Northern Tier Energy LP - FORM 10-Q

Northern Tier Energy LP - FORM 10-Q - August 5, 2014

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Attached files

Northern Tier Energy LP Reports

file	filename
EX-10.1 - EXHIBIT - Northern Tier Energy LP	nti-630x2014xexx101.htm
EX-31.2 - EXHIBIT - Northern Tier Energy LP	nti-6302014xexx312.htm
EX-32.2 - EXHIBIT - Northern Tier Energy LP	nti-6302014xexx322.htm
EX-32.1 - EXHIBIT - Northern Tier Energy LP	nti-6302014xexx321.htm
EX-31.1 - EXHIBIT - Northern Tier Energy LP	nti-6302014xexx311.htm
EXCEL - IDEA: XBRL DOCUMENT - Northern Tier Energy LP	Financial_Report.xls

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, 2014
OR
¨		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the transition period from to

COMMISSION FILE NO.: 001-35612

Northern Tier Energy LP

(Exact name of registrant as specified in its charter)




Delaware		80-0763623
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
1250 W. Washington Street, Suite 300 Tempe, Arizona (Address of principal executive offices)		85281 (Zip Code)

(Registrant’s telephone number including area code)

(602) 302-5450

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. (Check one)

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 5, 2014, Northern Tier Energy LP had 92,714,641 common units outstanding. The common units trade on the New York Stock Exchange under the ticker symbol “NTI.”

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NORTHERN TIER ENERGY LP

FORM 10-Q FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2014

TABLE OF CONTENTS



			Page
CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS			3

PART I - FINANCIAL INFORMATION			4
	ITEM 1.	Financial Statements	4
		Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	4
		Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2014 and 2013	5
		Consolidated Statements of Cash Flows for the six months ended June 30, 2014 and 2013	6
		Notes to Consolidated Financial Statements	7
	ITEM 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	21
	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	40
	ITEM 4.	Controls and Procedures	42
PART II - OTHER INFORMATION			42
	ITEM 1.	Legal Proceedings	42
	ITEM 1A.	Risk Factors	42
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42
	ITEM 5.	Other Information	42
	ITEM 6.	Exhibits	43
SIGNATURES			44

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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, reorganization and related costs and operating results are based on our forecasts for our existing operations and our current plans for our reorganization 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;


•	changes in the spread between WTI crude oil and Western Canadian Select crude oil;


•	changes in the spread between WTI crude oil and Brent crude oil;


•	changes in the Group 3 6:3:2:1 product 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;


•	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;


•	potential product liability claims and other litigation;


•	changes in economic conditions, generally, and in the markets we serve, consumer behavior, and travel and tourism trends; and


•	changes in our treatment as a partnership for U.S. federal or state income tax purposes.

For additional information regarding known material factors that could cause our actual results to differ from our projected results, please see (1) Part II, “Item 1A. Risk Factors” elsewhere in this Report and (2) Part I, “Item 1A. Risk Factors” of our 2013 Annual Report on Form 10-K and (3) Part II, "Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2014.

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

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data, unaudited)



	June 30, 2014			December 31, 2013
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	106.9		$	85.8
Receivables, less allowance for doubtful accounts	301.6			242.0
Inventories	199.2			173.5
Other current assets	18.0			23.7
Total current assets	625.7			525.0
NON-CURRENT ASSETS
Equity method investment	83.8			86.2
Property, plant and equipment, net	446.4			446.2
Intangible assets	33.8			33.8
Other assets	25.2			26.6
Total Assets	$	1,214.9		$	1,117.8
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	444.0		$	367.0
Accrued liabilities	36.7			48.5
Total current liabilities	480.7			415.5
NON-CURRENT LIABILITIES
Long-term debt	275.0			275.0
Lease financing obligation	8.3			8.4
Other liabilities	19.5			17.8
Total liabilities	783.5			716.7
Commitments and contingencies	—			—
EQUITY
Accumulated other comprehensive loss	(1.9		)	(2.0		)
Partners' capital (92,714,842 and 92,100,363 units issued and outstanding at June 30, 2014 and December 31, 2013, respectively)	433.3			403.1
Total equity	431.4			401.1
Total Liabilities and Equity	$	1,214.9		$	1,117.8

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

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NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF OPERATIONS

AND COMPREHENSIVE INCOME

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



	Three Months Ended						Six Months Ended
	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
REVENUE	$	1,602.5		$	1,131.2		$	2,948.8		$	2,246.2
COSTS, EXPENSES AND OTHER
Cost of sales	1,432.0			960.0			2,588.3			1,839.2
Direct operating expenses	65.4			62.1			131.8			126.4
Turnaround and related expenses	0.9			27.3			1.4			37.0
Depreciation and amortization	10.2			9.4			20.1			18.0
Selling, general and administrative	22.7			20.9			49.7			46.4
Reorganization and related costs	3.5			0.5			12.9			0.9
Other (income) loss, net	2.2			(1.6		)	1.2			(6.5		)
OPERATING INCOME	65.6			52.6			143.4			184.8
Gains from derivative activities	—			20.6			—			14.1
Interest expense, net	(6.2		)	(6.3		)	(12.4		)	(12.7		)
INCOME BEFORE INCOME TAXES	59.4			66.9			131.0			186.2
Income tax provision	(1.5		)	(3.0		)	(1.6		)	(2.9		)
NET INCOME	57.9			63.9			129.4			183.3
Other comprehensive income, net of tax	—			—			0.1			0.1
COMPREHENSIVE INCOME	$	57.9		$	63.9		$	129.5		$	183.4

EARNINGS PER UNIT INFORMATION:
Weighted average number of units outstanding:
Basic	92,427,069			91,915,000			92,296,346			91,915,000
Diluted	92,454,923			91,931,829			92,306,861			91,934,960
Earnings per unit:
Basic	$	0.62		$	0.70		$	1.40		$	1.99
Diluted	$	0.62		$	0.70		$	1.40		$	1.99

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

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NORTHERN TIER ENERGY LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions, unaudited)



	Six Months Ended
Increase (decrease) in cash	June 30, 2014			June 30, 2013
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	129.4		$	183.3
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	20.1			18.0
Non-cash interest expense	1.2			1.2
Equity-based compensation expense	5.5			5.7
Accelerated equity-based compensation expense due to reorganization activities	4.8			—
Loss from equity method investment	0.9			—
Gain from the change in fair value of outstanding derivatives	(0.3		)	(39.9		)
Changes in assets and liabilities, net:
Accounts receivable	(59.6		)	(64.2		)
Inventories	(25.7		)	(20.4		)
Other current assets	6.0			14.9
Accounts payable and accrued expenses	70.3			27.5
Other, net	1.7			(2.0		)
Net cash provided by operating activities	154.3			124.1
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures	(25.1		)	(69.3		)
Return of capital from investments	1.4			0.9
Net cash used in investing activities	(23.7		)	(68.4		)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity distributions	(109.5		)	(230.1		)
Net cash used in financing activities	(109.5		)	(230.1		)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents	21.1			(174.4		)
Cash and cash equivalents at beginning of period	85.8			272.9
Cash and cash equivalents at end of period	$	106.9		$	98.5

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

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NORTHERN TIER ENERGY LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LP (“NTE LP” or the “Company”) is an independent downstream energy company with refining, retail and pipeline operations that serve the Petroleum Administration for Defense District II (“PADD II”) region of the United States. NTE LP holds 100% of the membership interest in Northern Tier Energy LLC (“NTE LLC”). 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”). In connection with the Company's IPO on July 31, 2012, NTE LLC contributed all of its membership interests in NTR, NTB and SAF to NTRH in exchange for all of the membership interests in NTRH. Effective August 1, 2012, NTRH elected to be treated as a corporation for income tax purposes in order to preserve the MLP tax status of NTE LP. SPPR has a 17% interest in MPL Investments 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 455,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 2). NTOT is a crude oil trucking business in North Dakota that collects crude oil directly from wellheads in the Bakken shale and transports it to regional pipeline and rail facilities.

On November 12, 2013, Western Refining, Inc. (“Western Refining”) acquired 100% of NT InterHoldCo LLC, which owned 100% of Northern Tier Energy GP LLC ("NTE GP"), the general partner of NTE LP, and 35,622,500 common units, or 38.7%, of NTE LP for total consideration of $775 million plus the distribution on the common units acquired with respect to the quarter ended September 30, 2013. The balance of the limited partner units remain publicly traded. NTE LP received no proceeds from this transaction.

As of June 30, 2014, the St. Paul Park refinery owned by SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 96,500 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, 2014, NTR operates 164 convenience stores under the SuperAmerica brand and SAF supports 81 franchised stores which also utilize the SuperAmerica brand. These 245 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 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, 2014 are not necessarily indicative of the results that may be expected for the year ending December 31, 2014, or for any other period. The consolidated balance sheet at December 31, 2013 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 consolidated financial statements should be read in conjunction with the Company’s 2013 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 Annual Report on Form 10-K for the year ended December 31, 2013, 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 - SPPR, NTRH and NTOT. All intercompany accounts have been eliminated in these consolidated financial statements.

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The Company’s common equity interest in MPL is accounted for using the equity method of accounting. Equity income from MPL represents the Company’s proportionate share of net income available to common equity owners generated by MPL.

The equity method investment is assessed for impairment whenever changes in facts or circumstances indicate a loss in value has occurred. When the loss is deemed to be other than temporary, the carrying value of the equity method investment is written down to fair value, and the amount of the write-down is included in net 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, 2014 and December 31, 2013, and is included in other noncurrent assets within the consolidated balance sheets.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities as of the date of the consolidated financial statements and the reported amounts of revenues and expenses during the respective reporting periods. Actual results could differ from those estimates.

Operating Segments

The Company has two reportable operating segments; Refining and Retail (see Note 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 – operates 164 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

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 consolidated statements of operations. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of sale. If a loss on disposal is expected, such losses are generally recognized when the assets are classified as held for sale.

Expenditures for routine maintenance and repair costs are expensed when incurred. Refinery process units require periodic major maintenance and repairs that are commonly referred to as “turnarounds.” The required frequency of the maintenance varies by unit, but generally is every two to six years depending on the processing unit involved. Turnaround costs are expensed as incurred.

Derivative Financial Instruments

The Company is exposed to earnings and cash flow volatility based on the timing and change in refined product prices and crude oil prices. To manage these risks, the Company may use derivative instruments associated with the purchase or sale of crude oil and refined products. Crack spread futures and swap contracts may be used to hedge the volatility of refining margins. The Company also may use futures contracts to manage price risks associated with inventory quantities above or below target levels. The Company does not enter into derivative contracts for speculative purposes. All derivative instruments are recorded in the consolidated balance sheet at fair value and are classified depending on the maturity date of the underlying contracts. Changes in the fair value of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of operations. Gains and losses from derivative activity specific to the risk mitigation on inventory quantities in excess of target inventory levels are included within cost of sales. Gains and losses from derivative activity specific to the risk mitigation on the crack spread futures and swap derivatives are included within gains (losses) on derivative activities. Derivative gains and losses are reported as operating activities within the consolidated statements of cash flows.

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Excise Taxes

The Company collects and remits excise and other taxes to various government authorities. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations. These taxes totaled $103.2 million and $71.1 million for the three months ended June 30, 2014 and 2013, respectively, and $192.1 million and $141.9 million for the six months ended June 30, 2014 and 2013, respectively.

Cost of Sales

Cost of sales in the consolidated statements of operations and comprehensive income excludes depreciation and amortization of refinery assets and the direct labor and overhead costs related to the operation of the refinery. These costs are included in the consolidated statements of operations and comprehensive income in the depreciation and amortization and direct operating expenses line items, respectively.

Product Exchanges

The Company enters into exchange contracts whereby it agrees to deliver a particular quantity and quality of crude oil or refined products at a specified location and date to a particular counterparty and to receive from the same counterparty a particular quantity and quality of crude oil or refined products at a specified location on the same or another specified date. The exchange receipts and deliveries are nonmonetary transactions, with the exception of associated grade or location differentials that are settled in cash. These transactions are not recorded as revenue because they involve the exchange of inventories held in the ordinary course of business to facilitate sales to customers or delivery of feedstocks to the Company's refinery. The exchange transactions are recognized net within cost of sales at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials. Contracts for crude oil or refined products deliveries or receipts that do not meet the requirements to allow for netting are recognized as separate revenue and cost of sales transactions.

Renewable Identification Numbers

The Company is subject to obligations to purchase Renewable Identification Numbers ("RINs") required to comply with the Renewable Fuels Standard. The Company's overall RINs obligation is based on a percentage of domestic shipments of on-road fuels as established by the Environmental Protection Agency ("EPA"). To the degree the Company is unable to blend the required amount of biofuels to satisfy our RINs obligation, RINs must be purchased on the open market to avoid penalties and fines. The Company records its RINs obligation on a net basis in Accrued expenses when its RINs liability is greater than the amount of RINs earned and purchased in a given period and in Prepaid expenses and other current assets when the amount of RINs earned and purchased is greater than the RINs liability.

Reclassification

Certain reclassifications have been made to the prior-year financial information in order to conform to the Company’s current presentation. Specifically, $5.0 million and $5.3 million in net gains from derivative activity related to risk mitigation on refined product inventory in excess of targeted levels have been reclassified from gains (losses) from derivative activities to cost of sales for the three and six months ended June 30, 2013, respectively, within the consolidated statements of operations and comprehensive income.

Accounting Developments

In April 2014, the FASB issued ASU No. 2014-08, which updated the guidance in ASC Topic 205, “Presentation of Financial Statements”, and ASC Topic 360, “Property, Plant and Equipment.” This ASU raises the threshold for a disposal to qualify as discontinued operations and requires new disclosures for individually material disposal transactions that do not meet the definition of a discontinued operation. Under the new standard, companies report discontinued operations when they have a disposal that represents a strategic shift that has or will have a major impact on operations or financial results. This update will be applied prospectively and is effective for annual periods, and interim periods within those years, beginning after December 15, 2014. Early adoption is permitted provided the disposal was not previously disclosed. The adoption of this guidance is not expected to have a material impact on the Company's results of operations, cash flows or financial position.

In May 2014, the Financial Accounting Standards Board (“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 the Company in the annual period beginning after December 15, 2016. The Company is evaluating the effect of adopting this new accounting guidance but does not expect adoption will have a material impact on the Company's results of operations, cash flows or financial position.

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3. RELATED PARTY TRANSACTIONS

The original investors in NTE LLC, which included ACON Refining Partners L.L.C. and TPG Refining L.P., were related parties of the Company from inception through November 12, 2013, the date they sold their remaining indirect interest in the Company to a subsidiary of Western Refining (see Note 1). Upon execution of that transaction, Western Refining became a related party to the Company. For the six months ended June 30, 2014, the Company purchased $6.3 million of crude oil from a subsidiary of Western Refining. There were no crude purchases made from Western Refining for the three months ended June 30, 2014. During the three and six months ended June 30, 2014, the Company sold $3.8 million and $4.8 million, respectively, of asphalt and renewable identification numbers to Western Refining (see Note 2). Additionally, for the six months ended June 30, 2014, the Company realized $0.1 million in lease revenue from the sublease of railcars to a subsidiary of Western Refining.

MPL is also a related party of the Company, however the Company has a crude oil supply and logistics agreement with a third party and has had no direct supply transactions with MPL.

4. INCOME TAXES

NTE LP is treated as a MLP for 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 non-taxable pass-through entities for tax purposes.

The Company’s effective tax rate for the three months ended June 30, 2014 and 2013 was 2.5% and 4.5%, respectively. For the six months ended June 30, 2014 and 2013, the effective tax rate was 1.2% and 1.6%, respectively. For the six months ended June 30, 2014 and 2013, the Company's consolidated federal and state expected statutory tax rate were 41.5% and 40.4%, respectively. The Company's effective tax rate for the six months ended June 30, 2014 and 2013 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)	2014		2013
Crude oil and refinery feedstocks	$	17.0	$	29.4
Refined products	143.6		106.7
Merchandise	22.7		22.6
Supplies and sundry items	15.9		14.8
Total	$	199.2	$	173.5

The LIFO method accounted for 81% and 78% of total inventory value at June 30, 2014 and December 31, 2013, respectively.

During the three and six months ended June 30, 2014, expected permanent reductions in quantities of crude oil and refinery feedstocks inventory resulted in a liquidation of LIFO inventory quantities acquired at lower costs in prior years. This LIFO liquidation resulted in a decrease in cost of sales of approximately $1.0 million and $1.8 million, respectively, for the three and six months ended June 30, 2014. There were no such LIFO liquidations during the comparable periods in 2013.

6. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $83.8 million and $86.2 million at June 30, 2014 and December 31, 2013, respectively.

As of June 30, 2014 and December 31, 2013, the carrying amount of the equity method investment was $6.3 million higher and $6.4 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 $1.4 million and $1.2 million in distributions from MPL in the three months ended June 30, 2014 and 2013, respectively, and $1.4 million and $6.1 million for the six months ended June 30, 2014 and 2013, respectively. Equity income (loss) from MPL was $(2.4) million and $1.8 million for the three months ended June 30, 2014 and 2013, respectively, and $(0.9) million and $5.2 million for the six months ended June 30, 2014 and 2013, respectively.

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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	2014		2013
Land		$	9.0	$	9.0
Retail stores and equipment	2 - 22 years	59.6		54.9
Refinery and equipment	5 - 24 years	436.5		403.5
Buildings and building improvements	25 years	8.6		8.9
Software	5 years	18.8		18.6
Vehicles	5 years	4.6		4.7
Other equipment	2 - 7 years	8.7		8.5
Precious metals		10.2		10.2
Assets under construction		8.3		26.3
		564.3		544.6
Less: accumulated depreciation		117.9		98.4
Property, plant and equipment, net		$	446.4	$	446.2

PP&E includes gross assets acquired under capital leases of $9.2 million and $8.6 million at June 30, 2014 and December 31, 2013, respectively, with related accumulated depreciation of $1.5 million and $1.2 million, respectively. The Company had depreciation expense related to capitalized software of $0.9 million for both the three months ended June 30, 2014 and 2013, and $1.8 million for both the six months ended June 30, 2014 and 2013.

8. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights and trade names amounting to $33.8 million at both June 30, 2014 and December 31, 2013. At both June 30, 2014 and December 31, 2013, the franchise rights and trade name intangible asset values were $12.4 million and $21.4 million, respectively. These assets have an indefinite life and therefore are not amortized, but rather are tested for impairment annually or sooner if events or changes in circumstances indicate that the fair value of the intangible asset has been reduced below carrying value. Historically, the Company performed its annual indefinite lived intangible testing as of October 31st. We have changed the date of our annual impairment test to June 30th. Based on the testing performed as of June 30, 2014, the Company has concluded that no impairment is present at this time.

9. DERIVATIVES

The Company is subject to crude oil and refined product market price fluctuations caused by supply conditions, weather, economic conditions and other factors. Historically, the Company entered into crack spread derivative contracts as a strategy to mitigate refining margin risk on a portion of its 2011 through 2013 projected refining production. The Company periodically uses futures contracts to manage price risks associated with inventory quantities both above and below target levels.

Under its risk mitigation strategy, the Company may buy or sell an amount equal to a fixed price times a certain number of barrels, and to buy or sell in return an amount equal to a specified variable price times the same amount of barrels. Physical volumes are not exchanged and these contracts are net settled with cash. The contracts are not being accounted for as hedges for financial reporting purposes. The Company recognizes all derivative instruments as either assets or liabilities at fair value on the balance sheet and any related net gain or loss is recorded within the consolidated statements of operations. Net gains or losses for contracts to mitigate price risk associated with inventory quantities above target levels are recorded in cost of sales. Net gains or losses for contracts to mitigate refining margin risk are recorded in gains (losses) from derivative activities. 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. As of December 31, 2013, all of the Company's outstanding crack spread derivative contracts had expired and, as such, at both December 31, 2013 and June 30, 2014, the Company had no open crack spread derivative instruments. However, the Company did have outstanding futures contracts at June 30, 2014 to manage price risks on inventory quantities above target levels.

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All derivative contracts are marked to market at period end and the resulting gains and losses are recognized in earnings. Recognized gains and losses on derivatives were as follows:



	Three Months Ended						Six Months Ended
(in millions)	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Gain (loss) on the change in fair value of outstanding derivatives	$	0.5		$	28.7		$	0.3		$	39.9
Settled derivative losses	(2.4		)	(3.1		)	(3.1		)	(20.5		)
Total recognized gain (loss)	$	(1.9	)	$	25.6		$	(2.8	)	$	19.4

Gain (loss) recognized in Cost of sales	(1.9		)	5.0			$	(2.8	)	$	5.3
Gains recognized in Gains from derivative activities	—			20.6			—			14.1
Total recognized net gain (loss) on derivatives	$	(1.9	)	$	25.6		$	(2.8	)	$	19.4

The fair value of the Company’s outstanding derivative instruments as of June 30, 2014 constituted an unrealized gain of $0.3 million, located in other current assets. The Company had no outstanding positions at December 31, 2013.

10. DEBT

2020 Secured Notes

NTE LLC has outstanding $275 million in aggregate principal amount of 7.125% senior secured notes due 2020 (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 consolidating 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. 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. Wester 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 notes maturing on November 15, 2020. Effective in October 2013, the 2020 Secured Notes were registered with the SEC.

At any time prior to the maturity date of the notes, the Company may, at its option, redeem all or any portion of the notes for the outstanding principal amount plus unpaid interest and a make-whole premium as defined in the indenture. If the Company experiences a change in control or makes certain asset dispositions, as defined under the indenture, the Company may be required to repurchase all or part of the notes plus unpaid interest and, in certain cases, pay a redemption premium.

The 2020 Secured Notes contain certain covenants that, among other things, limit the ability, subject to certain exceptions, of the Company to incur additional debt or issue preferred equity interests, to purchase, redeem or otherwise acquire or retire its equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of its property or assets, to merge, consolidate, lease or sell substantially all of the Company’s assets, to suffer a change of control or to enter into new lines of business.

ABL Facility

The Company's ABL facility (the “ABL Facility”) is a $300 million secured asset-based revolving credit facility with a maturity date of July 17, 2017.

The ABL Facility includes a springing financial covenant to provide that, if the amount available under the revolving credit facility is less than the greater of (i) 12.5% of the lesser of (x) the $300 million commitment amount and (y) the then-applicable borrowing base and (ii) $22.5 million, the Company must comply with a minimum Fixed Charge Coverage Ratio (as defined in the ABL Facility) of at least 1.0 to 1.0. Other covenants include, but are not limited to: restrictions, subject to certain exceptions, on the ability of the Company and its subsidiaries to sell or otherwise dispose of assets, incur additional

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indebtedness or issue preferred stock, pay dividends and distributions or repurchase capital stock, create liens on assets, make investments, loans or advances, make certain acquisitions, engage in mergers or consolidations, and engage in certain transactions with affiliates.

Borrowings under the ABL Facility bear interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and 1.50%) or (b) a LIBOR rate plus applicable margin (ranging between 2.00% and 2.50%). The alternate base rate is the greater of (a) the prime rate, (b) the Federal Funds Effective rate plus 50 basis points, or (c) the one-month LIBOR rate plus 100 basis points and a spread of up to 225 basis points based upon percentage utilization of this facility. In addition to paying interest on outstanding borrowings, the Company is also required to pay an annual commitment fee ranging from 0.375% to 0.500% and letter of credit fees.

As of June 30, 2014, the borrowing base under the ABL Facility was $279.2 million and availability under the ABL Facility was $244.0 million (which is net of $35.2 million in outstanding letters of credit). The Company had no borrowings under the ABL Facility at June 30, 2014 or December 31, 2013.

11. EQUITY

Public Offerings

During the year ended December 31, 2013, Northern Tier Holdings LLC (NT Holdings), the owner of NTE GP LLC prior to November 12, 2013, completed three secondary public offerings of 37,605,000 NTE LP common units in total. These offerings did not increase the total common units outstanding and the Company received no proceeds. Under the Company’s partnership agreement, the offering costs from subsequent offerings of common units to the public by NT Holdings were incurred by the Company. For the three and six months ended June 30, 2013, the Company expensed $0.5 million and $0.9 million, respectively, of offering costs from these secondary offerings (see Note 19).

Western Refining Acquisition

On November 12, 2013, NT Holdings formed a new subsidiary, NT InterHoldCo LLC, and contributed all of its interest in NTE LP and NTE GP, the general partner of NTE LP, to NT InterHoldCo LLC. Subsequent to the contribution, NT Holdings entered into a definitive agreement to sell all of its interests in NT InterHoldCo LLC to Western Refining for total consideration of $775 million plus the cash distribution payable to the holders of the common units acquired with respect to the quarter ended September 30, 2013. As a result of this transaction, Western Refining now indirectly owns 100% of Northern Tier Energy GP LLC and 35,622,500 common units, or 38.7%, of NTE LP. The balance of the limited partner units remain publicly traded. NTE LP received no proceeds from this transaction. As of the purchase date, NT InterHoldCo LLC, as the owner of the general partner of NTE LP, has the ability to appoint all of the members of the general partner’s board of directors.

Distribution Policy

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

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The following table details the quarterly distributions paid to common unitholders during the year ended December 31, 2013 and the six months ended June 30, 2014 (in millions, except per unit amounts):



Date Declared	Date Paid	Common Units and equivalents (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2013 Distributions:
February 11, 2013	February 28, 2013	91.9	$	1.27	$	116.7
May 13, 2013	May 30, 2013	92.2	$	1.23	113.4
August 13, 2013	August 29, 2013	92.2	$	0.68	62.7
November 11, 2013	November 27, 2013	92.2	$	0.31	28.6
Total distributions paid during 2013			$	3.49	$	321.4
2014 Distributions:
February 7, 2014	February 28, 2014	92.4	$	0.41	$	37.9
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
Total distributions paid during 2014			$	1.18	$	109.5

Effective August 5, 2014, the board of directors of NTE LP's general partner declared a quarterly distribution of $0.53 per unit to common unitholders and phantom common unit holders (see Note 14) as of August 18, 2014, payable on August 29, 2014. This distribution of approximately $49.2 million in aggregate is based on available cash generated during the three months ended June 30, 2014.

Changes in Partners' Equity



(in millions)	Accumulated Other Comprehensive Income			Partners' Capital			Total Partners' Equity
Balance at December 31, 2013	$	(2.0	)	$	403.1		$	401.1
Net income	—			129.4			129.4
Distributions	—			(109.5		)	(109.5		)
Equity-based compensation expense	—			10.3			10.3
Amortization of net prior service cost on defined benefit plans	0.1			—			0.1
Balance at June 30, 2014	$	(1.9	)	$	433.3		$	431.4

During the six months ended June 30, 2014, the Company's common units issued and outstanding increased by 614,479, all of which were attributable to equity-based compensation awards, net of forfeitures (see Note 14).

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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, 2014 and 2013. The Company has outstanding restricted common units, phantom common units, and dividend equivalent rights under its LTIP program (see Note 14) that participate in distributions. Additionally, distributions paid on 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 (loss) 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, 2014			June 30, 2013		June 30, 2014			June 30, 2013
Net income available to common unitholders	$	57.9		$	63.9	$	129.4		$	183.3
Less: income allocated to participating securities	(0.4		)	—		(0.5		)	—
Net income attributable to unrestricted common units	$	57.5		$	63.9	$	128.9		$	183.3

Weighted average unrestricted common units - basic	92,427,069			91,915,000		92,296,346			91,915,000
Plus: dilutive potential common securities	27,854			16,829		10,515			19,960
Weighted average unrestricted common units - diluted	92,454,923			91,931,829		92,306,861			91,934,960

Basic earnings per unit	$	0.62		$	0.70	$	1.40		$	1.99
Diluted earnings per unit	$	0.62		$	0.70	$	1.40		$	1.99

12. FAIR VALUE MEASUREMENTS

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

Accounting guidance does not prescribe which valuation technique should be used when measuring fair value and does not prioritize among the techniques. Accounting guidance establishes a fair value hierarchy that prioritizes the inputs used in 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.

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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.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at June 30, 2014 and December 31, 2013:



	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	June 30, 2014		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	106.9	$	106.9	$	—	$	—
Other current assets
Derivative asset - current	0.3		—		0.3		—
	$	107.2	$	106.9	$	0.3	$	—



	Balance at		Quoted prices in active markets		Significant other observable inputs		Unobservable inputs
(in millions)	December 31, 2013		(Level 1)		(Level 2)		(Level 3)
ASSETS
Cash and cash equivalents	$	85.8	$	85.8	$	—	$	—
	$	85.8	$	85.8	$	—	$	—

As of June 30, 2014 and December 31, 2013, 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, 2014 and 2013, there were no transfers in or out of Levels 1, 2 or 3.

Assets not recorded at fair value on a recurring basis, such as property, plant and equipment, intangible assets and cost method investments, are recognized at fair value when they are impaired. During the three months ended June 30, 2014 and 2013, there were no adjustments to the fair value of such assets.

The carrying value of debt, which is reported on the Company’s consolidated balance sheets, reflects the cash proceeds received upon its issuance, net of subsequent repayments. The fair value of the 2020 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).



	June 30, 2014				December 31, 2013
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Secured Notes	$	275.0	$	298.4	$	275.0	$	291.1

13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:



	Six Months Ended
(in millions)	June 30, 2014			June 30, 2013
Asset retirement obligation balance at beginning of period	$	2.2		$	1.9
Costs incurred to remediate	(0.2		)	—
Accretion expense	0.2			0.1
Asset retirement obligation balance at end of period	$	2.2		$	2.0

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14. EQUITY-BASED COMPENSATION

The Company maintains an equity-based compensation plan designed to encourage employees and directors of the Company to achieve superior performance. The current plan is maintained by the general partner of NTE LP and is referred to as the 2012 Long-Term Incentive Plan (“LTIP”). A former equity-based plan (the “NT Investor Plan”) was sponsored by members of NT Investors, the parent company of NT Holdings, and granted profit unit interests in NT Investors. All equity-based compensation expense related to both plans is recognized by the Company. The Company recognized equity-based compensation expense of $1.2 million and $0.4 million for the three months ended June 30, 2014, respectively, and $5.5 million and $5.7 million for the six months ended June 30, 2014, and 2013, respectively, related to these plans. This expense is included in selling, general and administrative expenses in the consolidated statements of operations and comprehensive income.

LTIP

Approximately 9.2 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, 2014, approximately 0.8 million units were outstanding under the LTIP. The Company recognizes the expense on all LTIP awards ratably from the grant date until all units become unrestricted. Awards generally vest ratably over a three-year period beginning on the award's first anniversary date. Compensation expense related to these restricted units is based on the grant date fair value as determined by the closing market price on the grant date, reduced by the fair value of estimated forfeitures. For awards to employees, the Company estimates a forfeiture rate which is subject to revision depending on the actual forfeiture experience.

Restricted Common Units

As of June 30, 2014, the Company had 0.4 million restricted common units outstanding. Upon vesting, these common units will no longer be restricted. All restricted common units participate in distributions on an equal basis with common units 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, 2014, the forfeiture rates on LTIP awards ranged from zero to 10%, depending on the employee classification and the length of the award's vesting period.

During the three and six months ended June 30, 2014, the Company recognized $1.7 million and $4.8 million, respectively, of equity-based compensation related to the accelerated vesting of LTIP grants as part of a plan that includes the relocation of its corporate offices and the reorganization of various positions within the Company (see Note 19).

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 Price		Until Maturity
Nonvested at December 31, 2013	306.6		$	27.02	2.9
Awarded	486.9		24.31		2.0
Cancelled	(1.9	)	26.52		2.4
Vested	(361.6	)	25.99		—
Nonvested at June 30, 2014	430.0		$	24.81	2.3

Phantom Common Units

During the second quarter of 2014, the Company began issuing phantom common units to key employees. As of June 30, 2014, the Company had 0.3 million phantom common units outstanding. Upon vesting, the Company may settle these units in common units or cash at the discretion of the board of directors of the General Partner, 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 cancelled, any accrued distributions on the underlying units are forfeited by the grantee. As of June 30, 2014, the Company had $0.3 million in accrued phantom common unit distributions located in accrued liabilities in the consolidated balance sheet. For phantom common unit awards outstanding at June 30, 2014, the forfeiture rates on LTIP awards ranged from 5% to 20%, depending on the employee classification.

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A summary of the phantom common unit activity is set forth below:



	Number of		Weighted		Weighted
	phantom common units		Average Grant		Average Term
	(in thousands)		Date Price		Until Maturity
Nonvested at December 31, 2013	—		$	—	—
Awarded	347.1		27.01		2.7
Cancelled	(1.0	)	27.01		2.7
Nonvested at June 30, 2014	346.1		$	27.01	2.5

As of June 30, 2014 and December 31, 2013, the total unrecognized compensation cost for units awarded under the LTIP was $15.7 million and $6.1 million, respectively.

NT Investor Plan

The NT Investor Plan was an equity participation plan which provided for the award of profit interest units in NT Investors to certain employees and independent non-employee directors of NTE LLC. Approximately 29 million profit interest units in NT Investors were reserved for issuance under the plan. The exercise price for a profit interest unit was not to be less than 100% of the fair market value of NT Investors equity units on the date of grant. Profit interest units were to vest in annual installments over a period of five years after the date of grant and expire ten years after the date of grant. Upon NT Investors meeting certain thresholds of distributions from NTE LLC and NTE LP, profit interest unit vesting would accelerate. Continued employment in any subsidiary of NT Investors was a condition of vesting and, as such, compensation expense was recognized in the Company’s financial statements based upon the fair value of the award on the date of grant. This compensation expense was a non-cash expense of the Company. The NT Investor Plan awards were satisfied by cash distributions made from NT Holdings and did not dilute cash available for distribution to the unitholders of NTE LP.

In January 2013, upon completion of the Company’s secondary public offering of 10.7 million common units owned by NT Holdings, all outstanding and unvested profit interest units under the NT Investor Plan became immediately fully-vested. As a result, the Company accelerated all remaining unrecognized expense related to this plan resulting in a non-cash expense of $5.3 million recorded during the six months ended June 30, 2013 related to this plan. This expense is included in selling, general and administrative expenses in the consolidated statements of operations and comprehensive income. No further awards will be issued from the NT Investor Plan.

15. EMPLOYEE BENEFIT PLANS

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, 2014 and 2013 was $0.6 million and $0.5 million, respectively, and for the six months ended June 30, 2014 and 2013 was $1.1 million and $1.0 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 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, 2014 and 2013 was $0.1 million and $0.2 million, respectively, and for both the six months ended June 30, 2014 and 2013 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, 2014		June 30, 2013
Net cash from operating activities included:
Interest paid	$	11.3	$	13.1
Income taxes paid	—		0.4

Noncash investing and financing activities include:
Capital expenditures included in accounts payable	$	3.3	$	1.6

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. The ultimate resolution of these contingencies could, individually or in the aggregate, be material to the Company’s consolidated financial statements.

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At June 30, 2014 and December 31, 2013, liabilities for remediation totaled $3.0 million and $1.5 million, respectively. These liabilities are expected to be settled over at least the next 25 years. At June 30, 2014, the estimated future cash flows to settle this liability totaled $4.0 million, which are stated at their present value using a discount rate of 3.16%. Receivables for recoverable costs from the state, under programs to assist companies in clean-up efforts related to underground storage tanks at retail marketing outlets, and others were $0.1 million at both June 30, 2014 and December 31, 2013.

On June 3, 2014, SPPR was issued a National Pollutant Discharge Elimination Permit/State Disposal System Permit by the Minnesota Pollution Control Agency relating to its upgraded waste water treatment plant at its St. Paul Park refinery. This permit requires the refinery to conduct additional testing of its remaining lagoon. The refinery is currently planning to perform this testing as soon as water table conditions permit. Following this testing, the refinery may be required to incur future remediation costs and/or capital spending, relating to this lagoon and associated fire water resources, some of which may be recoverable from Marathon under an agreement entered into in connection with our December 2010 acquisition of the St. Paul Park refinery, among other assets, from Marathon. While the amounts of any potential future remediation costs are not yet estimable, we do not anticipate that such remediation costs would have a material impact on the Company's financial condition, results of operations or cash flows.

It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred by the Company or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates for which a liability has been recorded because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology.

Franchise Agreements

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

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

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



(in millions)
Three months ended June 30, 2014	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 (loss) from equity method investment	$	(2.4	)	$	—	$	—		$	(2.4	)
Depreciation and amortization	$	8.3		$	1.7	$	0.2		$	10.2
Capital expenditures	$	7.2		$	2.9	$	—		$	10.1



(in millions)
Three months ended June 30, 2013	Refining		Retail		Other			Total
Revenues
Customer	$	753.0	$	378.2	$	—		$	1,131.2
Intersegment	261.8		—		—			261.8
Segment revenues	1,014.8		378.2		—			1,393.0
Elimination of intersegment revenues	—		—		(261.8		)	(261.8		)
Total revenues	$	1,014.8	$	378.2	$	(261.8	)	$	1,131.2

Income (loss) from operations	$	53.1	$	8.0	$	(8.5	)	$	52.6
Income from equity method investment	$	1.8	$	—	$	—		$	1.8
Depreciation and amortization	$	7.5	$	1.8	$	0.1		$	9.4
Capital expenditures	$	41.4	$	0.9	$	0.1		$	42.4



(in millions)
Six months ended June 30, 2014	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

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(in millions)
Six months ended June 30, 2013	Refining		Retail		Other			Total
Revenues
Customer	$	1,524.8	$	721.4	$	—		$	2,246.2
Intersegment	508.6		—		—			508.6
Segment revenues	2,033.4		721.4		—			2,754.8
Elimination of intersegment revenues	—		—		(508.6		)	(508.6		)
Total revenues	$	2,033.4	$	721.4	$	(508.6	)	$	2,246.2

Income (loss) from operations	$	195.2	$	8.6	$	(19.0	)	$	184.8
Income from equity method investment	$	5.2	$	—	$	—		$	5.2
Depreciation and amortization	$	14.2	$	3.6	$	0.2		$	18.0
Capital expenditures	$	67.9	$	1.3	$	0.1		$	69.3

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		Corporate/Other		Total
At June 30, 2014	$	951.3	$	134.8	$	128.8	$	1,214.9

At December 31, 2013	$	875.6	$	138.2	$	104.0	$	1,117.8

Total assets for the refining and retail segments exclude all intercompany balances. All cash and cash equivalents are included as corporate/other assets. All property, plant and equipment are located in the United States.

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 $3.5 million and $12.9 million of expense during the three and six months ended June 30, 2014, respectively, which included compensation related to the severance of employment and the acceleration of unvested equity based compensation. These costs are recognized in the reorganization and related costs line within the consolidated statements of operations and comprehensive income. All reorganization and related costs are recognized in the Other segment. The Company expects that substantially all reorganization costs associated with the corporate office relocation have been fully recognized at June 30, 2014. As of June 30, 2014, the Company had $1.9 million in unpaid reorganization expenses included in the accrued liabilities line item of the consolidated balance sheets, which will be paid from 2014 through 2016.



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

For the three and six months ended June 30, 2013, the Company recognized a charge of $0.5 million and $0.9 million for equity offering costs that did not meet the requirements for deferral, related to a secondary public offering of common units held by the owner of the Company's general partner interest at that time, NT Holdings (see Note 11).

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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 pipeline operations that serves the PADD II region of the United States. We operate our assets in two business segments: the refining business and the retail business. For the six months ended June 30, 2014, we had total revenues of $2.9 billion, operating income of $143.4 million, net income of $129.4 million and Adjusted EBITDA of $184.7 million. A definition and reconciliation of Adjusted EBITDA to net income 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 96,500 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 while limiting the impact of rising trucking costs for crude oil in North Dakota. Our refining business also includes our 17% interest in MPL and MPLI, which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

As of June 30, 2014, our retail business operated 164 convenience stores under the SuperAmerica brand and also supported 81 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, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Revenue	$	1,602.5		$	1,131.2		$	2,948.8		$	2,246.2
Costs, expenses and other:
Cost of sales	1,432.0			960.0			2,588.3			1,839.2
Direct operating expenses	65.4			62.1			131.8			126.4
Turnaround and related expenses	0.9			27.3			1.4			37.0
Depreciation and amortization	10.2			9.4			20.1			18.0
Selling, general and administrative	22.7			20.9			49.7			46.4
Reorganization and related costs	3.5			0.5			12.9			0.9
Other (income) loss, net	2.2			(1.6		)	1.2			(6.5		)
Operating income	65.6			52.6			143.4			184.8
Gains from derivative activities	—			20.6			—			14.1
Interest expense, net	(6.2		)	(6.3		)	(12.4		)	(12.7		)
Income before income taxes	59.4			66.9			131.0			186.2
Income tax provision	(1.5		)	(3.0		)	(1.6		)	(2.9		)
Net income	$	57.9		$	63.9		$	129.4		$	183.3

Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013

Revenue. Revenue for the three months ended June 30, 2014, was $1,602.5 million compared to $1,131.2 million for the three months ended June 30, 2013, an increase of 41.7%. Refining segment revenue increased 46.5% and retail segment revenue decreased 1.9% compared to the three months ended June 30, 2013. Refining revenue included a $100 million increase in crude oil revenues in the three months ended June 30, 2014 (accompanied by a corresponding repurchase) and a 49.7% increase in sales volumes of refined products versus the three months ended June 30, 2013. The higher refined product volumes are primarily attributable to increased throughput capacity resulting from our crude expansion project completed in the second quarter of 2013, along with less downtime in the second quarter of 2014 compared to the second quarter of 2013 due to a major turnaround in the 2013 period. Retail revenue decreased primarily due to lower average selling prices per gallon for fuel sales during the three months ended June 30, 2014. Excise taxes included in revenue increased by $32.1 million for the 2014 period over the 2013 period.

Cost of sales. Cost of sales totaled $1,432.0 million for the three months ended June 30, 2014 compared to $960.0 million for the three months ended June 30, 2013, an increase of 49.2%. This increase was primarily due to increased sales volumes and higher feedstock costs during the three months ended June 30, 2014 compared to the three months ended June 30, 2013. Additionally, the refining segment's cost of sales from crude oil sales increased by $100 million and excise taxes increased by $32.1 million for the three months ended June 30, 2014 compared to the three months ended June 30, 2013.

Direct operating expenses. Direct operating expenses totaled $65.4 million for the three months ended June 30, 2014 compared to $62.1 million for the three months ended June 30, 2013, an increase of 5.3%, due primarily to higher natural gas costs and an increase in estimated costs related to environmental obligations, both within our refining segment.

Turnaround and related expenses. Turnaround and related expenses totaled $0.9 million for the three months ended June 30, 2014 compared to $27.3 million for the three months ended June 30, 2013. The turnaround costs in the three months ended June 30, 2014 relate to a partial turnaround project associated with our hydrogen unit. The turnaround costs in the three months ended June 30, 2013 relate to the costs of a planned major plant turnaround, which lasted the entire month of April 2013.

Depreciation and amortization. Depreciation and amortization was $10.2 million for the three months ended June 30, 2014 compared to $9.4 million for the three months ended June 30, 2013, an increase of 8.5%. This increase was primarily due to increased refining assets placed in service since June 30, 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses were $22.7 million for the three months ended June 30, 2014 compared to $20.9 million for the three months ended June 30, 2013. This increase of 8.6%

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relates primarily to higher personnel and risk management costs for the three months ended June 30, 2014 compared to the three months ended June 30, 2013.

Reorganization and related costs. Reorganization and related costs for the three months ended June 30, 2014 and 2013 were $3.5 million and $0.5 million, respectively. The increase was due to costs incurred in connection with the relocation of our corporate office and reorganization of various positions within the Company. We believe substantially all costs related to this corporate reorganization were fully recognized as of June 30, 2014. The reorganization and related costs in the three months ended June 30, 2013 relate primarily to offering costs for the sale of common units by NT Holdings that did not meet the accounting required for deferral.

Other (income) loss, net. Other (income) loss, net was a net loss of $2.2 million for the three months ended June 30, 2014 compared to a net gain of $1.6 million for the three months ended June 30, 2013. This decrease was primarily due to lower income from our investment in MPL, which was incurring costs for non-routine maintenance and upgrades during the three months ended June 30, 2014.

Gains from derivative activities. For the three months ended June 30, 2014, we had no gains or losses from derivative activities as our remaining crack spread derivatives expired in December 2013. For the three months ended June 30, 2013, our gains from derivative activities were $20.6 million which primarily related to changes in the fair value of outstanding derivatives at June 30, 2013. These derivatives were entered into to partially hedge the crack spreads for our refining business.

Interest expense, net. Interest expense, net was $6.2 million for the three months ended June 30, 2014 compared to $6.3 million for the three months ended June 30, 2013. These interest charges relate primarily to our senior secured notes, commitment fees, interest on the ABL facility and the amortization of deferred financing costs.

Income tax (provision) benefit. The income tax expense for the three months ended June 30, 2014 was $1.5 million compared to $3.0 million for the three months ended June 30, 2013. The reduction was due to lower income generated by our retail segment for the three months ended June 30, 2014 compared to the three months ended June 30, 2013.

Net income. Our net income was $57.9 million for the three months ended June 30, 2014 compared to $63.9 million for the three months ended June 30, 2013, a decrease of $6.0 million. This decrease was primarily due to higher direct operating costs, higher reorganization and related costs and lower gains from derivative activities in 2014, partially offset by lower turnaround expenses in 2014.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

Revenue. Revenue for the six months ended June 30, 2014 was $2,948.8 million compared to $2,246.2 million for the six months ended June 30, 2013, an increase of 31.3%. Refining segment revenue increased 34.3% and retail segment revenue decreased 2.1% compared to the six months ended June 30, 2013. Refining revenue included a $270 million increase in crude oil revenues in the six months ended June 30, 2014 (accompanied by a corresponding repurchase) and a 25.3% increase in sales volumes of refined products versus the six months ended June 30, 2013. The higher refined product volumes are primarily attributable to increased throughput capacity resulting from our crude expansion project completed in the second quarter of 2013, along with less downtime in 2014 compared to 2013 due to a major turnaround in the 2013 period. Retail revenue decreased primarily due to lower average selling prices per gallon for fuel sales during the six months ended June 30, 2014. Excise taxes included in revenue increased by $50.2 million for the 2014 period over the 2013 period.

Cost of sales. Cost of sales totaled $2,588.3 million for the six months ended June 30, 2014 compared to $1,839.2 million for the six months ended June 30, 2013, an increase of 40.7%, primarily due to higher volumes and feedstock costs in the six months ended June 30, 2014. Also, there was an increase of $270 million in cost of sales related to crude oil sales and a 25.3% increase in refining sales volumes during the six months ended June 30, 2014. Lastly, excise taxes included in cost of sales increased by $50.2 million for the 2014 period over the 2013 period.

Direct operating expenses. Direct operating expenses totaled $131.8 million for the six months ended June 30, 2014 compared to $126.4 million for the six months ended June 30, 2013, an increase of 4.3%, due primarily to the impact of higher natural gas costs within our refining segment during the six months ended June 30, 2014.

Turnaround and related expenses. Turnaround and related expenses totaled $1.4 million for the six months ended June 30, 2014 compared to $37.0 million for the six months ended June 30, 2013. The turnaround costs in the six months ended June 30, 2014 include costs for a partial turnaround of our hydrogen unit, which was completed in the second quarter of 2014. The 2013 costs relate to a planned major plant turnaround which lasted the entire month of April 2013.

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Depreciation and amortization. Depreciation and amortization was $20.1 million for the six months ended June 30, 2014 compared to $18.0 million for the six months ended June 30, 2013, an increase of 11.7%. This increase was due primarily to increased refining assets placed in service since June 30, 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses were $49.7 million for the six months ended June 30, 2014 compared to $46.4 million for the six months ended June 30, 2013. This increase of 7.1% relates primarily to higher personnel and risk management costs for the six months ended June 30, 2014 compared to the six months ended June 30, 2013.

Reorganization and related costs. Reorganization and related costs for the six months ended June 30, 2014 and 2013 were $12.9 million and $0.9 million, respectively. The increase was due to costs incurred in connection with the relocation of our corporate office and reorganization of various positions within the Company. We believe substantially all costs related to this corporate reorganization were fully recognized as of June 30, 2014. The reorganization and related costs in the six months ended June 30, 2013 relate primarily to offering costs for the sale of common units by NT Holdings that did not meet the accounting required for deferral.

Other (income) loss, net. Other (income) loss, net was a $1.2 million loss for the six months ended June 30, 2014 compared to income of $6.5 million for the six months ended June 30, 2013. This change is driven primarily by a reduction in the equity income of MPL due to non-routine expense projects on the pipeline during the six months ended June 30, 2014 and $1.8 million of miscellaneous income that was recognized in the first quarter of 2013 related to settlements from indemnification arrangements.

Gains from derivative activities. For the six months ended June 30, 2014, we had no gains or losses from derivative activities as our remaining crack spread derivatives expired in December 2013. For the six months ended June 30, 2013, our gains from derivative activities were $14.1 million. We recorded a gain on the change in fair value of outstanding derivatives during the six months ended June 30, 2013 of $39.6 million. These unrealized gains were offset by losses of $25.5 million in the six months ended June 30, 2013 related to settled contracts. These derivatives were entered into to partially hedge the crack spreads for our refining business.

Interest expense, net. Interest expense, net was $12.4 million for the six months ended June 30, 2014 and $12.7 million for the six months ended June 30, 2013. These interest charges 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, 2014 was $1.6 million compared to $2.9 million for the six months ended June 30, 2013. The reduction was due to lower income generated by our retail segment.

Net income. Our net income was $129.4 million for the six months ended June 30, 2014 compared to $183.3 million for the six months ended June 30, 2013. This reduction in net income is primarily attributable to a $46.5 million reduction of our refining gross product margin, a decrease in gains from derivative activities of $14.1 million and a $12.0 million increase in our reorganization and related costs. These decreases in income were partially offset by a $35.6 million decrease in turnaround and related activities during the six months ended June 30, 2014.

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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, 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



	Three Months Ended June 30, 2013
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	753.0	$	378.2	$	—		$	1,131.2
Intersegment sales	261.8		—		(261.8		)	—
Segment revenue	$	1,014.8	$	378.2	$	(261.8	)	$	1,131.2
Cost of sales:
Cost of sales	$	889.0	$	70.7	$	0.3		$	960.0
Intersegment purchases	—		261.8		(261.8		)	—
Segment cost of sales	$	889.0	$	332.5	$	(261.5	)	$	960.0



	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



	Six Months Ended June 30, 2013
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	1,524.8	$	721.4	$	—		$	2,246.2
Intersegment sales	508.6		—		(508.6		)	—
Segment revenue	$	2,033.4	$	721.4	$	(508.6	)	$	2,246.2
Cost of sales:
Cost of sales	$	1,709.0	$	130.1	$	0.1		$	1,839.2
Intersegment purchases	—		508.6		(508.6		)	—
Segment cost of sales	$	1,709.0	$	638.7	$	(508.5	)	$	1,839.2

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Refining Segment



	Three Months Ended					Six Months Ended
(in millions)	June 30, 2014		June 30, 2013			June 30, 2014		June 30, 2013
Revenue	$	1,486.7	$	1,014.8		$	2,730.3	$	2,033.4
Costs, expenses and other:
Cost of sales	1,359.5		889.0			2,452.4		1,709.0
Direct operating expenses	35.3		32.9			72.7		68.9
Turnaround and related expenses	0.9		27.3			1.4		37.0
Depreciation and amortization	8.3		7.5			16.3		14.2
Selling, general and administrative	8.0		6.9			16.2		14.4
Other (income) loss, net	1.9		(1.9		)	0.7		(5.3		)
Operating income	$	72.8	$	53.1		$	170.6	$	195.2
Key Operating Statistics
Refining gross product margin (in millions)(3)	$	127.2	$	125.8		$	277.9	$	324.4
Total refinery production (bpd)(1)	93,342		55,594			93,139		70,752
Total refinery throughput (bpd)	93,022		55,486			92,826		70,343
Refined products sold (bpd)(2)	102,409		68,395			95,822		76,499
Per barrel of throughput:
Refining gross product margin(3)	$	15.03	$	24.91		$	16.54	$	25.48
Direct operating expenses(4)	$	4.17	$	6.52		$	4.33	$	5.41
Per barrel of refined products sold:
Refining gross product margin(3)	$	13.65	$	20.21		$	16.02	$	23.43
Direct operating expenses(4)	$	3.79	$	5.29		$	4.19	$	4.98
Refinery product yields (bpd):
Gasoline	46,747		26,715			44,859		33,816
Distillate(5)	34,483		19,093			35,063		23,848
Asphalt	5,494		6,212			6,663		8,408
Other(6)	6,618		3,574			6,554		4,680
Total	93,342		55,594			93,139		70,752
Refinery throughput (bpd):
Crude oil	91,853		54,524			91,964		68,654
Other feedstocks(7)	1,169		962			862		1,689
Total	93,022		55,486			92,826		70,343
Market Statistics:
Crude Oil Average Pricing:
West Texas Intermediate ($/barrel)	$	102.99	$	95.35		$	100.85	$	94.76
PADD II / Group 3 Average Product Pricing:
Unleaded 87 Gasoline ($/barrel)	$	119.07	$	120.27		$	115.75	$	119.15
Ultra Low Sulfur Diesel ($/barrel)	$	123.93	$	123.34		$	124.21	$	126.80


(1)	Excludes fuel and coke on catalyst, which are used in our refining process. Also excludes purchased refined products.


(2)	Includes produced and purchased refined products, including ethanol and biodiesel.

(3)

Refining gross product margin is calculated by subtracting refining costs of sales from total refining revenues. Refining gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in this calculation (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of refining gross product margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures.” Refining gross product margin per barrel is a per barrel

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


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


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


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


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

Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013

Refining gross product margin. Refining gross product margin for the three months ended June 30, 2014 was $127.2 million compared to $125.8 million for the three months ended June 30, 2013, an increase of 1.1%. This increase was primarily due to a $471.9 million increase in refinery revenue due to increased throughput volume resulting from our crude expansion project in 2013 along with less downtime in 2014 compared to 2013 due to turnaround activities in 2013. The increase was substantially offset by lower market crack spreads during the three months ended June 30, 2014 compared to three months ended June 30, 2013. The approximate 40% decrease in market crack spreads resulted in a decrease in refining gross margin per barrel of throughput from $24.91 for the three months ended June 30, 2013 to $15.03 for the three months ended June 30, 2014.

Direct operating expenses. Direct operating expense totaled $35.3 million for the three months ended June 30, 2014 compared to $32.9 million for the three months ended June 30, 2013, an 7.3% increase. This increase was due primarily to increased natural gas costs resulting from reduced usage in 2013 due to the turnaround along with an increase in the estimated costs for groundwater remediation at the refinery.

Turnaround and related expenses. Turnaround and related expenses totaled $0.9 million for the three months ended June 30, 2014 compared to $27.3 million for the three months ended June 30, 2013, a decrease of $26.4 million. The turnaround costs in the three months ended June 30, 2014 relate to a partial turnaround project associated with our hydrogen unit. The turnaround costs in the three months ended June 30, 2013 relate to the costs of a planned major plant turnaround which lasted the entire month of April 2013.

Depreciation and amortization. Depreciation and amortization was $8.3 million for the three months ended June 30, 2014 compared to $7.5 million for the three months ended June 30, 2013, an increase of 10.7%. This increase was due to increased assets placed in service during the first six months of 2013, the most significant of which was the expansion project for one of our crude units which was placed in service in the second quarter of 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses were $8.0 million and $6.9 million for the three months ended June 30, 2014 and 2013, respectively, an increase of 15.9% due primarily to higher risk management costs.

Other (income) loss, net. Other (income) loss, net was a $1.9 million loss for the three months ended June 30, 2014 compared to income of $1.9 million for the three months ended June 30, 2013. This change is driven primarily by a reduction in the equity income of MPL in the second quarter of 2014 due to non-routine expense projects on the pipeline during the three months ended June 30, 2014.

Operating income. Income from operations was $72.8 million for the three months ended June 30, 2014 compared to $53.1 million for the three months ended June 30, 2013. This increase was primarily due to lower turnaround expenses in the three months ended June 30, 2014 compared to the same period in 2013, partially offset by higher direct operating expenses and lower equity income from MPL.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

Refining gross product margin. Refining gross product margin for the six months ended June 30, 2014 was $277.9 million compared to $324.4 million for the six months ended June 30, 2013, a decrease of 14.3%, primarily due to lower market crack spreads, partially offset by higher sales volumes in the six months ended June 30, 2014. The higher sales volumes during the six months ended June 30, 2014 are related to increased throughput capacity from our crude expansion project completed in the second quarter of 2013 as well as less refinery downtime from the 2013 turnaround and crude expansion

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project. Refining gross product margin per barrel of throughput was $16.54 for the six months ended June 30, 2014 compared to $25.48 for the six months ended June 30, 2013, a decrease of $8.94, or 35.1%, which is mostly attributable to lower market crack spreads in the six months ended June 30, 2014.

Direct operating expenses. Direct operating expenses totaled $72.7 million for the six months ended June 30, 2014 compared to $68.9 million for the six months ended June 30, 2013, a 5.5% increase. This increase was due primarily to the impact of higher natural gas costs during the six months ended June 30, 2014.

Turnaround and related expenses. Turnaround and related expenses totaled $1.4 million for the six months ended June 30, 2014 compared to $37.0 million for the six months ended June 30, 2013. The turnaround costs in the six months ended June 30, 2014 include costs for a partial turnaround of our hydrogen unit in the second quarter of 2014. The 2013 costs relate to a planned major plant turnaround which lasted the entire month of April 2013.

Depreciation and amortization. Depreciation and amortization was $16.3 million for the six months ended June 30, 2014 compared to $14.2 million for the six months ended June 30, 2013, an increase of 14.8%. This increase was due to increased assets placed in service since June 30, 2013, the most significant of which was the expansion project for one of our crude units which was placed in service in the second quarter of 2013.

Selling, general and administrative expenses. Selling, general and administrative expenses were $16.2 million and $14.4 million for the six months ended June 30, 2014 and 2013, respectively, an increase of 12.5%. This increase was primarily due to higher risk management and personnel costs in the six months ended June 30, 2014.

Other (income) loss, net. Other (income) loss, net was a $0.7 million loss for the six months ended June 30, 2014 compared to income of $5.3 million for the six months ended June 30, 2013. This change is driven primarily by a reduction in the equity income of MPL in the first quarter of 2014 due to non-routine expense projects on the pipeline during the six months ended June 30, 2014.

Operating income. Income from operations was $170.6 million for the six months ended June 30, 2014 compared to $195.2 million for the six months ended June 30, 2013. This decrease from the prior-year period of $24.6 million is primarily due to less favorable market crack spreads, higher direct operating expenses and lower equity income from MPL, offset by higher sales volumes and lower turnaround expenses during the six months ended June 30, 2014.

Retail Segment



	Three Months Ended						Six Months Ended
(in millions)	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Revenue	$	370.9		$	378.2		$	706.0		$	721.4
Costs, expenses and other:
Cost of sales	327.6			332.5			623.4			638.7
Direct operating expenses	30.1			29.6			59.1			57.9
Depreciation and amortization	1.7			1.8			3.4			3.6
Selling, general and administrative	6.5			6.3			13.4			12.6
Operating income	$	5.0		$	8.0		$	6.7		$	8.6
Operating data:
Retail gross product margin (1)	$	43.3		$	45.7		$	82.6		$	82.7
Company-owned stores:
Fuel gallons sold (in millions)	76.8			77.0			149.8			151.6
Fuel margin per gallon (2)	$	0.19		$	0.23		$	0.19		$	0.20
Merchandise sales	$	89.9		$	86.0		$	168.4		$	161.8
Merchandise margin % (3)	26.5		%	27.0		%	26.2		%	27.2		%
Number of stores at period end	164			163			164			163
Franchisee stores:
Fuel gallons sold (in millions)(4)	18.3			12.0			32.5			24.1
Royalty income	$	0.7		$	0.6		$	1.3		$	1.2
Number of stores at period end	81			73			81			73
Market Statistics:
PADD II gasoline prices ($/gallon)	$	3.70		$	3.72		$	3.56		$	3.63

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(1)

Retail gross product margin is calculated by subtracting retail costs of sales from total retail revenues. Retail gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance as a general indication of the amount above our cost of products that we are able to sell retail products. Each of the components used in this calculation (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of retail gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of retail gross product margin to the most directly comparable GAAP measure, see “Results of Operations—Other Non-GAAP Performance Measures."

(2)

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

(3)

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


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

Three Months Ended June 30, 2014 Compared to the Three Months Ended June 30, 2013

Retail gross product margin. Retail gross product margin for the three months ended June 30, 2014 was $43.3 million compared to $45.7 million for the three months ended June 30, 2013, a decrease of 5.3%. This decrease was driven primarily by lower fuel margins at our company-operated stores which accounted for a $3.9 million decrease. For the three months ended June 30, 2014 and 2013, the average fuel margin per gallon was $0.19 per gallon and $0.23 per gallon, respectively. Partially offsetting this decrease in fuel margin was increased margin on merchandise and other of $1.5 million, due primarily to higher revenues at NTB due to improvements in product pricing.

Direct operating expenses. Direct operating expenses totaled $30.1 million for the three months ended June 30, 2014, compared to $29.6 million for the three months ended June 30, 2013, an increase of 1.7%, due primarily to higher personnel and advertising costs.

Depreciation and amortization. Depreciation and amortization was $1.7 million and $1.8 million for the three months ended June 30, 2014 and 2013, respectively.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.5 million and $6.3 million for the three months ended June 30, 2014 and 2013, respectively. This increase was due to higher personnel and risk management costs partially offset by lower spending on information technology related services.

Operating income. Operating income was $5.0 million for the three months ended June 30, 2014 compared to $8.0 million for the three months ended June 30, 2013, a decrease of $3.0 million. This decrease was driven primarily by lower gross margin on fuel.

Six Months Ended June 30, 2014 Compared to the Six Months Ended June 30, 2013

Retail gross product margin. Retail gross product margin for the six months ended June 30, 2014 was $82.6 million compared to $82.7 million for the six months ended June 30, 2013, a decrease of 0.1%. This decrease was primarily due to lower fuel margin at our company-operated stores which decreased $1.6 million from the prior year quarter, primarily due to a $0.01 decline in average fuel margin per gallon sold and, to a lesser extent, lower fuel volumes. Partially offsetting the lower fuel margin was a 16.7% increase in other revenue during the six months ended June 30, 2014 primarily due to higher revenues from NTB resulting from product pricing improvements.

Direct operating expenses. Direct operating expenses totaled $59.1 million for the six months ended June 30, 2014 compared to $57.9 million for the six months ended June 30, 2013, an increase of 2.1%. This increase is primarily due to higher personnel costs and rent and utility costs at our stores in the six months ended June 30, 2014.

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Depreciation and amortization. Depreciation and amortization was $3.4 million and $3.6 million for the six months ended June 30, 2014 and 2013, respectively.

Selling, general and administrative expenses. Selling, general and administrative expenses were $13.4 million and $12.6 million for the six months ended June 30, 2014 and 2013, respectively, a 6.3% increase. The increase relates primarily to higher personnel and risk management costs in the six months ended June 30, 2014, partially offset by lower costs for information technology services.

Operating income. Operating income was $6.7 million for the six months ended June 30, 2014 compared to $8.6 million for the six months ended June 30, 2013, a decrease of $1.9 million. The decrease is primarily attributable to higher direct operating expenses and selling, general and administrative expenses during the six months ended June 30, 2014.

Adjusted EBITDA

Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with the board of directors of our general partner, creditors, analysts and investors concerning our financial performance. We also believe Adjusted EBITDA may be used by some investors to assess the ability of our assets to generate sufficient cash flow to make distributions to our unitholders. The revolving credit facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing our senior secured notes and the revolving credit facility. Adjusted EBITDA should not be considered as an alternative to operating earnings or net earnings as measures of operating performance. In addition, Adjusted EBITDA is not presented as and should not be considered an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before turnaround and related expenses, equity-based compensation expense, gains (losses) from derivative activities, reorganization and related costs and adjustments to reflect proportionate depreciation expense from MPL operations. Other companies, including companies in our industry, may calculate Adjusted EBITDA differently than we do, limiting its usefulness as a comparative measure. Adjusted EBITDA also has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of our results as reported under GAAP. Some of these limitations include that Adjusted EBITDA:


•	does not reflect our cash expenditures, or future requirements, for capital expenditures or contractual commitments;


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


•	does not reflect our interest expense, or the cash requirements necessary to service interest or principal payments, on our debt;


•	does not reflect the equity income in our MPL investment, but includes 17% of the calculated EBITDA of MPL;


•	does not reflect gains and losses from crack spread derivative contract activities, which may have a substantial impact on our cash flow;


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


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

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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, 2014
	Refining		Retail		Other			Total
(in millions)
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	—		—		1.2			1.2
Reorganization and related costs	—		—		3.5			3.5
Adjusted EBITDA	$	82.7	$	6.7	$	(7.3	)	$	82.1



	Three Months Ended June 30, 2013
	Refining		Retail		Other			Total
(in millions)
Net income	$	53.1	$	5.0	$	5.8		$	63.9
Adjustments:
Interest expense	—		—		6.3			6.3
Income tax provision	—		3.0		—			3.0
Depreciation and amortization	7.5		1.8		0.1			9.4
EBITDA subtotal	60.6		9.8		12.2			82.6
MPL proportionate depreciation expense	0.7		—		—			0.7
Turnaround and related expenses	27.3		—		—			27.3
Equity-based compensation expense	—		—		0.4			0.4
Reorganization and related costs	—		—		0.5			0.5
Gains from derivative activities	—		—		(20.6		)	(20.6		)
Adjusted EBITDA	$	88.6	$	9.8	$	(7.5	)	$	90.9

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	Six Months Ended June 30, 2014
	Refining	Retail	Other		Total
(in millions)
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	—	—	5.5		5.5
Reorganization and related costs	—	—	12.9		12.9
Adjusted EBITDA	189.7	10.1	(15.1	)	184.7



	Six Months Ended June 30, 2013
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	195.2	$	5.7	$	(17.6	)	$	183.3
Adjustments:
Interest expense	—		—		12.7			12.7
Income tax provision	—		2.9		—			2.9
Depreciation and amortization	14.2		3.6		0.2			18.0
EBITDA subtotal	209.4		12.2		(4.7		)	216.9
MPL proportionate depreciation expense	1.4		—		—			1.4
Turnaround and related expenses	37.0		—		—			37.0
Equity-based compensation expense	—		—		5.7			5.7
Reorganization and related costs	—		—		0.9			0.9
Gains from derivative activities	—		—		(14.1		)	(14.1		)
Adjusted EBITDA	$	247.8	$	12.2	$	(12.2	)	$	247.8

Other Non-GAAP Performance Measures

Refining gross product margin per barrel, retail fuel margin and merchandise margin are non-GAAP performance measures that we believe are important to investors in analyzing our segment performance.

Refining gross product margin per barrel is a financial measurement calculated by subtracting refining costs of sales from total refining revenues and dividing the difference by the total throughput or total refined products sold for the respective periods presented. Refining gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refining performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in these calculations (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refining gross product margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure.

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The following table shows the reconciliation of refining gross product margin to refining revenue and refining cost of sales for the periods indicated. A reconciliation of refining revenue and refining cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in “—Segment Financial Data.”



	Three Months Ended				Six Months Ended
(in millions)	June 30, 2014		June 30, 2013		June 30, 2014		June 30, 2013
Refining revenue	$	1,486.7	$	1,014.8	$	2,730.3	$	2,033.4
Refining cost of sales	1,359.5		889.0		2,452.4		1,709.0
Refining gross product margin	$	127.2	$	125.8	$	277.9	$	324.4

Retail fuel margin and merchandise margin are non-GAAP measures that we believe are important to investors in evaluating our retail segment’s operating results as these measures provide an indication of our performance on significant product categories within the segment. Our calculation of fuel margin and merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.

The following table shows the reconciliations of fuel margin and merchandise margin to retail revenue and retail cost of sales for the periods indicated. A reconciliation of retail revenue and retail cost of sales to consolidated revenue and cost of sales in our consolidated statements of operations and comprehensive income is included above in “—Segment Financial Data.”



	Three Months Ended						Six Months Ended
(in millions)	June 30, 2014			June 30, 2013			June 30, 2014			June 30, 2013
Retail revenue:
Fuel revenue	$	273.7		$	285.2		$	523.1		$	545.9
Merchandise revenue	89.9			86.0			168.4			161.8
Other revenue	11.9			11.6			23.2			22.3
Intercompany eliminations	(4.6		)	(4.6		)	(8.7		)	(8.6		)
Retail revenue	370.9			378.2			706.0			721.4

Retail cost of sales:
Fuel cost of sales	259.2			266.8			494.4			515.6
Merchandise cost of sales	66.1			62.7			124.3			117.8
Other cost of sales	6.9			7.6			13.4			13.9
Intercompany eliminations	(4.6		)	(4.6		)	(8.7		)	(8.6		)
Retail cost of sales	327.6			332.5			623.4			638.7

Retail gross product margin:
Fuel margin	14.5			18.4			28.7			30.3
Merchandise margin	23.8			23.3			44.1			44.0
Other margin	5.0			4.0			9.8			8.4
Intercompany eliminations	—			—			—			—
Retail gross product margin	$	43.3		$	45.7		$	82.6		$	82.7

Liquidity and Capital Resources

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

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including prevailing market conditions, interest rates and our financial condition and credit rating. For discussions on our refinery gross product margin per barrel and retail fuel margin per gallon and merchandise margin for company-operated stores, see “Results of Operations—Refining Segment” and “Results of Operations—Retail Segment.”

As of June 30, 2014, we had $275 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 (the “2020 Secured Notes”) and had no outstanding balance under our ABL Facility. As of June 30, 2014, the borrowing base under the ABL Facility was $279.2 million and availability under the ABL Facility was $244.0 million (which is net of $35.2 million in outstanding letters of credit).

During the first quarter of 2014, we initiated a plan that includes 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 will be terminated. As such, we recognized $3.5 million and $12.9 million of expense during the three and six months ended June 30, 2014, respectively, which included compensation related to the severance of employment and the acceleration of unvested equity based compensation. The Company expects that substantially all reorganization costs associated with the corporate office relocation have been fully recognized at June 30, 2014. As of June 30, 2014, remaining cash payments under this reorganization plan are estimated to be $1.9 million, which will be paid from 2014 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 our revolving credit facility, will be adequate to meet our ordinary course working capital, capital expenditures, debt service and other cash requirements for at least the next twelve months. However, we may increase future liquidity via the sale of additional common units, obtaining new or expanded borrowing capacity, or both.

Cash Flows

The following table sets forth our cash flows for the periods indicated:



	Six Months Ended
(in millions)	June 30, 2014			June 30, 2013
Net cash provided by operating activities	$	154.3		$	124.1
Net cash used in investing activities	(23.7		)	(68.4		)
Net cash used in financing activities	(109.5		)	(230.1		)
Net increase (decrease) in cash and cash equivalents	21.1			(174.4		)
Cash and cash equivalents at beginning of period	85.8			272.9
Cash and cash equivalents at end of period	$	106.9		$	98.5

Net Cash Provided By Operating Activities. Net cash provided by operating activities for the six months ended June 30, 2014 was $154.3 million. The most significant providers 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 working capital increase of $7.3 million.

Net cash provided by operating activities for the six months ended June 30, 2013 was $124.1 million. The most significant providers of cash were our net income ($183.3 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($18.0 million), equity-based compensation ($5.7 million) and gain from the change in fair value of outstanding derivatives ($39.9 million). Additionally, cash was negatively impacted by a net working capital increase of $44.2 million.

The increase in cash provided by operating activities of $30.2 million versus the prior year is primarily due to lower working capital requirements, partially offset by lower earnings.

Net Cash Used In Investing Activities. Net cash used in investing activities for the six months ended June 30, 2014 of $23.7 million was primarily related to capital expenditures. 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.

Net cash used in investing activities for the six months ended June 30, 2013 was $68.4 million, relating primarily to capital expenditures of $69.3 million. Capital spending for the six months ended June 30, 2013 primarily included the capacity expansion project on one of our crude distillation units, our waste water treatment plant construction at our refinery, safety related enhancements and facility improvements at the refinery and retail store locations.

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The decrease in cash used in investing activities of $44.7 million versus the prior year is primarily due to the capacity expansion project to one of our crude distillation units in the prior year quarter which did not reoccur in 2014.

Net Cash Used In Financing Activities. 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.

Net cash used in financing activities for the six months ended June 30, 2013 of $230.1 million was related to our quarterly distributions to unitholders.

The decrease in cash used in financing activities of $120.6 million versus the prior year quarter is primarily due to lower cash available for distribution in the fourth quarter of 2013 and the first quarter of 2014 versus the same quarters 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, 2014 was $145.0 million, consisting of $625.7 million in total current assets and $480.7 million in total current liabilities. Working capital at December 31, 2013 was $109.5 million, consisting of $525.0 million in total current assets and $415.5 million in total current liabilities. The increase in working capital as of June 30, 2014 was primarily due to cash generated by operations being in excess of our capital spending and cash distributions, partially offset by timing differences in the payment and collection of accounts payable and accounts receivable.

We maintain a crude oil and supply and logistics agreement with J.P. Morgan Commodities Canada Corporation (“JPM CCC”) pursuant to which JPM CCC assists us in the purchase of the crude oil requirements of our refinery and provides transportation and other logistical services for delivery of the crude oil to our storage tanks at Cottage Grove, Minnesota, which are approximately two miles from our refinery. In March 2012, we amended and restated the crude oil supply and logistics agreement with JPM CCC. Upon delivery of the crude oil to us, we pay JPM CCC the price of the crude oil plus certain agreed fees and expenses. We believe this crude oil supply and logistics agreement significantly reduces our crude inventories and allows us to take title to and price our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished product output is sold.

Capital Spending

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.

Capital spending for the six months ended June 30, 2013 of $69.3 million was primarily related to the capacity expansion project on one of our crude distillation units, our waste water treatment plant construction at our refinery and safety related enhancements and facility improvements at the refinery and retail store locations.

For 2014, we currently expect to spend approximately $36 million on capital projects, including approximately $17 million on the upgrade of our waste water treatment facility, the majority of which was incurred as of June 30, 2014. The remaining projects primarily relate to the ongoing replacement spending also referred to as maintenance capital. While we do not have a significant amount of capital spending planned for discretionary projects for 2014, the board of directors of our general partner may approve cash reserves for discretionary projects in determining cash available for distributions. These reserves would replenish cash used for discretionary projects in prior years and could be utilized for future discretionary projects.

Our Distribution Policy

We expect within 60 days after the end of each quarter to make distributions to unitholders of record as of the applicable record date. The board of directors of our general partner adopted a policy pursuant to which distributions for each quarter will equal the amount of available cash we generate in such quarter. Distributions on our units will be in cash. Available cash for each quarter will be determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter will generally equal our cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate, including reserves for turnaround and related expenses. Such a decision by the board of directors may have an adverse impact on the available cash in the quarter(s) in which the reserves are withheld and a corresponding mitigating impact on the future quarter(s) in which the reserves are utilized. Actual turnaround and related expenses will be funded with cash reserves or borrowings under our revolving credit facility. We do not intend to maintain excess distribution coverage or reserve cash for the purpose of maintaining stability or growth in our quarterly distribution. We do not intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.

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Because our policy will be to distribute an amount equal to the available cash we generate each quarter, our unitholders will have direct exposure to fluctuations in the amount of cash generated by our business. The amount of quarterly distributions, if any, will vary based on operating cash flow during such quarter. As a result, quarterly distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in, among other factors, (i) operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices received for finished products, (iii) working capital requirements, (iv) capital expenditures and (v) cash reserves deemed necessary or appropriate by the board of directors of our general partner. Such variations in the amount of the quarterly distributions may be significant. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The board of directors of our general partner may change the foregoing distribution policy at any time. Our partnership agreement does not require us to pay distributions to our unitholders on a quarterly or other basis.

The following table details the quarterly distributions declared to common unitholders since our IPO in July 2012 (in millions, except per unit amounts):



Date Declared	Date Paid	Common Units and equivalents (in millions)	Distribution per common unit and equivalent		Total Distribution (in millions)
2013 Distributions:
February 11, 2013	February 28, 2013	91.9	$	1.27	$	116.7
May 13, 2013	May 30, 2013	92.2	$	1.23	113.4
August 13, 2013	August 29, 2013	92.2	$	0.68	62.7
November 11, 2013	November 27, 2013	92.2	$	0.31	28.6
Distributions declared during 2013			$	3.49	321.4
2014 Distributions:
February 7, 2014	February 28, 2014	92.4	$	0.41	37.9
May 6, 2014	May 30, 2014	93.0	$	0.77	71.6
August 5, 2014	August 29, 2014	93.1	$	0.53	$	49.2
Distributions declared during 2014			$	1.71	158.7

Total distributions declared since 2013			$	5.20	$	480.1

Notwithstanding our distribution policy, certain provisions of the indenture governing the 2020 Secured Notes and our revolving credit 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, 2014:



(in millions)	Three Months Ended June 30, 2014
Net income	$	57.9
Adjustments:
Interest expense	6.2
Income tax provision	1.5
Depreciation and amortization	10.2
EBITDA subtotal	75.8
MPL proportionate depreciation expense	0.7
Turnaround and related expenses	0.9
Equity-based compensation impacts	1.2
Reorganization and related costs	3.5
Adjusted EBITDA (1)	82.1
Cash interest expense	(5.6		)
Current tax provision	(1.5		)
MPL proportionate depreciation expense	(0.7		)
Capital expenditures (2)	(10.1		)
Cash reserve for turnaround and related expenses (4)	(7.5		)
Cash reserve for discretionary capital expenditures (4)	(7.5		)
Cash Available for Distribution (3)	$	49.2

(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 Secured Notes and ABL Facility. We believe the presentation of Adjusted EBITDA is useful to investors because it is frequently used by securities analysts, investors and other interested parties in the evaluation of companies in our industry. The calculation of Adjusted EBITDA generally eliminates the effects of financings, income taxes and the accounting effects of significant turnaround activities which many of our peers capitalize and therefore exclude from Adjusted EBITDA. Adjusted EBITDA should not be considered as an alternative to operating income or net income as measures of operating performance. In addition, Adjusted EBITDA is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. Adjusted EBITDA is defined as net income (loss) before interest expense, income taxes and depreciation and amortization, adjusted for depreciation from the Minnesota Pipe Line operations, turnaround and related expenses, equity-based compensation expense, gains or losses from derivative activities and costs related to our reorganization activities. Adjusted EBITDA has limitations as an analytical tool and should not be considered in isolation, or as a substitute for analysis of the results as reported under GAAP.


(2)	Capital expenditures include maintenance, replacement and and regulatory capital projects on an accrual basis.

(3)

Cash available for distribution is a non-GAAP performance measure that we believe is important to investors in evaluating our overall cash generation performance. Cash available for distribution should not be considered as an alternative to operating income or net income (loss) as measures of operating performance. In addition, cash available for distribution is not presented as, and should not be considered, an alternative to cash flow from operations as a measure of liquidity. We have reconciled cash available for distribution to Adjusted EBITDA and in addition reconciled Adjusted EBITDA to net income. Cash available for distribution has limitations as an analytical tool and 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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(4)	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.

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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. We may use financial instruments such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of the identified risks. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements.

Commodity Price Risk

As a refiner of petroleum products, we have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, we must achieve a positive spread between the cost of raw materials and the value of finished products (i.e., refinery gross product margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The timing, direction and overall change in refined product prices versus crude oil prices will impact profit margins and could have a significant impact on our earnings and cash flows. Assuming all other factors remained constant, a $1 per barrel change in our average refinery gross product margin, based on our average refinery throughput for the six months ended June 30, 2014 of 92,826 bpd, would result in a change of $33.9 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 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 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.

In addition, the crude oil supply and logistics agreement with JPM CCC allows us to take title to, and price, our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished refined products are sold. Furthermore, this agreement enables us to mitigate potential working capital fluctuations relating to crude oil price volatility.

Basis Risk

The effectiveness of our risk mitigation strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors, for example the location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure. In hedging NYMEX or U.S. Gulf Coast (or any other relevant benchmark) crack spreads, we experience location basis as the settlement price of NYMEX refined products (related more to New York Harbor cash markets) or U.S. Gulf Coast refined products (related more to U.S. Gulf Coast cash markets) may be different than the prices of refined products in our Upper Great Plains pricing area. The risk associated with not hedging the basis when using NYMEX or U.S. Gulf Coast forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX or U.S. Gulf Coast while pricing in our market remains flat or decreases, then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the pricing in our market. Assuming all other factors remained constant, a $1 per barrel change in our gasoline and distillate basis would result in an annual change of $16.4 million and $12.8 million in our annual gross product margin on gasoline and distillate sales, respectively, based on our average refinery production of these productsfor the six months ended June 30, 2014 of 44,859 bpd and 35,063 bpd, respectively.

Commodities Price and Basis Risk Management Activities

We have entered into agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined petroleum products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. Under the agreements, as market conditions permit, we have the capacity to mitigate our crack spread risk with respect to reasonable percentages of the refinery’s projected monthly production of some or all of these refined products. As of June 30, 2014, we have no hedged barrels of future gasoline and diesel production.

We may enter into additional futures derivatives contracts at times when we believe market conditions or other circumstances suggest that it is prudent to do so. Although we have historically been hedged at higher levels of expected production, we intend to hedge significantly less than what we hedged at the time of our inception. We may use commodity derivatives contracts such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of

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the identified risks; however, it is our plan to hedge a lesser amount of production than we historically have, which will increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis. Additionally, we may take advantage of opportunities to modify our derivative portfolio to change the percentage of our hedged refined product volumes when circumstances suggest that it is prudent to do so.

Interest Rate Risk

As of June 30, 2014, the availability under our revolving credit facility was $244.0 million. This availability is net of $35.2 million in outstanding letters of credit as of June 30, 2014. We had no borrowings under our revolving credit facility at June 30, 2014. Borrowings under our revolving credit facility bear interest, at our election, at either an alternative base rate, plus an applicable margin (which ranges between 1.00% and 1.50% pursuant to a grid based on average excess availability) or a LIBOR rate plus an applicable margin (which ranges between 2.00% and 2.50% pursuant to a grid based on average excess availability).

We have interest rate exposure on a portion of the cost of crude oil payable to JPM CCC for the crude oil inventory that they purchase for delivery to our refinery under the crude oil supply and logistics agreement. This exposure is offset with the credits we receive from JPM CCC for the trade terms granted by suppliers to them on crude oil purchases intended for our refinery. Our interest rate exposure is the spread between 3-months and 1-month LIBOR. A widening of the spread between these two rates may result in a higher cost of crude oil to us.

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.

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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, 2014. 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, 2014.

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, 2014, that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

While we may, from time to time, be involved in various lawsuits, claims and proceedings arising in the normal course of business, we are not currently a party to any lawsuits, claims or proceedings that, if determined adversely against us, would have a material adverse effect on our financial position, 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 2013 Annual Report on Form 10-K and on Form 10-Q for the quarter ended March 31, 2014, which risks could materially affect our business, financial condition or future results. There has been no material change in our risk factors from those described in the 2013 Annual Report on Form 10-K or the Quarterly Report on Form 10-Q for the quarter ended March 31, 2014. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 5. Other Information.

On August 4, 2014, the Company entered into an employment agreement with its Executive Vice President and Chief Financial Officer, David Bonczek. This agreement replaces and supersedes all previous agreements in place between the Company and Mr. Bonczek, and provides for an annual base salary to Mr. Bonczek of $400,000 per year and the opportunity to earn an incentive-based annual cash bonus under the Company’s Incentive Compensation Plan (the “Bonus Plan”). For 2014, Mr. Bonczek’s target bonus under the Bonus Plan is equal to 100% of his annual base salary and may range from 0% and 200% of target, depending upon the achievement of certain performance metrics. Mr. Bonczek is also eligible to participate in other employee benefit plans, practices and programs maintained by the Company, as in effect from time to time on the same basis as other similarly situated executives of the Company, to the extent consistent with applicable law and the terms of such plans and programs.

The agreement further provides for relocation benefits consistent with the Company’s relocation policies, as well as certain severance benefits. If Mr. Bonczek’s employment is terminated by the Company without cause or by Mr. Bonczek for good reason on or before March 31, 2015, then following execution of a release agreement he will be entitled to (a) a lump sum equal to one-times his annual base salary; (b) acceleration of all unvested equity awards issued under the Company’s Long-Term Incentive Plan (“LTIP”) prior to January 1, 2014; (c) outplacement support; (d) reimbursement for a portion of up to six months’ worth of COBRA premiums; (e) unused and accrued vacation; and (f) potential cash bonus under the Bonus Plan for 2014.

If Mr. Bonczek’s employment is terminated by the Company without cause or by Mr. Bonczek for good reason after March 31, 2015, then following execution of a release agreement he will be entitled to a lump sum equal to one-times his annual base salary at the time of termination plus unused and accrued vacation pay. If such termination is within twelve months following the occurrence of a change of control, then, in addition to the payments described in the preceding sentence, all outstanding LTIP awards held by Mr. Bonczek shall immediately vest.

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The above statements are qualified in their entirety by reference to the employment agreement, which has been filed as Exhibit 10.1 to this Quarterly Report on Form 10-Q.

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 5, 2014	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 5, 2014	By:	/s/ David Bonczek
	Name:	David Bonczek
	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
10.1(a) (c)		Employment Letter Agreement, dated August 4, 2014, by and between Northern Tier Energy LLC and David Bonczek.

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 David Bonczek, 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 David Bonczek, 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(b)		XBRL Instance Document.

101.SCH(b)		XBRL Taxonomy Extension Schema Document.

101.CAL(b)		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF(b)		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB(b)		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE(b)		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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