ended						Six Months Ended
(in millions)	June 30, 2015			June 30, 2014			June 30, 2015			June 30, 2014
Retail revenue:
Fuel revenue	$	198.4		$	273.7		$	359.9		$	523.1
Merchandise revenue	95.8			89.9			178.4			168.4
Other revenue	9.8			11.9			18.7			23.2
Intercompany eliminations	(4.8		)	(4.6		)	(9.1		)	(8.7		)
Retail revenue	299.2			370.9			547.9			706.0
Retail cost of sales:
Fuel cost of sales	181.5			259.2			327.8			494.4
Merchandise cost of sales	71.0			66.1			132.2			124.3
Other cost of sales	4.2			6.9			8.3			13.4
Intercompany eliminations	(4.8		)	(4.6		)	(9.1		)	(8.7		)
Retail cost of sales	251.9			327.6			459.2			623.4
Retail gross margin:
Fuel margin	16.9			14.5			32.1			28.7
Merchandise margin	24.8			23.8			46.2			44.1
Other margin	5.6			5.0			10.4			9.8
Intercompany eliminations	—			—			—			—
Retail gross margin	$	47.3		$	43.3		$	88.7		$	82.6

Liquidity and Capital Resources

Our primary sources of liquidity have traditionally been cash generated from our operating activities and availability under the 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 could 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 financial condition and credit rating. For discussions on our refinery gross margin per barrel and retail fuel margin per gallon and merchandise margin for company-operated stores, see “Results of Operations—Refining Segment” and “—Retail Segment,” above.

On September 29, 2014, NTE LLC 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 June 30, 2015, the borrowers under the ABL Facility had no outstanding balance under the ABL Facility. The borrowing base under the ABL Facility was $284.1 million and availability under the ABL Facility was $253.5 million (which is net of $30.6 million in outstanding letters of credit).

As of June 30, 2015, we had $353.9 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the “2020 Secured Notes”). On September 29, 2014, the Company issued an additional $75.0 million of the 2020 Secured Notes at 105.75% of par for gross proceeds of $79.2 million. This offering was issued under the same indenture and associated terms as the existing 2020 Secured Notes. The Company incurred financing costs of $2.5 million associated with this offering. The issuance premium of $4.2 million and financing costs of $2.5 million associated with this offering will both be amortized as a net reduction to interest expense over the remaining life of the notes. The proceeds from the September 2014 offering were used to purchase crude oil inventories in connection with the wind-down of our crude oil supply and logistics

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agreement (as amended, the "Crude Intermediation Agreement") with J.P. Morgan Commodities Canada Corporation ("JPM CCC").

During the first quarter of 2014, we initiated a plan that included a relocation of our corporate offices and the reorganization of various positions, primarily among senior management. In relation to this reorganization plan, it was determined during the six months ended June 30, 2014 that certain employees would be terminated. As such, we recognized $12.9 million of expense during the six months ended June 30, 2014, which included compensation related to the severance of employment and the acceleration of unvested equity-based compensation. As of June 30, 2015, remaining cash payments under this reorganization plan are estimated to be $0.5 million, which will be paid through 2016.

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:

	Six Months Ended
(in millions)	June 30, 2015			June 30, 2014
Net cash provided by operating activities	$	203.2		$	154.3
Net cash used in investing activities	(17.7		)	(23.7		)
Net cash used in financing activities	(145.5		)	(109.5		)
Net increase in cash and cash equivalents	40.0			21.1
Cash and cash equivalents at beginning of period	87.9			85.8
Cash and cash equivalents at end of period	$	127.9		$	106.9

Net Cash Provided By Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2015 was $203.2 million. The most significant sources of cash were our net income ($240.1 million) adjusted for non-cash expenses, such as depreciation and amortization expense ($21.6 million) and equity-based compensation ($5.5 million). We also recognized a non-cash change of $49.0 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 investment in working capital of $12.5 million.

Net cash provided by operating activities for the six months ended June 30, 2014 was $154.3 million. The most significant sources of cash were our net income ($129.4 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($20.1 million) and equity-based compensation ($10.3 million). Additionally, cash was negatively impacted by a net investment in working capital of $7.3 million.

The increase in cash provided by operating activities of $48.9 million versus the prior year is primarily due to higher net income of $110.7 million, reduced for the non-cash inventory adjustment related to lower of cost or market ($49.0 million) and lower equity-based compensation expense ($4.8 million).

Net Cash Used In Investing Activities. Net cash used in investing activities for the six months ended June 30, 2015 of $17.7 million was primarily related to capital expenditures. Capital spending for the six months ended June 30, 2015 primarily included the desalter project, fire water tanks, crude unit capacity improvements on our Number 2 crude unit and the flare instrumentation project, all within our refining segment.

Net cash used in investing activities for the six months ended June 30, 2014 was $23.7 million, relating primarily to capital expenditures of $25.1 million. Capital spending for the six months ended June 30, 2014 primarily included the waste water treatment plant construction at our refinery and safety related enhancements and facility improvements at the refinery and retail store locations.

The decrease in cash used in investing activities of $6.0 million versus the prior year is primarily due to the completion of our wastewater treatment facility in the second quarter of 2014.

Net Cash Used In Financing Activities. Net cash used in financing activities for the six months ended June 30, 2015 of $145.5 million was related to our quarterly distributions to unitholders.

Net cash used in financing activities for the six months ended June 30, 2014 of $109.5 million was related to our quarterly distributions to unitholders.

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The increase in cash used in financing activities of $36.0 million versus the prior year period is due to higher cash distributions in the six months ended June 30, 2015 versus the same period in the year prior. We distribute cash to our unitholders one quarter in arrears of when it was earned.

Working Capital

Working capital at June 30, 2015 was $302.8 million, consisting of $721.7 million in total current assets and $418.9 million in total current liabilities. Working capital at December 31, 2014 was $204.3 million, consisting of $591.2 million in total current assets and $386.9 million in total current liabilities. The increase in working capital as of June 30, 2015 was primarily due to cash generated by operations being in excess of our capital spending and cash distributions, as well as increased inventory and other working capital requirements due to timing differences in the payment and collection of accounts payable and accounts receivable.

Prior to September 30, 2014, we maintained the Crude Intermediation Agreement with JPM CCC pursuant to which JPM CCC assisted us in the purchase of crude oil for our storage tanks at Cottage Grove, Minnesota, which are approximately two miles from our refinery. Upon delivery of the crude oil to us, we paid JPM CCC the price of the crude oil plus certain agreed fees and expenses. With the termination of the agreement with JPM CCC, as described below, we expect to utilize existing trade credit with our vendors to fund the purchase of crude oil. We may also utilize letters of credit under the ABL Facility to facilitate crude oil purchases with vendors.

JPMorgan Chase & Co. announced its intention to sell the physical portions of its commodities business (which includes JPM CCC) to a third party during the fourth quarter of 2014. In advance of this sale, JPM CCC and the Company mutually agreed to terminate the Crude Intermediation Agreement. We believe that in addition to avoiding the supply fees, we now have further control over and visibility into our crude oil procurement process as a result of terminating this agreement.

In order to finance the incremental working capital requirement from the termination of the Crude Intermediation Agreement, we issued $75.0 million of additional senior secured notes under our existing note indenture. We also expanded the capacity of the ABL Facility from $300 million to $500 million in order to provide further flexibility to manage ongoing working capital requirements.

Capital Spending

Total capital spending was $17.7 million for the six months ended June 30, 2015. Capital spending for the six months ended June 30, 2015 primarily included expenditures related to the desalter project, the construction of fire water tanks, a capacity enhancement project on one of our crude units and flare instrumentation (approximately $12.0 million in total) at our refinery as well as safety related enhancements and facility improvements at the refinery and retail store locations.

Total capital spending was $25.1 million for the six months ended June 30, 2014, all of which was considered non-discretionary. Capital spending for the six months ended June 30, 2014 primarily included the waste water treatment plant construction at our refinery and safety related enhancements and facility improvements at the refinery and retail store locations.

We currently expect to spend approximately $52 million in the second half of 2015, for a total of $70 million, which includes approximately $34 million in discretionary capital spending that is expected to consist, in part, of the new desalter equipment, relocation of a solvent de-asphalting unit and spending related to our two crude unit revamp projects. The remaining sustaining and regulatory projects totaling $36 million primarily relate to safety/security, environmental, fire water tanks, and ongoing replacement spending also referred to as maintenance and regulatory capital. We currently intend to fund organic growth capital spending through cash reserves, borrowings from our ABL Facility or issuance of debt or equity securities. The board of directors of our general partner may approve setting aside cash reserves for discretionary projects in determining cash available for distributions. These reserves would replenish cash used for discretionary projects in prior periods or could be utilized for future discretionary projects.

Our Distribution Policy

We generally expect within 60 days after the end of each quarter to make distributions to unitholders of record as of the applicable record date. The board of directors of our general partner adopted a policy pursuant to which distributions for each quarter will equal the amount of available cash we generate in such quarter. Distributions on our units will be in cash. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. Distributions 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, regulatory, and organic growth capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for turnaround and related expenses. Such a decision by the board of directors may have an adverse impact on the available cash in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized.

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Actual turnaround and related expenses and organic growth capital spending 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. 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 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) organic growth capital expenditures less any amounts we may choose to fund with borrowings from our 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. 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 quarter in the year ended December 31, 2014 and the six months ended June 30, 2015:

Date Declared	Date Paid	Common Units and equivalents at record date (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2014 Distributions:
February 7, 2014	February 28, 2014	92.7	$	0.41	$	38.0
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
August 5, 2014	August 29, 2014	93.0	$	0.53	49.3
November 4, 2014	November 25, 2014	93.1	$	1.00	92.9
Total distributions declared during 2014			$	2.71	$	251.8
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
Total distributions declared during 2015			$	2.76	$	258.0

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.

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The following table details our calculation of cash available for distribution for the three months ended June 30, 2015:

(in millions)	Three Months Ended June 30, 2015
Net income	$	128.9
Adjustments:
Interest expense	7.5
Income tax provision	2.9
Depreciation and amortization	10.8
EBITDA subtotal	150.1
Lower of cost or market inventory adjustment (2)	(38.2		)
MPL proportionate depreciation expense	0.7
Turnaround and related expenses	1.2
Equity-based compensation impacts	2.9
Adjusted EBITDA (1)	116.7
Cash interest expense	(6.9		)
Current tax provision	(1.0		)
MPL proportionate depreciation expense	(0.7		)
Reduction in working capital reserve (3)	25.0
Capital expenditures (4)	(14.3		)
Cash reserve for turnaround and related expenses (5)	(7.5		)
Cash Available for Distribution (6)	$	111.3

(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, and equity-based compensation expense. 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 a reduction in a 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 second quarter 2015, crude oil prices increased, resulting in an estimated $25.0 million benefit to the Company's cash earnings from operations and a reduction in working capital. As a result, the Board of Directors of Northern Tier's general partner reduced 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.

(6) Cash available for distribution is a non-GAAP performance measure that we believe is important to investors in evaluating our overall cash generation performance. Cash available for distribution should not be considered as an alternative to operating income or net income 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

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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.

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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 six months ended June 30, 2015 of 96,544 bpd, would result in a change of $17.5 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 1.7 million barrels at both June 30, 2015 and December 31, 2014. The average cost of these crude oil inventories was approximately $80.79 and $81.41 per barrel on a LIFO basis at June 30, 2015 and December 31, 2014, respectively, excluding the impact of the lower of cost or market reserve of $10.9 million and $35.3 million at June 30, 2015 and December 31, 2014, respectively.  Our refined and intermediate products totaled approximately 1.8 million barrels and 1.7 million barrels at June 30, 2015 and December 31, 2014, respectively.  The average cost of our refined and intermediate inventories was approximately $84.68 and $86.39 per barrel on a LIFO basis at June 30, 2015 and December 31, 2014, respectively, excluding the impact of the lower of cost of market reserve of $13.7 million and $38.3 million at June 30, 2015 and December 31, 2014, 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 $8.3 million and $6.2 million in our annual gross margin on gasoline and distillate sales, respectively, based on our average refinery production of these products for the six months ended June 30, 2015 of 45,786 bpd and 34,005 bpd, respectively.

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Commodities Price and Basis Risk Management Activities

We have entered into agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined petroleum products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. Under the agreements, as market conditions permit, we have the capacity to mitigate our crack spread risk with respect to reasonable percentages of the refinery’s projected monthly production of some or all of these refined products. As of June 30, 2015, we have no hedged barrels of future gasoline and diesel production.

We periodically use futures and swaps contracts to manage price risks associated with inventory quantities both above and below target levels. Under our risk mitigation strategy, we may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash. The contracts are not being accounted for as hedges for financial reporting purposes. We recognizes all derivative instruments, except for those that qualify for the normal purchase and normal sales exception, 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 condensed consolidated statements of operations and comprehensive income. 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 the 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 A- 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 June 30, 2015. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2015.

Changes in internal control over financial reporting

There were no changes in our internal control over financial reporting that occurred during the quarter ended June 30, 2015, 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 2014 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 six months ended June 30, 2015, 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 2014 Annual Report on Form 10-K, which risks could materially affect our business, financial condition or future results. The Company has identified an additional risk factor to those discussed in our 2014 Annual Report which is disclosed below. 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.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes or differing interpretations, possibly applied on a retroactive basis.

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the proposed Fiscal Year 2016 Budget recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, this proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the IRS, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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 August 4, 2015	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 August 4, 2015	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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