UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark one)

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: June 30, 2013

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 Number: 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.)
38C Grove Street, Suite 100 Ridgefield, Connecticut	06877
(Address of principal executive offices)	(Zip Code)

(203) 244-6550

(Registrant’s telephone number, including area code)

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.    x  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).    x  Yes    ¨  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	¨	Accelerated filer	¨
Non-accelerated filer	x  (Do not check if a smaller reporting company)	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ¨  Yes    x  No

As of August 12, 2013, Northern Tier Energy LP had 92,086,053 common units outstanding.

NORTHERN TIER ENERGY LP

FORM 10-Q FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2013

TABLE OF CONTENTS

CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS
PART I – FINANCIAL INFORMATION
ITEM 1. Financial Statements
Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012	4
Consolidated Statements of Operations and Comprehensive Income for the three and six month periods ended June 30, 2013 and 2012	5
Consolidated Statements of Cash Flows for the six month periods ended June 30, 2013 and 2012	6
Notes to Consolidated Financial Statements	7
ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
ITEM 3. Quantitative and Qualitative Disclosures about Market Risk	40
ITEM 4. Controls and Procedures	42
PART II – OTHER INFORMATION
ITEM 1. Legal Proceedings	42
ITEM 1A. Risk Factors	42
ITEM 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
ITEM 6. Exhibits	42
SIGNATURES	43

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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 and operating results are based on our forecasts for our existing operations and 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 and crack spreads, including the impact of these factors on our liquidity;

• 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, including guidance related to the Dodd-Frank Act;

• 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. income or state 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” and elsewhere in this Report and (2) Part I, “Item 1A. Risk Factors” of our 2012 Annual Report on Form 10-K.

Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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PART I – FINANCIAL INFORMATION

Item 1. Financial Statements

NORTHERN TIER ENERGY LP

CONSOLIDATED BALANCE SHEETS

(in millions, except unit data)

	June 30,			December 31,
	2013			2012
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	98.5		$	272.9
Receivables, less allowance for doubtful accounts		193.5			129.3
Inventories		182.8			162.4
Other current assets		23.1			34.9
Total current assets		497.9			599.5
NON-CURRENT ASSETS
Equity method investment		86.4			87.5
Property, plant and equipment, net		437.7			386.0
Intangible assets		35.4			35.4
Other assets		27.9			28.4
Total Assets	$	1,085.3		$	1,136.8
LIABILITIES AND EQUITY
CURRENT LIABILITIES
Accounts payable	$	281.6		$	230.4
Accrued liabilities		53.6			77.4
Derivative liability		6.8			43.7
Total current liabilities		342.0			351.5
NON-CURRENT LIABILITIES
Long-term debt		275.0			275.0
Lease financing obligation		7.3			7.5
Other liabilities		18.2			19.0
Total liabilities		642.5			653.0
Commitments and contingencies
EQUITY
Accumulated other comprehensive loss		(2.4	)		(2.5	)
Partners’ capital (92,086,053 and 91,921,112 units issued and outstanding at June 30, 2013 and December 31, 2012, respectively)		445.2			486.3
Total equity		442.8			483.8
Total Liabilities and Equity	$	1,085.3		$	1,136.8

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 (LOSS)

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

	Three Months Ended						Six Months Ended
	June 30,			June 30,			June 30,			June 30,
	2013			2012			2013			2012
REVENUE (a)	$	1,131.2		$	1,155.2		$	2,246.2		$	2,154.3
COSTS, EXPENSES AND OTHER
Cost of sales (a)		965.0			825.0			1,844.5			1,664.8
Direct operating expenses		62.1			61.5			126.4			122.2
Turnaround and related expenses		27.3			11.5			37.0			15.0
Depreciation and amortization		9.4			7.8			18.0			16.3
Selling, general and administrative		20.9			24.8			46.4			45.1
Formation and offering costs		0.5			1.0			0.9			1.0
Contingent consideration loss		—			0.1			—			65.8
Other income, net		(1.6	)		(1.2	)		(6.5	)		(3.3	)
OPERATING INCOME		47.6			224.7			179.5			227.4
Realized losses from derivative activities		(3.1	)		(67.4	)		(20.5	)		(120.3	)
Loss on early extinguishment of derivatives		—			(92.2	)		—			(136.8	)
Unrealized gains from derivative activities		28.7			191.3			39.9			102.9
Interest expense, net		(6.3	)		(10.7	)		(12.7	)		(21.1	)
INCOME BEFORE INCOME TAXES		66.9			245.7			186.2			52.1
Income tax provision		(3.0	)		(0.1	)		(2.9	)		(0.1	)
NET INCOME		63.9			245.6			183.3			52.0
Other comprehensive income, net of tax		—			—			0.1			—
COMPREHENSIVE INCOME	$	63.9		$	245.6		$	183.4		$	52.0
EARNINGS PER UNIT INFORMATION:
BASIC:
Weighted average number of units outstanding		91,915,000						91,915,000
Earnings per common unit	$	0.70					$	1.99
DILUTED:
Weighted average number of units outstanding		91,931,829						91,934,960
Earnings per common unit	$	0.70					$	1.99
SUPPLEMENTAL INFORMATION:
(a) Excise taxes included in revenue and cost of sales	$	71.1		$	71.2		$	141.9		$	136.8

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
	June 30,			June 30,
Increase (decrease) in cash	2013			2012
CASH FLOWS FROM OPERATING ACTIVITIES
Net income	$	183.3		$	52.0
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		18.0			16.3
Non-cash interest expense		1.2			2.4
Equity-based compensation expense		5.7			0.9
Equity method investment, net		—			(0.3	)
Contingent consideration loss		—			65.8
Unrealized gains from derivative activities		(39.9	)		(102.9	)
Loss on early extinguishment of derivatives		—			136.8
Changes in assets and liabilities, net:
Accounts receivable		(64.2	)		(57.4	)
Inventories		(20.4	)		4.0
Other current assets		14.9			14.4
Accounts payable and accrued expenses		27.5			(27.8	)
Other, net		(2.0	)		(4.3	)
Net cash provided by operating activities		124.1			99.9
CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(69.3	)		(12.4	)
Return of capital from investments		0.9			—
Net cash used in investing activities		(68.4	)		(12.4	)
CASH FLOWS FROM FINANCING ACTIVITIES
Equity distributions		(230.1	)		(40.0	)
Net cash used in financing activities		(230.1	)		(40.0	)
CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents		(174.4	)		47.5
Cash and cash equivalents at beginning of period		272.9			123.5
Cash and cash equivalents at end of period	$	98.5		$	171.0

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 (UNAUDITED)

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”) and was organized in such a way as to be treated as a master limited partnership (“MLP”) for tax purposes. NTE LLC was a wholly-owned subsidiary of Northern Tier Holdings LLC (“NT Holdings”) until July 31, 2012. On July 31, 2012, NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in connection with the closing of the underwritten initial public offering (“IPO”) of NTE LP (see Note 3). NT Holdings is a wholly-owned subsidiary of Northern Tier Investors LLC (“NT Investors”). NT Investors, NT Holdings and NTE LLC were formed by ACON Refining Partners L.L.C., TPG Refining L.P. and certain members of management (collectively, the “Investors”) during 2010. The St. Paul Park Refinery and Retail Marketing Business were formerly owned and operated by subsidiaries of Marathon Oil Corporation (“Marathon Oil”). These subsidiaries, Marathon Petroleum Company, LP (“MPC LP”), Speedway LLC (“Speedway”) and MPL Investments LLC, are together referred to as “MPC” or “Marathon” and are now subsidiaries of Marathon Petroleum Corporation (“Marathon Petroleum”). Marathon Petroleum was a wholly-owned subsidiary of Marathon Oil until June 30, 2011. Effective December 1, 2010, NTE LLC acquired the business from Marathon for approximately $608 million (the “Marathon Acquisition,” see Note 5).

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 IPO of NTE LP (see Note 3), 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.

As of June 30, 2013, SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 89,500 barrels per calendar 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 to markets primarily located in the Upper Great Plains of the United States.

As of June 30, 2013, NTR operates 163 convenience stores under the SuperAmerica brand and SAF supports 73 franchised stores which also utilize the SuperAmerica brand. These 236 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 United States 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, 2013 are not necessarily indicative of the results that may be expected for the year ending December 31, 2013, or for any other period.

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The consolidated balance sheet at December 31, 2012 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 2012 Annual Report on Form 10-K.

2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation

NTE LP is a Delaware limited partnership that was established as Northern Tier Energy, Inc. on October 24, 2011 and was subsequently converted into NTE LP as of June 4, 2012. On July 31, 2012, NTE LP closed its IPO whereby it sold 18,687,500 limited partnership units to the public. In connection with the closing of the IPO, NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK units, which were subsequently converted into common units, of NTE LP (see Note 3). Upon the closing of the IPO, the consolidated historical financial statements of NTE LLC became the historical financial statements of NTE LP. NTE LP consolidates all accounts of NTE LLC and its subsidiaries. NTE LLC consolidates all accounts of SPPR and NTRH. All significant intercompany accounts have been eliminated in these consolidated financial statements.

The Company’s common equity interest in MPL is accounted for using the equity method of accounting in accordance with the Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 323. 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 8 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 cost of $6.9 million as of June 30, 2013 and December 31, 2012 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 21 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, and includes the Company’s interest in NTOT, MPL and MPLI, and

• Retail – operates 163 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

Cash and Cash Equivalents

The Company considers all highly liquid investments with maturities of three months or less from the date of purchase to be cash equivalents.

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.

8

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 are 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 are recognized in the consolidated statements of operations. These gains and losses are reported as operating activities within the consolidated statements of cash flows.

Excise Taxes

The Company is required by various governmental authorities, including federal and state, to collect and remit taxes on certain products. Such taxes are presented on a gross basis in revenue and cost of sales in the consolidated statements of operations. These taxes totaled $71.1 million and $71.2 million for the three months ended June 30, 2013 and 2012, respectively, and $141.9 million and $136.8 million for the six months ended June 30, 2013 and 2012, respectively.

Income Taxes

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. As such, the Company has recorded deferred tax assets and deferred tax liabilities related to NTRH as of the election date. Additionally, the Company recorded current period income taxes for all periods subsequent to August 1, 2012 (see Note 6) at the NTRH level. Prior to August 1, 2012, all of the Company’s income was derived from subsidiaries which were limited liability companies and were therefore pass-through entities for federal income tax purposes. As a result, the Company did not incur federal income taxes prior to this date. The Company’s policy is to recognize interest related to any underpayment of taxes as interest expense and any penalties as administrative expenses.

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 our refinery. The exchange transactions are recognized at the carrying amount of the inventory transferred plus or minus any cash settlement due to grade or location differentials.

Accounting Developments

In February 2013, the FASB issued ASU No. 2013-02, “Reporting of Amounts Reclassified Out of Other Comprehensive Income,” which requires public companies to present information about reclassification adjustments from accumulated other comprehensive income in their annual and interim financial statements in a single note or on the face of the financial statements. This standard is effective prospectively for annual and interim reporting periods beginning after December 15, 2012. The Company’s presentation of comprehensive income in this quarterly report complies with this accounting standard.

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3. INITIAL PUBLIC OFFERING OF NORTHERN TIER ENERGY LP

On July 25, 2012, NTE LP priced 16,250,000 common units in its IPO at a price of $14.00 per unit, and on July 26, 2012, NTE LP common units began trading on the New York Stock Exchange (ticker symbol: NTI). NTE LP closed its IPO of 18,687,500 common units, which included 2,437,500 common units issued pursuant to the underwriters’ exercise of their option to purchase additional common units, on July 31, 2012.

The net proceeds from the IPO of approximately $245 million, after deducting the underwriting discount, along with approximately $56 million of cash on hand were used to: (i) distribute approximately $124 million to NT Holdings, of which approximately $92 million was used to redeem Marathon’s existing preferred interest in NT Holdings and $32 million was distributed to ACON Refining Partners L.L.C., TPG Refining L.P. and entities in which certain members of the Company’s management team hold an ownership interest, (ii) pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., related to deferred payment obligations from the early extinguishment of derivatives (see Note 11), (iii) pay $40 million to Marathon, which represents the cash component of a settlement agreement NTE LLC entered into with Marathon in satisfaction of a contingent consideration arrangement that was part of the Marathon Acquisition (see Note 5), (iv) redeem $29 million of NTE LLC senior secured notes at a redemption price of 103% of the principal amount thereof, plus accrued interest, for an estimated $31 million, and (v) pay other offering costs of approximately $15 million.

In connection with the closing of the IPO the following transactions and events occurred in the third quarter of 2012:

• The settlement agreement with Marathon with respect to the contingent consideration arrangements that were entered into in connection with the Marathon Acquisition became effective (see Note 5);

• The Company’s management services agreement with ACON Refining Partners L.L.C and TPG Refining L.P. (see Note 4) was terminated;

• NT Holdings contributed all of its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK units;

• NTE LP issued 18,687,500 common units to the public, representing a 20.3% limited partner interest; and

• NTRH elected to be treated as a corporation for federal income tax purposes, subjecting it to corporate-level tax.

4. RELATED PARTY TRANSACTIONS

The Investors, which include ACON Refining Partners L.L.C. and TPG Refining L.P., are related parties of the Company. MPL is also a related party of the Company. Subsequent to the Marathon Acquisition (see Note 5), the Company entered into a crude oil supply and logistics agreement with a third party and no longer has direct supply transactions with MPL.

Upon completion of the Marathon Acquisition, the Company entered into a management services agreement with the Investors pursuant to which they provided the Company with ongoing management, advisory and consulting services. This management services agreement was terminated in conjunction with the IPO of NTE LP as of July 31, 2012. While this agreement was in effect, the Investors also received quarterly management fees equal to 1% of the Company’s “Adjusted EBITDA” (as defined in the agreement) for the previous quarter (subject to a minimum annual fee of $2 million), as well as reimbursements for out-of pocket expenses incurred by them in connection with providing such management services. The Company recognized management fees relating to these services of $1.7 million and $2.2 million for the three and six months ended June 30, 2012, respectively. As a result of the NTE LP IPO, the Company was required to pay the Investors a specified success fee of $7.5 million that is a part of the IPO offering expenses discussed in Note 3.

5. MARATHON ACQUISITION

As previously described in Note 1, effective December 1, 2010, the Company acquired the business from MPC for $608 million. The Marathon Acquisition was accounted for by the purchase method of accounting for business combinations. Included in this amount was the estimated fair value of earn-out payments of $54 million as of the acquisition date. Of the remainder of the $608 million purchase price, $361 million was paid in cash as of December 31, 2010 and $80 million was satisfied by issuing MPC a perpetual payment in kind preferred interest in NT Holdings. The residual purchase price of $113 million (excluding the contingent earn-out consideration) was paid during the three months ended March 31, 2011. Upon the closing of the NTE LP IPO, MPC’s perpetual payment in kind preferred interest in NT Holdings was redeemed at par plus accrued interest for a total of approximately $92 million.

The Marathon Acquisition included contingent consideration arrangements under which the Company could have received margin support payments of up to $60 million from MPC or could have paid MPC net earn-out payments of up to $125 million over the term of the arrangements, depending on the Company’s Adjusted EBITDA as defined in the arrangements. On May 4, 2012, NTE LLC entered into a settlement agreement with MPC regarding the contingent consideration. The

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settlement agreement was contingent upon the consummation of the IPO of NTE LP, which occurred on July 31, 2012 (see Note 3). Pursuant to this settlement agreement, MPC received $40 million of the net proceeds from the IPO of NTE LP and NT Holdings issued MPC a new $45 million perpetual payment in kind preferred interest in NT Holdings in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. This preferred interest in NT Holding will not be dilutive to NTE LP unitholders. The Company also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the margin support agreement. Upon the consummation of the NTE LP IPO, the Company reversed the amounts recorded for the margin support and earn-out arrangements and recorded a liability of $85 million representing the amount of the settlement agreement.

6. INCOME TAXES

On July 31, 2012, NTRH was established as the parent company of NTR and NTB. NTRH elected to be taxed as a corporation for federal and state income tax purposes effective August 1, 2012. Prior to that, no provision for federal income tax was calculated on earnings of the Company or its subsidiaries as all entities were non-taxable.

On August 1, 2012, the Company recorded an $8.0 million tax charge to recognize its deferred tax asset and liability positions as of NTRH’s election to be taxed as a corporation. As of NTRH’s election date, the Company recorded a current deferred tax asset of $2.2 million, included in other current assets, and a non-current deferred tax liability of $10.2 million, included in other liabilities.

The Company’s effective tax rate for the three and six months ended June 30, 2013 was 4.5% and 1.6%, respectively, as compared to the Company’s combined federal and state expected statutory tax rate of 40.4%. The Company’s effective tax rate for the three and six months ended June 30, 2013 is lower than the statutory rate primarily due to the fact that only the retail operations of the Company are taxable entities. The Company’s effective tax rate for the three and six months ended June 30, 2012 is less than 1.0% due to the fact that the Company acted as a pass through entity for income tax purposes during that period.

7. INVENTORIES

	June 30,		December 31,
(in millions)	2013		2012
Crude oil and refinery feedstocks	$	8.2	$	9.7
Refined products		137.5		117.0
Merchandise		20.9		20.8
Supplies and sundry items		16.2		14.9
Total	$	182.8	$	162.4

The LIFO method accounted for 80% and 78% of total inventory value at June 30, 2013 and December 31, 2012, respectively.

8. EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in MPL. The carrying value of this equity method investment was $86.4 million and $87.5 million at June 30, 2013 and December 31, 2012, respectively.

As of June 30, 2013 and December 31, 2012, the carrying amount of the equity method investment was $6.5 million and $6.7 million higher than the underlying net assets of the investee, respectively. The Company is amortizing this difference over the remaining life of MPL’s primary asset (the fixed asset life of the pipeline).

Distributions received from MPL were $1.2 million and $2.2 million for the three months ended June 30, 2013 and 2012, respectively, and $6.1 million and $5.6 million for the six months ended June 30, 2013 and 2012, respectively. Equity income from MPL was $1.8 million and $3.0 million for the three months ended June 30, 2013 and 2012, respectively, and $5.2 million and $5.9 million for the six months ended June 30, 2013 and 2012, respectively.

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9. 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	2013		2012
Land		$	8.9	$	8.9
Retail stores and equipment	2 - 22 years		48.7		49.1
Refinery and equipment	5 - 24 years		380.1		330.4
Buildings and building improvements	25 years		9.2		8.3
Software	5 years		18.2		17.8
Vehicles	5 years		4.7		2.9
Other equipment	2 - 7 years		6.5		6.1
Precious metals			10.6		10.5
Assets under construction			30.0		14.3
			516.9		448.3
Less: accumulated depreciation			79.2		62.3
Property, plant and equipment, net		$	437.7	$	386.0

PP&E includes gross assets acquired under capital leases of $7.9 million at both June 30, 2013 and December 31, 2012, with related accumulated depreciation of $0.9 million and $0.7 million, respectively. The Company had depreciation expense related to capitalized software of $0.9 million and $0.8 million for the three months ended June 30, 2013 and 2012, respectively, and $1.8 million and $1.6 million for the six months ended June 30, 2013 and 2012, respectively.

10. INTANGIBLE ASSETS

Intangible assets are comprised of franchise rights amounting to $19.8 million and trademarks amounting to $15.6 million at both June 30, 2013 and December 31, 2012. 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.

11. DERIVATIVES

The Company is subject to crude oil and refined product market price fluctuations caused by supply conditions, weather, economic conditions and other factors. In October 2010, at the request of the Company, MPC initiated a strategy to mitigate refining margin risk on a portion of the business’s 2011 and 2012 projected refining production. In connection with the Marathon Acquisition, derivative instruments executed pursuant to this strategy, along with all corresponding rights and obligations, were assumed by the Company. The Company also may periodically use futures contracts to manage price risks associated with inventory quantities above or below target levels.

Under the 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 as a gain or loss in the derivative activity captions on the consolidated statements of operations. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 14) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end. At June 30, 2013 and December 31, 2012, the Company had open commodity derivative instruments consisting of crude oil futures to buy two million and five million barrels, respectively, and refined products futures and swaps to sell two million and five million barrels, respectively, primarily to mitigate the volatility of refining margins through 2013.

For the three months ended June 30, 2013 and 2012, the Company recognized net gains of $25.6 million and $31.7 million, respectively, related to derivative activities. Of these total net gains, $3.1 million and $159.6 million represented realized losses on settled contracts (including early extinguishments in 2012 as noted below) for the three months ended June 30, 2013 and 2012, respectively. Additionally, the Company recognized unrealized gains of $28.7 million and $191.3 million on open contracts for the three months ended June 30, 2013 and 2012, respectively.

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For the six months ended June 30, 2013 and 2012, the Company recognized a net gain of $19.4 million and a net loss of $154.2 million, respectively, related to derivative activities. Of these total gains and losses, $20.5 million and $257.1 million represented realized losses on settled contracts (including early extinguishments in 2012 as noted below) for the six months ended June 30, 2013 and 2012, respectively. Additionally, the Company recognized unrealized gains of $39.9 million and $102.9 million on open contracts for the six months ended June 30, 2013 and 2012, respectively.

During the first six months of 2012, the Company entered into arrangements to settle or re-price a portion of its existing derivative instruments ahead of their respective expiration dates. The Company realized $136.8 million of losses related to these early extinguishments. The cash payments for the early extinguishment of these derivative instruments were deferred at the time of settlement. In August 2012, the Company paid $92 million related to these early settlements with the proceeds from the IPO (see Note 3). The remainder of these losses began to come due beginning in September 2012 and end in January 2014. The early extinguishments were treated as a current period loss as of the date of extinguishment. Interest accrues on the deferred loss liabilities at a weighted average interest rate of 7.1%. Interest expense related to these liabilities was $0.2 million and $0.6 million for the three months ended June 30, 2013 and 2012, respectively and $0.5 million and $1.0 million for the six months ended June 30, 2013 and 2012, respectively. The deferred payment obligations related to these early extinguishment losses are included in the June 30, 2013 balance sheet as $9.4 million within current liabilities. At December 31, 2012, these deferred payment obligations are included in the balance sheet as $28.9 million within current liabilities and $0.9 million in long-term liabilities under the accrued liabilities and other liabilities captions, respectively.

The following table summarizes the fair value amounts of the Company’s outstanding derivative instruments by location on the balance sheet as of June 30, 2013 and December 31, 2012:

(in millions)	Balance Sheet Classification	June 30, 2013			December 31, 2012
Commodity swaps and futures	Other current assets	$	5.1		$	2.1
Commodity swaps and futures	Derivative liability		(6.8	)		(43.7	)
Net liability position		$	(1.7	)	$	(41.6	)

The Company is exposed to credit risk in the event of nonperformance by its counterparty on these derivative instruments. The counterparties are large financial institutions with credit ratings of at least BBB by Standard and Poor’s and A3 by Moody’s. In the event of default, the Company would potentially be subject to losses on a derivative instrument’s mark-to-market gains. The Company does not expect nonperformance on any of its derivative instruments.

The Company is not subject to any margin calls for these crack spread derivatives and the counterparty does not have the right to demand collateral.

12. DEBT

During the year ended December 31, 2012, the Company redeemed the $290 million outstanding of its 10.50% Senior Secured Notes due December 1, 2017 (“2017 Secured Notes”), completed a $275 million private placement of its 7.125% Senior Secured Notes due November 15, 2020 (“2020 Secured Notes”) and amended its $300 million secured asset-based revolving credit facility established at inception (“Initial ABL Facility”). The 2017 Senior Secured Notes and Initial ABL Facility were entered into in connection with the Marathon Acquisition.

2020 Secured Notes

On November 8, 2012, NTE LLC privately placed $275 million in aggregate principal amount of 7.125% senior secured notes due 2020. The 2020 Secured Notes were guaranteed, jointly and severally, on a senior secured basis by all of the Company’s existing and future direct and indirect subsidiaries; however, not on a full and unconditional basis as a result of subsidiaries being able to be released as guarantors under certain customary circumstances for such arrangements. A subsidiary guarantee can be released under customary circumstances, including (a) the sale of the subsidiary, (b) the subsidiary is declared “unrestricted,” (c) the legal or covenant defeasance or satisfaction and discharge of the indenture, or (d) liquidation or dissolution of the subsidiary. 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. 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.

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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 stock, to purchase, redeem or otherwise acquire or retire our equity interests, to make certain investments, loans and advances, to sell, lease or transfer any of our property or assets, to merge, consolidate, lease or sell substantially all of the Company’s assets, to suffer a change of control and to enter into new lines of business.

ABL Facility

On July 17, 2012, the Company entered into an amendment of its Initial ABL Facility. The amendment to the Initial ABL Facility (the “Amended ABL Facility”) is a $300 million secured asset-based revolving credit facility. The amendment, among other things, (i) changed the amount by which the aggregate principal amount of the revolving credit facility can be increased from $100 million to $150 million for a maximum aggregate principal amount of $450 million subject to borrowing base availability and lender approval, (ii) reduced the rates at which borrowings under the revolving credit facility bear interest, and (iii) extended the maturity of the revolving credit facility from December 1, 2015 to July 17, 2017. The amendment to the revolving credit facility removed the requirement that the Company satisfy a pro forma minimum fixed charge coverage test in connection with consummating certain transactions, including the making of certain Restricted Payments and Permitted Payments (each as defined in the Amended ABL Facility).

In connection with the removal of this requirement, the Amended ABL Facility also revised the springing financial covenant to provide that, if the amount available under the revolving credit facility is less than the greater of (i) 12.5% (changed from 15%) 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 Amended ABL Facility) of at least 1.0 to 1.0. Other covenants that were common to both the Initial ABL Facility and the Amended ABL Facility 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 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 Amended ABL Facility bear interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and1.50%) 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, 2013, the borrowing base under the Amended ABL Facility was $242.3 million and availability under the Amended ABL Facility was $192.1 million (which is net of $50.2 million in outstanding letters of credit). The Company had no borrowings under the Amended ABL Facility at June 30, 2013 or December 31, 2012.

13. EQUITY

Initial Public Offering

As discussed in Note 3, concurrent with the closing of the NTE LP IPO, NT Holdings contributed its membership interests in NTE LLC to NTE LP in exchange for 54,844,500 common units and 18,383,000 PIK common units. Additionally, NTE LP issued 18,687,500 common units to the public for total common units outstanding as of the IPO of 91,915,000, all of which represent limited partnership interests in NTE LP. NT Holdings is also the sole member in Northern Tier Energy GP LLC, the non-economic general partner of NTE LP.

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Additionally, during the six months ended June 30, 2013, NT Holdings completed two secondary public offerings of 26,105,000 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 the Company’s units to the public by NT Holdings are incurred by the Company. During the six months ended June 30, 2013, the Company incurred $0.9 million of offering costs from these secondary offerings.

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 Company’s general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the Company’s general partner 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.

The following table details the distributions paid during the six months ended June 30, 2013 (in millions, except per unit amounts):

Date Declared	Date Paid	Common Units		Distribution per common unit		Total Distribution
February 11, 2013	February 28, 2013		91.9	$	1.27	$	116.7
May 13, 2013	May 30, 2013		92.2	$	1.23	$	113.4

On August 12, 2013, the Company declared a quarterly distribution of $0.68 per unit to common unitholders of record on August 22, 2013, payable on August 29, 2013. This distribution of approximately $63 million in aggregate is based on available cash generated during the three months ended June 30, 2013.

Earnings per Unit

The following tables illustrate the computation of basic and diluted earnings per unit for the three and six months ended June 30, 2013.

	For the three months ended June 30, 2013
	Income		Units		Per-Unit
(in millions, except unit and per-unit data)	(Numerator)		(Denominator)		Amounts
Basic EPS
Net income available to common unitholders	$	63.9		91,915,000	$	0.70
Effect of Dilutive Securities
Contingently issuable performance based awards		—		16,829
Diluted EPS
Net income available to common unitholders plus assumed conversions	$	63.9		91,931,829	$	0.70
	For the six months ended June 30, 2013
	Income		Units		Per-Unit
(in millions, except unit and per-unit data)	(Numerator)		(Denominator)		Amounts
Basic EPS
Net income available to common unitholders	$	183.3		91,915,000	$	1.99
Effect of Dilutive Securities
Contingently issuable performance based awards		—		19,960
Diluted EPS
Net income available to common unitholders plus assumed conversions	$	183.3		91,934,960	$	1.99

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Diluted earnings per unit for both the three and six months ended June 30, 2013 include contingently issuable unit awards granted to certain members of management in the second quarter of 2013 (see Note 16). These awards are in form of restricted units and are contingent upon the completion of service and, in certain cases, upon the Company’s achievement of certain performance targets. The number of units ultimately issued under the performance based grants will depend on actual results. As of June 30, 2013, the Company has included the dilutive impact of awards where the completion of a requisite service period and the achievement of a performance target are considered probable.

14. 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.

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

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The following table provides the assets and liabilities carried at fair value measured on a recurring basis at June 30, 2013 and December 31, 2012:

(in millions)	Balance at June 30, 2013		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Unobservable inputs (Level 3)
ASSETS
Cash and cash equivalents	$	98.5	$	98.5	$	—	$	—
Other current assets
Derivative asset—current		5.1		—		5.1		—
	$	103.6	$	98.5	$	5.1	$	—
LIABILITIES
Derivative liability—current	$	6.8	$	—	$	6.8	$	—
	$	6.8	$	—	$	6.8	$	—
(in millions)	Balance at December 31, 2012		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Unobservable inputs (Level 3)
ASSETS
Cash and cash equivalents	$	272.9	$	272.9	$	—	$	—
Other current assets
Derivative asset—current		2.1		—		2.1		—
	$	275.0	$	272.9	$	2.1	$	—
LIABILITIES
Derivative liability—current	$	43.7	$	—	$	43.7	$	—
	$	43.7	$	—	$	43.7	$	—

As of June 30, 2013 and December 31, 2012, the Company had no Level 3 fair value assets or liabilities. During the third quarter of 2012 and in conjunction with the NTE LP IPO, the Company terminated the contingent consideration arrangements (margin support and earn-out) with MPC and settled all outstanding assets and liabilities by paying MPC $40 million in cash and by NT Holdings issuing a $45 million perpetual payment in kind preferred interest in NT Holdings to MPC.

Prior to the settlement, the Company determined the fair value of its contingent consideration arrangements based on a probability-weighted income approach derived from financial performance estimates. The impacts of changes in the fair value of these arrangements were recorded in the statements of operations as contingent consideration (loss) income. During the six months ended June 30, 2012, the Company recorded a $65.8 million loss related to changes in the fair value of its contingent consideration arrangements. These contingent consideration arrangements were reported at fair value using Level 3 inputs due to such arrangements not having observable market prices. The fair value of the arrangements was determined based on a Monte Carlo simulation prepared by a third party service provider using management projections of future period EBITDA levels.

The significant unobservable inputs used in the fair value measurement of the Company’s Level 3 arrangements were management projections of EBITDA. In developing these management projections, the Company used the forward market prices for various crude oil types, other feedstocks and refined products and applied its historical operating performance metrics against those forward market prices to develop its projected future EBITDA. Significant increases (decreases) in the projected future EBITDA levels would have resulted in significantly higher (lower) fair value measurements.

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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 both the three and six months ended June 30, 2013 and 2012, 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, 2013				December 31, 2012
	Carrying		Fair		Carrying		Fair
(in millions)	Amount		Value		Amount		Value
2020 Secured Notes	$	275.0	$	280.8	$	275.0	$	282.9

15. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:

	Six Months Ended
(in millions)	June 30, 2013		June 30, 2012
Asset retirement obligation balance at beginning of period	$	1.9	$	1.5
Revisions of previous estimates		—		0.3
Accretion expense		0.1		0.2
Asset retirement obligation balance at end of period	$	2.0	$	2.0

16. EQUITY-BASED COMPENSATION

The Company and its affiliates maintain two distinct equity-based compensation plans designed to encourage employees and directors of the Company and its affiliates to achieve superior performance. The initial plan (the “NT Investor Plan”) is sponsored by members of NT Investors, the parent company of NT Holdings, and granted profit unit interests in NT Investors. The second plan is maintained by the general partner of NTE LP and is referred to as the 2012 Long-Term Incentive Plan (“LTIP”). All equity-based compensation expense related to both plans is recognized by the Company.

LTIP

Approximately 9.2 million NTE LP common units are reserved for issuance under the LTIP. The LTIP was created concurrent with NTE LP’s IPO and permits the award of unit options, restricted units, phantom units, unit appreciation rights and other awards that derive their value from the market price of NTE LP’s common units. As of June 30, 2013, approximately 0.3 million units were outstanding under the LTIP, all of which were restricted units. The Company recognizes the expense on these restricted units ratably from the grant date until all units become unrestricted.

During the second quarter of 2013, the Company granted contingently issuable unit awards under the LTIP to certain members of management. These LTIP awards are in form of restricted units and are contingent upon the Company’s achievement of a “cash available for distribution” target (as defined in the award agreement) for the twelve months ended December 31, 2013. The number of units ultimately issued under these grants can fluctuate above or below the target units (as defined in the award agreement) depending on actual cash available for distribution during 2013. As of June 30, 2013, the Company estimates that it will achieve its target.

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A summary of the LTIP unit activity is set forth below:

	Number of			Weighted		Weighted
	LTIP units			Average Grant		Average Term
	(in thousands)			Date Price		Until Maturity
Outstanding at December 31, 2012		6.1		$	25.69		3.0
Awarded		284.0			27.23		3.4
Cancelled		(2.8	)		28.28		2.8
Outstanding at June 30, 2013		287.3		$	27.19		3.3

As of June 30, 2013 and December 31, 2012, the total unrecognized compensation cost for LTIP restricted units was $6.6 million and $0.2 million, respectively.

NT Investor Plan

The NT Investor Plan is an equity participation plan which provides 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 shall not be less than 100% of the fair market value of NT Investors equity units on the date of grant. Profit interest units 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 will accelerate. Continued employment in any subsidiary of NT Investors is a condition of vesting and, as such, compensation expense is recognized in the Company’s financial statements based upon the fair value of the award on the date of grant. This compensation expense is a non-cash expense of the Company. The NT Investor Plan awards are satisfied by cash distributions made to NT Holdings and will 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 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 (loss). No further awards are planned to be issued from the NT Investor Plan.

17. DEFINED BENEFIT PLANS

Cash Balance Plan

During 2011, the Company initiated a defined benefit cash balance pension plan (the “Cash Balance Plan”) for eligible employees. Company contributions are made to the individual account of the participants equal to 5.0% of eligible compensation. Participants’ individual 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 the three months ended June 30, 2013 and 2012 was $0.5 million and $0.4 million, respectively, and for the six months ended June 30, 2013 and 2012 was $1.0 million and $0.8 million, respectively. These costs related primarily to current period service costs.

Retiree Medical Plan

During 2012, the Company began to sponsor 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, inclusive of years of service with Marathon, 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 and six months ended June 30, 2013 was $0.2 million and $0.3 million, respectively, related primarily to current period and prior service costs.

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18. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:

	Six Months Ended
	June 30,		June 30,
(in millions)	2013		2012
Net cash from operating activities included:
Interest paid	$	13.1	$	16.7
Income taxes paid		0.4		—
Noncash investing and financing activities include:
Capital expenditures included in accounts payable		1.6		1.3

19. LEASING ARRANGEMENTS

As described in Note 5, concurrent with the Marathon Acquisition, certain Marathon assets (including real property interests and land related to 130 of the SuperAmerica convenience stores and the SuperMom’s bakery) were sold to a third party equity real estate investment trust. In connection with the closing of the Marathon Acquisition, the Company has assumed the leasing of these properties from the real estate investment trust on a long-term basis.

In accordance with ASC Topic 840-40 “Sale Leaseback Transactions,” the Company determined that subsequent to the sale, it had a continuing involvement for a portion of these property interests due to potential environmental obligations or due to subleasing arrangements. For these respective properties, the fair value of the assets and the related financing obligation will remain on the Company’s consolidated balance sheet until the end of the lease term or until the continuing involvement is resolved. The assets are included in property, plant and equipment and are being depreciated over their remaining useful lives. The lease payments relating to these property interests are recognized as interest expense. Subsequent to the initial transaction, the Company’s continuing involvement ended for a subset of these stores and, as such, the related fair value of the assets and the financing obligation for these stores have been removed from the Company’s consolidated balance sheet.

The remainder of properties sold to the third party real estate investment trust are treated as operating leases. The Company also leases a variety of facilities and equipment under other operating leases, including land and building space, office equipment, vehicles, rail tracks for storage of rail tank cars near the refinery and numerous rail tank cars.

20. 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. However, management believes that the Company will remain a viable and competitive enterprise even though it is possible that these contingencies could be resolved unfavorably.

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, 2013 and December 31, 2012, liabilities for remediation totaled $1.4 million and $3.0 million, respectively. These liabilities are expected to be settled over at least the next 10 years. It is not presently possible to estimate the ultimate amount of all remediation costs that might be incurred or the penalties that may be imposed. Furthermore, environmental remediation costs may vary from estimates because of changes in laws, regulations and their interpretation; additional information on the extent and nature of site contamination; and improvements in technology. 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 $0.3 million at both June 30, 2013 and December 31, 2012.

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.

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Guarantees

Certain agreements related to assets sold in the normal course of business contain performance and general guarantees, including guarantees regarding inaccuracies in representations, warranties, covenants and agreements, and environmental and general indemnifications that require the Company to perform upon the occurrence of a triggering event or condition. These guarantees and indemnifications were part of the normal course of selling assets. The Company has assumed these guarantees and indemnifications upon the Marathon Acquisition. However, in certain cases, MPC LP has also provided an indemnification in favor of the Company.

The Company is not typically able to calculate the maximum potential amount of future payments that could be made under such contractual provisions because of the variability inherent in the guarantees and indemnities. Most often, the nature of the guarantees and indemnities is such that there is no appropriate method for quantifying the exposure because the Company has little or no past experience associated with the underlying triggering event upon which a reasonable prediction of the outcome can be based. The Company is not currently making any payments relating to such guarantees or indemnifications.

21. 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 and related assets, and includes the Company’s interest in NTOT, MPL and MPLI, and

• Retail – operates 163 convenience stores primarily in Minnesota and Wisconsin. The retail segment also includes the operations of NTB and SAF.

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

(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	$	48.1	$	8.0	$	(8.5	)	$	47.6
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)
Three months ended June 30, 2012	Refining		Retail		Other			Total
Revenues
Customer	$	775.6	$	379.6	$	—		$	1,155.2
Intersegment		263.6		—		—			263.6
Segment revenues		1,039.2		379.6		—			1,418.8
Elimination of intersegment revenues		—		—		(263.6	)		(263.6	)
Total revenues	$	1,039.2	$	379.6	$	(263.6	)	$	1,155.2
Income (loss) from operations	$	235.1	$	4.8	$	(15.2	)	$	224.7
Income from equity method investment	$	3.0	$	—	$	—		$	3.0
Depreciation and amortization	$	6.1	$	1.6	$	0.1		$	7.8
Capital expenditures	$	5.8	$	0.7	$	0.5		$	7.0

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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	$	189.9	$	8.6	$	(19.0	)	$	179.5
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
(in millions)
Six months ended June 30, 2012	Refining		Retail		Other			Total
Revenues
Customer	$	1,430.1	$	724.2	$	—		$	2,154.3
Intersegment		503.6		—		—			503.6
Segment revenues		1,933.7		724.2		—			2,657.9
Elimination of intersegment revenues		—		—		(503.6	)		(503.6	)
Total revenues	$	1,933.7	$	724.2	$	(503.6	)	$	2,154.3
Income (loss) from operations	$	313.6	$	4.0	$	(90.2	)	$	227.4
Income from equity method investment	$	5.9	$	—	$	—		$	5.9
Depreciation and amortization	$	12.1	$	3.8	$	0.4		$	16.3
Capital expenditures	$	10.7	$	1.0	$	0.7		$	12.4

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, 2013	$	825.6	$	141.6	$	118.1	$	1,085.3
At December 31, 2012	$	706.1	$	134.7	$	296.0	$	1,136.8

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.

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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 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. Please see “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent downstream energy company with refining, retail and pipeline operations that serve 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, 2013, we had total revenues of $2.2 billion, operating income of $179.5 million, net income of $183.3 million and Adjusted EBITDA of $242.5 million. A definition and reconciliation of Adjusted EBITDA to net income (loss) is included herein under the caption “Adjusted EBITDA.”

Refining Business

Our refining business primarily consists of a refinery located in St. Paul Park, Minnesota. During the three months ended June 30, 2013, we completed a capacity expansion project on one of our crude units at the refinery and increased our capacity levels to 89,500 barrels per calendar day, or 92,500 barrels per stream day, compared to our prior capacity levels of 81,500 barrels per calendar day, or 84,500 barrels per stream day. Our refinery has an estimated complexity index of 11.5, which refers to a measure of a refinery’s ability to process lower cost crude oils into higher value light refined products. Our refinery’s complexity allows us to process a variety of light, heavy, sweet and sour crudes, many of which have historically priced at a discount to the NYMEX WTI price benchmark, meaning we can process lower cost crude oils into higher value refined products.

We are one of only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the PADD II region. The PADD II region covers the following states: 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 oils 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 and a Mississippi River dock. Beginning in December 2012, we initiated a crude oil transportation business in North Dakota to allow us to purchase crude oil at the wellhead in the Bakken Shale while limiting the impact of rising trucking costs for crude oil in North Dakota. Our refining business also includes our 17% interest in Minnesota Pipe Line Company, LLC (“MPL”), which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

As of June 30, 2013, our retail business operated 163 convenience stores under the SuperAmerica brand and also supported 73 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 other merchandise such as beverages, prepared food and a large variety of snacks and prepackaged items. Our refinery supplies substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores.

We also own and operate SuperMom’s Bakery, which prepares and distributes baked goods and other prepared food items for sale in our 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,
	June 30,			June 30,			June 30,			June 30,
(in millions)	2013			2012			2013			2012
Revenue	$	1,131.2		$	1,155.2		$	2,246.2		$	2,154.3
Costs, expenses and other:
Cost of sales		965.0			825.0			1,844.5			1,664.8
Direct operating expenses		62.1			61.5			126.4			122.2
Turnaround and related expenses		27.3			11.5			37.0			15.0
Depreciation and amortization		9.4			7.8			18.0			16.3
Selling, general and administrative		20.9			24.8			46.4			45.1
Formation and offering costs		0.5			1.0			0.9			1.0
Contingent consideration loss		—			0.1			—			65.8
Other income, net		(1.6	)		(1.2	)		(6.5	)		(3.3	)
Operating income		47.6			224.7			179.5			227.4
Realized losses from derivative activities		(3.1	)		(67.4	)		(20.5	)		(120.3	)
Loss on early extinguishment of derivatives		—			(92.2	)		—			(136.8	)
Unrealized gains from derivative activities		28.7			191.3			39.9			102.9
Interest expense, net		(6.3	)		(10.7	)		(12.7	)		(21.1	)
Income before income taxes		66.9			245.7			186.2			52.1
Income tax provision		(3.0	)		(0.1	)		(2.9	)		(0.1	)
Net income	$	63.9		$	245.6		$	183.3		$	52.0

Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

Revenue. Revenue for the three months ended June 30, 2013 was $1,131.2 million compared to $1,155.2 million for the three months ended June 30, 2012, a decrease of 2.1%. Refining segment revenue decreased 2.3% and retail segment revenue decreased 0.4% compared to the three months ended June 30, 2012. The refining segment experienced a 23.0% decrease in sales volumes of refined products versus the 2012 period due to planned downtime resulting from a major plant turnaround and a crude expansion project during the 2013 second quarter that lowered refining throughput. This decrease in refined product revenue was partially offset by a $198.7 million increase in crude oil revenues within the refining segment in the 2013 period. These crude oil revenues relate to the sale of crude barrels (often accompanied by a repurchase) with the objective of optimizing our crude slate in a given period. Retail revenue was impacted by lower merchandise sales partially offset by slightly higher fuel sales from the prior-year period. Excise taxes included in revenue totaled $71.1 million and $71.2 million for the three months ended June 30, 2013 and 2012, respectively.

Cost of sales. Cost of sales totaled $965.0 million for the three months ended June 30, 2013 compared to $825.0 million for the three months ended June 30, 2012, an increase of 17.0%, primarily due to higher crude oil costs in the 2013 period and an increase of $199.1 million related to crude oil sales. Excise taxes included in cost of sales were $71.1 million and $71.2 million for the three months ended June 30, 2013 and 2012, respectively.

Direct operating expenses. Direct operating expenses totaled $62.1 million for the three months ended June 30, 2013 compared to $61.5 million for the three months ended June 30, 2012, an increase of 1.0%, due primarily to higher catalyst and employee related costs within our refining segment in the second quarter of 2013.

Turnaround and related expenses. Turnaround and related expenses totaled $27.3 million for the three months ended June 30, 2013 compared to $11.5 million for the three months ended June 30, 2012, an increase of $15.8 million. 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. The turnaround costs in the three months ended June 30, 2012 relate to a partial turnaround of the alkylation unit, which was completed in mid-May 2012.

Depreciation and amortization. Depreciation and amortization was $9.4 million for the three months ended June 30, 2013 compared to $7.8 million for the three months ended June 30, 2012, an increase of 20.5%. This increase was primarily due to depreciation of assets placed in service since June 30, 2012 primarily related to our refinery.

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Selling, general and administrative expenses. Selling, general and administrative expenses were $20.9 million for the three months ended June 30, 2013 compared to $24.8 million for the three months ended June 30, 2012. This decrease of $3.9 million from the prior year period relates primarily to lower employee related and risk management costs in the three months ended June 30, 2013.

Formation and offering costs. Formation and offering costs for the three months ended June 30, 2013 were $0.5 million versus $1.0 million for the three months ended June 30, 2012. All of the costs from the 2013 period are attributable to offering costs for sales of common units by Northern Tier Holdings LLC. The costs in the 2012 period relate to costs incurred in anticipation of our initial public offering in July 2012 that did not meet the accounting requirements for deferral.

Contingent consideration loss. Contingent consideration loss was $0.1 million for the three months ended June 30, 2012. The contingent consideration loss relates to the margin support and earn-out agreements entered into with Marathon in connection with the Marathon Acquisition. The contingent consideration loss in the 2012 period relates to changes in the financial performance estimates as of June 30, 2012 for the then remaining period of performance. The margin support and earn-out agreements were settled during the third quarter of 2012 and, as such, there is no contingent consideration loss in the second quarter of 2013.

Other income, net. Other income, net was $1.6 million for the three months ended June 30, 2013 compared to $1.2 million for the three months ended June 30, 2012. The increase from the prior year is primarily due to a $1.8 million charge in the 2012 period for management fees paid to ACON Refining Partners L.L.C. and TPG Refining L.P. that did not reoccur in 2013. This decline is partially offset by lower equity income from our investment in MPL, which had experienced reduced throughput volumes in the second quarter of 2013, due in part to our turnaround and capital expansion activities.

Gains (losses) from derivative activities. For the three months ended June 30, 2013, we had realized losses of $3.1 million related to settled contracts compared to $67.4 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We had unrealized gains on outstanding derivatives of $28.7 million for the three months ended June 30, 2013 compared to $191.3 million during the three months ended June 30, 2012. These derivatives were entered into to partially hedge the crack spreads for our refining business. In addition to these losses, during the three months ended June 30, 2012, we entered into arrangements to settle a portion of our then existing derivative instruments ahead of their respective expiration dates and incurred $92.2 million of realized losses related to these early extinguishments.

Interest expense, net. Interest expense, net was $6.3 million for the three months ended June 30, 2013 and $10.7 million for the three months ended June 30, 2012. These interest charges relate primarily to our outstanding senior secured notes as well as commitment fees and interest on the ABL facility and the amortization of deferred financing costs. The decrease from the prior-year quarter is primarily due to the reduced principal and interest rate inherent in our new senior secured notes entered into during the fourth quarter of 2012.

Income tax expense. The income tax expense for the three months ended June 30, 2013 was $3.0 million compared to $0.1 million for the three months ended June 30, 2012. Prior to July 31, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on July 31, 2012, our retail business became a tax paying entity for federal and state income taxes.

Net income. Our net income was $63.9 million for the three months ended June 30, 2013 compared to $245.6 million for the three months ended June 30, 2012. This reduction of $181.7 million was primarily attributable to a $187.0 million decrease in operating income for our refining segment due to less favorable refining gross margins, lower sales volumes as a result of planned downtime and higher turnaround costs in the second quarter of 2013 offset by lower corporate expenses and interest expense.

Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

Revenue. Revenue for the six months ended June 30, 2013 was $2,246.2 million compared to $2,154.3 million for the six months ended June 30, 2012, an increase of 4.3%. Refining segment revenue increased 5.2% and retail segment revenue decreased 0.4% compared to the six months ended June 30, 2012. The increase in refining revenue is primarily due to a $262.3 million increase in crude oil revenues in the 2013 period, partially offset by an 8.7% decrease in sales volumes of refined products versus the 2012 period. These crude oil revenues relate to the sale of crude barrels (often accompanied by a repurchase) with the objective of optimizing our crude slate in a given period. The lower refined product volumes in the 2013 period are primarily attributable to planned downtime resulting from the turnaround and capacity expansion activities at our St. Paul Park refinery in the second quarter of 2013 that reduced refining throughput. Retail revenue was impacted by lower merchandise sales partially offset by slightly higher fuel sales from the prior-year period. Excise taxes included in revenue totaled $141.9 million and $136.8 million for the six months ended June 30, 2013 and 2012, respectively.

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Cost of sales. Cost of sales totaled $1,844.5 million for the six months ended June 30, 2013 compared to $1,664.8 million for the six months ended June 30, 2012, an increase of 10.8%, due primarily to higher crude oil costs in the 2013 period and an increase of $262.4 million related to crude oil sales in our refining segment. Excise taxes included in cost of sales were $141.9 million and $136.8 million for the six months ended June 30, 2013 and 2012, respectively.

Direct operating expenses. Direct operating expenses totaled $126.4 million for the six months ended June 30, 2013 compared to $122.2 million for the six months ended June 30, 2012, an increase of 3.4%, due primarily to higher catalyst and employee related costs within our refining segment in the 2013 period.

Turnaround and related expenses. Turnaround and related expenses totaled $37.0 million for the six months ended June 30, 2013 compared to $15.0 million for the six months ended June 30, 2012, an increase of $22.0 million. The turnaround costs in the six months ended June 30, 2013 relate to the costs of a planned major plant turnaround which lasted the entire month of April 2013. The turnaround costs in the six months ended June 30, 2012 relate to a partial turnaround of the alkylation unit, which was completed in mid-May 2012.

Depreciation and amortization. Depreciation and amortization was $18.0 million for the six months ended June 30, 2013 compared to $16.3 million for the six months ended June 30, 2012, an increase of 10.4%. This increase was primarily due to depreciation of assets placed in service since June 30, 2012 primarily related to our refinery.

Selling, general and administrative expenses. Selling, general and administrative expenses were $46.4 million for the six months ended June 30, 2013 compared to $45.1 million for the six months ended June 30, 2012. This increase of $1.3 million from the prior year period relates primarily to a $5.3 million non-cash charge for equity compensation as a result of the accelerated vesting of equity-based awards under our NT Investor Plan in the first quarter of 2013 partially offset by lower employee related and risk management costs in the 2013 period.

Formation and offering costs. Formation and offering costs for the six months ended June 30, 2013 were $0.9 million compared to $1.0 million for the three months ended June 30, 2012. All of the costs from the 2013 period are attributable to offering costs for sales of common units by Northern Tier Holdings LLC. The costs in the 2012 period relate to costs incurred in anticipation of our initial public offering in July 2012 that did not meet the accounting requirements for deferral.

Contingent consideration loss. Contingent consideration loss was $65.8 million for the six months ended June 30, 2012. The contingent consideration loss relates to the margin support and earn-out agreements entered into with Marathon in connection with the Marathon Acquisition. The contingent consideration loss in the 2012 period relates to changes in the financial performance estimates as of June 30, 2012 for the then remaining period of performance. The margin support and earn-out agreements were settled during the third quarter of 2012 and, as such, there is no contingent consideration loss in the first six months of 2013.

Other income, net. Other income, net was $6.5 million for the six months ended June 30, 2013 compared to $3.3 million for the six months ended June 30, 2012. This change is driven primarily by $1.8 million of miscellaneous income related to a non-recurring settlement from an indemnification arrangement and a $1.8 million charge in the 2012 period for management fees paid to ACON Refining Partners L.L.C. and TPG Refining L.P. that did not reoccur in 2013.

Gains (losses) from derivative activities. For the six months ended June 30, 2013, we had realized losses of $20.5 million related to settled contracts compared to $120.3 million in the prior-year period. Offsetting benefits related to these losses were recognized through improved operating margins. We had unrealized gains on outstanding derivatives of $39.9 million for the six months ended June 30, 2013 compared to $102.9 million of unrealized losses during the six months ended June 30, 2012. These derivatives were entered into to partially hedge the crack spreads for our refining business. In addition to these losses, during the six months ended June 30, 2012, we entered into arrangements to settle a portion of our then existing derivative instruments ahead of their respective expiration dates and incurred $136.8 million of realized losses related to these early extinguishments.

Interest expense, net. Interest expense, net was $12.7 million for the six months ended June 30, 2013 and $21.1 million for the six months ended June 30, 2012. These interest charges relate primarily to our outstanding senior secured notes as well as commitment fees and interest on the ABL facility and the amortization of deferred financing costs. The decrease from the prior-year period is primarily due to the reduced principal and interest rate inherent in our new senior secured notes entered into during the fourth quarter of 2012.

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Income tax expense. The income tax expense for the six months ended June 30, 2013 was $2.9 million compared to $0.1 million for the six months ended June 30, 2012. Prior to July 31, 2012, we operated as a pass-through entity for federal tax purposes and, as such, only state taxes were recognized. Effective on July 31, 2012, our retail business became a tax paying entity for federal and state income taxes.

Net income. Our net income was $183.3 million for the six months ended June 30, 2013 compared to $52.0 million for the six months ended June 30, 2012. This improvement of $131.3 million was primarily attributable to an improvement of $173.6 million related to derivatives losses, $8.4 million of lower interest expense and $65.8 million of contingent consideration loss occurring in the 2012 period offset by a $123.7 million reduction in operating income for our refining segment due to less favorable refining gross margins, lower sales volumes and higher turnaround costs in the 2013 period.

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, 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	$	894.0	$	70.7	$	0.3		$	965.0
Intersegment purchases		—		261.8		(261.8	)		—
Segment cost of sales	$	894.0	$	332.5	$	(261.5	)	$	965.0

	Three Months Ended June 30, 2012
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	775.6	$	379.6	$	—		$	1,155.2
Intersegment sales		263.6		—		(263.6	)		—
Segment revenue	$	1,039.2	$	379.6	$	(263.6	)	$	1,155.2
Cost of sales:
Cost of sales	$	751.5	$	73.5	$	—		$	825.0
Intersegment purchases		—		263.6		(263.6	)		—
Segment cost of sales	$	751.5	$	337.1	$	(263.6	)	$	825.0

	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	$	1,714.3	$	130.1	$	0.1		$	1,844.5
Intersegment purchases		—		508.6		(508.6	)		—
Segment cost of sales	$	1,714.3	$	638.7	$	(508.5	)	$	1,844.5

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	Six Months Ended June 30, 2012
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	1,430.1	$	724.2	$	—		$	2,154.3
Intersegment sales		503.6		—		(503.6	)		—
Segment revenue	$	1,933.7	$	724.2	$	(503.6	)	$	2,154.3
Cost of sales:
Cost of sales	$	1,523.5	$	141.3	$	—		$	1,664.8
Intersegment purchases		—		503.6		(503.6	)		—
Segment cost of sales	$	1,523.5	$	644.9	$	(503.6	)	$	1,664.8

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Refining Segment

	Three Months Ended,						Six Months Ended,
	June 30,			June 30,			June 30,			June 30,
(in millions)	2013			2012			2013			2012
Revenue	$	1,014.8		$	1,039.2		$	2,033.4		$	1,933.7
Costs, expenses and other:
Cost of sales		894.0			751.5			1,714.3			1,523.5
Direct operating expenses		34.3			31.7			71.9			63.0
Turnaround and related expenses		27.3			11.5			37.0			15.0
Depreciation and amortization		7.5			6.1			14.2			12.1
Selling, general and administrative		5.5			6.4			11.4			12.5
Other income, net		(1.9	)		(3.1	)		(5.3	)		(6.0	)
Operating income	$	48.1		$	235.1		$	189.9		$	313.6
Key Operating Statistics
Total refinery production (bpd) (1)		55,594			82,069			70,752			79,253
Total refinery throughput (bpd)		55,486			81,906			70,343			78,659
Refined products sold (bpd) (2)		68,395			88,773			76,499			83,348
Per barrel of throughput:
Refining gross product margin (3)	$	23.92		$	38.60		$	25.06		$	28.65
Direct operating expenses (4)	$	6.79		$	4.25		$	5.65		$	4.40
Per barrel of refined products sold:
Refining gross product margin (3)	$	19.41		$	35.61		$	23.05		$	27.04
Direct operating expenses (4)	$	5.51		$	3.92		$	5.19		$	4.15
Refinery product yields (bpd):
Gasoline		26,715			38,186			33,816			38,544
Distillate (5)		19,093			26,742			23,848			25,451
Asphalt		6,212			12,455			8,408			10,389
Other (6)		3,574			4,686			4,680			4,869
Total		55,594			82,069			70,752			79,253
Refinery throughput (bpd):
Crude oil		54,524			80,796			68,654			77,020
Other feedstocks (7)		962			1,110			1,689			1,639
Total		55,486			81,906			70,343			78,659
Crude oil by type (bpd):
Light crude		32,466			44,666			37,149			45,713
Synthetic crude		9,449			13,337			14,134			12,473
Heavy crude		12,609			22,793			17,371			18,834
Total		54,524			80,796			68,654			77,020
Market Statistics:
Crude Oil Average Pricing:
West Texas Intermediate ($/barrel)	$	95.35		$	93.35		$	94.76		$	98.15
PADD II / Group 3 Average Pricing:
Unleaded 87 Gasoline ($/barrel)	$	120.27		$	120.53		$	119.15		$	121.11
Ultra Low Sulfur Diesel ($/barrel)	$	123.34		$	123.64		$	126.80		$	127.30

29

(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 per barrel of throughput 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 this calculation (revenues and cost of sales) can be reconciled directly to our statement 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. See “Other Non-GAAP Performance Measures” below.

(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 refining 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 refining 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 refining throughput.

Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

Revenue. Revenue for the three months ended June 30, 2013 was $1,014.8 million compared to $1,039.2 million for the three months ended June 30, 2012, a decrease of 2.3%. This decrease was primarily due to a 23.0% decrease in sales volumes of refined products versus the 2012 period due to planned downtime resulting from a major plant turnaround and a crude expansion project that both lowered refining throughput during the 2013 second quarter. This decrease in refined product revenue was partially offset by a $198.7 million increase in crude oil revenues in the 2013 period. These crude oil revenues relate to the sale of crude barrels (often accompanied by a repurchase) with the objective of optimizing our crude slate in a given period. Excise taxes included in revenue were $68.7 million and $68.8 million for the three months ended June 30, 2013 and 2012, respectively.

Cost of sales. Cost of sales totaled $894.0 million for the three months ended June 30, 2013 compared to $751.5 million for the three months ended June 30, 2012, a 19.0% increase. This increase was primarily due to higher crude costs in the 2013 period and an increase of $199.1 million related to crude oil sales. Excise taxes included in cost of sales were $68.7 million and $68.8 million for the three months ended June 30, 2013 and 2012, respectively. Refining gross product margin per barrel of throughput was $23.92 for the three months ended June 30, 2013 compared to $38.60 for the three months ended June 30, 2012, a decrease of $14.68, or 38.0%, which is primarily attributable to lower market crack spreads and less favorable differentials per barrel for our crude costs and refined product prices in the second quarter of 2013.

Direct operating expenses. Direct operating expenses totaled $34.3 million for the three months ended June 30, 2013 compared to $31.7 million for the three months ended June 30, 2012, an 8.2% increase. This increase was due primarily to higher catalyst and employee related costs in the second quarter of 2013.

Turnaround and related expenses. Turnaround and related expenses totaled $27.3 million for the three months ended June 30, 2013 compared to $11.5 million for the three months ended June 30, 2012, an increase of $15.8 million. 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. The turnaround costs in the three months ended June 30, 2012 relate to a partial turnaround of the alkylation unit, which was completed in mid-May 2012.

Depreciation and amortization. Depreciation and amortization was $7.5 million for the three months ended June 30, 2013 compared to $6.1 million for the three months ended June 30, 2012, an increase of 23.0%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since June 30, 2012.

Selling, general and administrative expenses. Selling, general and administrative expenses were $5.5 million and $6.4 million for the three months ended June 30, 2013 and 2012, respectively, a decrease of 14.1%. This decrease was primarily due to lower employee related costs in the second quarter of 2013.

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Other income, net. Other income, net was $1.9 million for the three months ended June 30, 2013 compared to $3.1 million for the three months ended June 30, 2012. This decrease is driven primarily by lower equity income from our investment in MPL, which had experienced reduced throughput volumes in the second quarter of 2013, partially due to our turnaround and capacity expansion activities.

Operating income. Income from operations was $48.1 million for the three months ended June 30, 2013 compared to $235.1 million for the three months ended June 30, 2012. This decrease from the prior-year period is primarily due to less favorable gross margins per throughput barrel, lower throughput rates due to the turnaround and capacity expansion projects and higher turnaround costs in the 2013 period.

Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

Revenue. Revenue for the six months ended June 30, 2013 was $2,033.4 million compared to $1,933.7 million for the six months ended June 30, 2012, an increase of 5.2%. This increase is primarily due to a $262.3 million increase in crude oil revenues in the 2013 period, partially offset by an 8.7% decrease in sales volumes of refined products versus the 2012 period. These crude oil revenues relate to the sale of crude barrels (often accompanied by a repurchase) with the objective of optimizing our crude slate in a given period. The lower refined product volumes in the 2013 period are primarily attributable to planned downtime resulting from the turnaround and capacity expansion activities at our St. Paul Park refinery in the second quarter of 2013 that reduced refining throughput. Excise taxes included in revenue were $137.4 million and $132.3 million for the six months ended June 30, 2013 and 2012, respectively.

Cost of sales. Cost of sales totaled $1,714.3 million for the six months ended June 30, 2013 compared to $1,523.5 million for the six months ended June 30, 2012, a 12.5% increase. This increase was primarily due to higher crude costs in the 2013 period and an increase of $262.4 million related to crude oil sales. Excise taxes included in cost of sales were $137.4 million and $132.3 million for the six months ended June 30, 2013 and 2012, respectively. Refining gross product margin per barrel of throughput was $25.06 for the six months ended June 30, 2013 compared to $28.65 for the six months ended June 30, 2012, a decrease of $3.59, or 12.5%, which is primarily attributable to lower market crack spreads and less favorable differentials per barrel for our crude costs and refined product prices in the 2013 period.

Direct operating expenses. Direct operating expenses totaled $71.9 million for the six months ended June 30, 2013 compared to $63.0 million for the six months ended June 30, 2012, a 14.1% increase. This increase was due primarily to higher catalyst and employee related costs in the 2013 period.

Turnaround and related expenses. Turnaround and related expenses totaled $37.0 million for the six months ended June 30, 2013 compared to $15.0 million for the six months ended June 30, 2012, an increase of $22.0 million. The turnaround costs in the six months ended June 30, 2013 relate to the costs of a planned major plant turnaround which lasted for the entire month of April 2013. The turnaround costs in the six months ended June 30, 2012 relate to a partial turnaround of the alkylation unit, which was completed in mid-May 2012.

Depreciation and amortization. Depreciation and amortization was $14.2 million for the six months ended June 30, 2013 compared to $12.1 million for the six months ended June 30, 2012, an increase of 17.4%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since June 30, 2012.

Selling, general and administrative expenses. Selling, general and administrative expenses were $11.4 million and $12.5 million for the six months ended June 30, 2013 and 2012, respectively, a decrease of 8.8%. This decrease was primarily due to lower employee related costs in the 2013 period.

Other income, net. Other income, net was $5.3 million for the six months ended June 30, 2013 compared to $6.0 million for the six months ended June 30, 2012. This decrease is driven primarily by lower equity income from our investment in MPL, which had experienced reduced throughput volumes in the second quarter of 2013, partially due to our turnaround and capital expansion activities.

Operating income. Income from operations was $189.9 million for the six months ended June 30, 2013 compared to $313.6 million for the six months ended June 30, 2012. This decrease from the prior-year period is primarily due to less favorable gross margins per throughput barrel, lower throughput rates due to the turnaround and capacity expansion projects and higher turnaround expenses in the 2013 period.

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Retail Segment

	Three Months Ended,						Six Months Ended,
(in millions)	June 30, 2013			June 30, 2012			June 30, 2013			June 30, 2012
Revenue	$	378.2		$	379.6		$	721.4		$	724.2
Costs, expenses and other:
Cost of sales		332.5			337.1			638.7			644.9
Direct operating expenses		29.6			29.8			57.9			59.2
Depreciation and amortization		1.8			1.6			3.6			3.8
Selling, general and administrative		6.3			6.3			12.6			12.3
Operating income	$	8.0		$	4.8		$	8.6		$	4.0
Operating data:
Company-owned stores:
Fuel gallons sold (in millions)		77.0			77.5			151.6			151.6
Fuel margin per gallon (1)	$	0.23		$	0.22		$	0.20		$	0.20
Merchandise sales (in millions)	$	86.0		$	90.7		$	161.8		$	169.6
Merchandise margin % (2)		27.0	%		24.9	%		27.2	%		25.3	%
Number of stores at period end		163			166			163			166
Franchisee stores:
Fuel gallons sold (in millions)		10.3			11.2			21.3			22.0
Royalty income (in millions)	$	0.6		$	0.5		$	1.2		$	1.0
Number of stores at period end		73			67			73			67
Market Statistics:
PADD II gasoline prices ($/gallon)	$	3.72		$	3.70		$	3.63		$	3.64

(1) Retail fuel margin per gallon is calculated by dividing retail fuel gross margin by the fuel gallons sold at company-operated stores. Retail fuel gross margin is a non-GAAP performance measure that we believe is important to investors in evaluating our retail performance. Our calculation of retail fuel gross margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. See “Other Non-GAAP Performance Measures” below.

(2) 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. 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. See “Other Non-GAAP Performance Measures” below.

Three Months Ended June 30, 2013 Compared to the Three Months Ended June 30, 2012

Revenue. Revenue for the three months ended June 30, 2013 was $378.2 million compared to $379.6 million for the three months ended June 30, 2012, a decrease of 0.4%. This decrease was primarily due to lower merchandise sales partially offset by slightly higher fuel revenues in the 2013 period. Excise taxes included in revenue were $2.4 million for both the three months ended June 30, 2013 and 2012.

Cost of sales. Cost of sales totaled $332.5 million for the three months ended June 30, 2013 and $337.1 million for the three months ended June 30, 2012, a decrease of 1.4% primarily due to lower merchandise sales. Excise taxes included in cost of sales were $2.4 million for both the three months ended June 30, 2013 and 2012. For company-operated stores, retail fuel margin per gallon was $0.23 and $0.22 for the three months ended June 30, 2013 and 2012, respectively.

Direct operating expenses. Direct operating expenses totaled $29.6 million for the three months ended June 30, 2013 compared to $29.8 million for the three months ended June 30, 2012, a decrease of 0.7% from the 2012 period as a result of focused cost controls in our retail stores.

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Depreciation and amortization. Depreciation and amortization was $1.8 million and $1.6 million for the three months ended June 30, 2013 and 2012, respectively. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since June 30, 2012.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.3 million for both the three months ended June 30, 2013 and 2012.

Operating income. Operating income was $8.0 million for the three months ended June 30, 2013 compared to $4.8 million for the three months ended June 30, 2012, an improvement of $3.2 million. This improvement is primarily attributable to improved merchandise and fuel margins and lower direct operating expenses in the 2013 period.

Six Months Ended June 30, 2013 Compared to the Six Months Ended June 30, 2012

Revenue. Revenue for the six months ended June 30, 2013 was $721.4 million compared to $724.2 million for the six months ended June 30, 2012, a decrease of 0.4%. This decrease was primarily due to lower merchandise sales partially offset by slightly higher fuel revenues in the 2013 period. Excise taxes included in revenue were $4.5 million for both the six months ended June 30, 2013 and 2012.

Cost of sales. Cost of sales totaled $638.7 million for the six months ended June 30, 2013 and $644.9 million for the six months ended June 30, 2012, a decrease of 1.0% primarily due to lower merchandise sales. Excise taxes included in cost of sales were $4.5 million for both the six months ended June 30, 2013 and 2012. For company-operated stores, retail fuel margin per gallon was $0.20 for both the six months ended June 30, 2013 and 2012.

Direct operating expenses. Direct operating expenses totaled $57.9 million for the six months ended June 30, 2013 compared to $59.2 million for the six months ended June 30, 2012, a decrease of 2.2% from the 2012 period as a result of focused cost controls in our retail stores.

Depreciation and amortization. Depreciation and amortization was fairly consistent at $3.6 million and $3.8 million for the six months ended June 30, 2013 and 2012, respectively.

Selling, general and administrative expenses. Selling, general and administrative expenses were $12.6 million and $12.3 million for the six months ended June 30, 2013 and 2012, respectively, which represents an increase of $0.3 million from the 2012 period. This increase primarily relates to higher shared service costs allocated to the retail segment in the first quarter of 2013.

Operating income. Operating income was $8.6 million for the six months ended June 30, 2013 compared to $4.0 million for the six months ended June 30, 2012, an improvement of $4.6 million. This improvement is primarily attributable to lower direct operating expenses and higher merchandise margins in the 2013 period.

33

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 Amended ABL Facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the 2020 Secured Notes, the Amended ABL Facility, earn-out, margin support and management services. Adjusted EBITDA should not be considered as an alternative to operating income or net income (loss) 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, contingent consideration, formation and offering costs and adjustments to reflect proportionate EBITDA from the Minnesota Pipeline operations. Other companies, including other 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 realized and unrealized gains and losses from hedging activities, which may have a substantial impact on our cash flow;

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

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

The following tables reconcile net income (loss) as reflected in the results of operations tables and segment footnote disclosures to Adjusted EBITDA for the periods presented:

	Three Months Ended June 30, 2013
(in millions)	Refining		Retail		Other			Total
Net income	$	48.1	$	8.0	$	7.8		$	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		55.6		9.8		17.2			82.6
Minnesota Pipe Line proportionate EBITDA		0.7		—		—			0.7
Turnaround and related expenses		27.3		—		—			27.3
Equity-based compensation expense		—		—		0.4			0.4
Unrealized gains on derivative activities		—		—		(28.7	)		(28.7	)
Formation and offering costs		—		—		0.5			0.5
Realized losses on derivative activities		—		—		3.1			3.1
Adjusted EBITDA	$	83.6	$	9.8	$	(7.5	)	$	85.9

34

	Three Months Ended June 30, 2012
(in millions)	Refining		Retail		Other			Total
Net income	$	235.1	$	4.8	$	5.7		$	245.6
Adjustments:
Interest expense		—		—		10.7			10.7
Income tax provision		—		—		0.1			0.1
Depreciation and amortization		6.1		1.6		0.1			7.8
EBITDA subtotal		241.2		6.4		16.6			264.2
Minnesota Pipe Line proportionate EBITDA		0.7		—		—			0.7
Turnaround and related expenses		11.5		—		—			11.5
Equity-based compensation expense		—		—		0.5			0.5
Unrealized gains on derivative activities		—		—		(191.3	)		(191.3	)
Contingent consideration loss		—		—		0.1			0.1
Loss on early extinguishment of derivatives		—		—		92.2			92.2
Formation and offering costs		—		—		1.0			1.0
Realized losses on derivative activities		—		—		67.4			67.4
Adjusted EBITDA	$	253.4	$	6.4	$	(13.5	)	$	246.3
	Six Months Ended June 30, 2013
(in millions)	Refining		Retail		Other			Total
Net income (loss)	$	189.9	$	8.6	$	(15.2	)	$	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		204.1		12.2		0.6			216.9
Minnesota Pipe Line proportionate EBITDA		1.4		—		—			1.4
Turnaround and related expenses		37.0		—		—			37.0
Equity-based compensation expense		—		—		5.7			5.7
Unrealized gains on derivative activities		—		—		(39.9	)		(39.9	)
Formation and offering costs		—		—		0.9			0.9
Realized losses on derivative activities		—		—		20.5			20.5
Adjusted EBITDA	$	242.5	$	12.2	$	(12.2	)	$	242.5

35

	Six Months Ended June 30, 2012
(in millions)	Refining		Retail		Other			Total
Net income (loss)	$	313.6	$	4.0	$	(265.6	)	$	52.0
Adjustments:
Interest expense		—		—		21.1			21.1
Income tax provision		—		—		0.1			0.1
Depreciation and amortization		12.1		3.8		0.4			16.3
EBITDA subtotal		325.7		7.8		(244.0	)		89.5
Minnesota Pipe Line proportionate EBITDA		1.4		—		—			1.4
Turnaround and related expenses		15.0		—		—			15.0
Equity-based compensation expense		—		—		0.9			0.9
Unrealized gains on derivative activities		—		—		(102.9	)		(102.9	)
Contingent consideration loss		—		—		65.8			65.8
Formation and offering costs		—		—		1.0			1.0
Loss on early extinguishment of derivatives		—		—		136.8			136.8
Realized losses on derivative activities		—		—		120.3			120.3
Adjusted EBITDA	$	342.1	$	7.8	$	(22.1	)	$	327.8

Other Non-GAAP Performance Measures

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

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

The following table shows the reconciliation of refining gross product margin to refining revenue for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended,				Six Months Ended,
(in millions)	June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Refining revenue	$	1,014.8	$	1,039.2	$	2,033.4	$	1,933.7
Refining cost of sales		894.0		751.5		1,714.3		1,523.5
Refining gross product margin	$	120.8	$	287.7	$	319.1	$	410.2
Throughput (barrels)		5.0		7.5		12.7		14.3
Refining gross product margin per barrel of throughput	$	23.92	$	38.60	$	25.06	$	28.65

Retail fuel gross 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 retail fuel gross margin and merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.

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The following table shows the reconciliation of retail gross margin to retail segment operating income for the three and six months ended June 30, 2013 and 2012:

	Three Months Ended,				Six Months Ended,
(in millions)	June 30, 2013		June 30, 2012		June 30, 2013		June 30, 2012
Retail gross margin:
Fuel margin	$	17.7	$	17.1	$	30.3	$	30.3
Merchandise margin		23.2		22.6		44.0		42.9
Other margin		4.8		2.8		8.4		6.1
Retail gross margin		45.7		42.5		82.7		79.3
Expenses:
Direct operating expenses		29.6		29.8		57.9		59.2
Depreciation and amortization		1.8		1.6		3.6		3.8
Selling, general and administrative		6.3		6.3		12.6		12.3
Retail segment operating income	$	8.0	$	4.8	$	8.6	$	4.0

Liquidity and Capital Resources

Our primary sources of liquidity have traditionally been cash generated from our operating activities and the borrowing availability under our Amended 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. Part of our long-term strategy is to increase cash available for distribution to our unitholders by making strategic acquisitions. Our ability to make these acquisitions in the future will depend largely on the availability of debt financing and on our ability to periodically use equity financing through the issuance of new common units. Future financing will depend on various factors, including prevailing market conditions, interest rates and our financial condition and credit rating.

As of June 30, 2013, we had $275 million of outstanding aggregate principal of our 7.125% senior secured notes due 2020 and had no outstanding balance under our Amended ABL Facility. As of June 30, 2013, the borrowing base under the Amended ABL Facility was $242.3 million and availability under the Amended ABL Facility was $192.1 million (which is net of $50.2 million in outstanding letters of credit).

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 expenditure, debt service and other cash requirements for at least the next twelve months.

We may use a variety of hedging instruments to enhance the stability of our cash flows. In general, we attempt to hedge 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. During the first quarter of 2012, we agreed to settle a portion of our existing derivative instruments ahead of their respective expiration dates and recognized a $44.6 million loss related to the early extinguishment. In addition, during the second quarter of 2012, we reset the price of our contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92.2 million. We used $92 million of the net proceeds of the IPO to settle a portion of these obligations relating to the early extinguishment and price reset. The remaining obligation will be settled via monthly payments continuing through January 2014. As of June 30, 2013, $9.4 million of the remaining liability related to these actions is included in current liabilities with the final amount to be paid in January 2014.

Pursuant to the Energy Policy Act of 2005 and the Energy Independence and Securing Act of 2007, the U.S. Environmental Protection Agency (“EPA”) has issued Renewable Fuels Standards (“RFS”) implementing mandates to blend renewable fuels into petroleum fuels produced and sold in the United States. We are subject to RFS. Under the RFS, the EPA establishes a volume of renewable fuels that obligated refineries must blend into their finished petroleum fuels. The obligated volume increases annually over time until 2022. Our refinery currently does not generate enough renewable identification number credits (“RINs”) to meet the current year requirement for some fuel categories, so we must purchase RINs on the open market for these categories. We project we will need to purchase between 25 and 35 million RINs on the open market for a total cost of between $20 and $30 million in 2013.

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Cash Flows

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

	Six Months Ended,
(in millions)	June 30, 2013			June 30, 2012
Net cash provided by operating activities	$	124.1		$	99.9
Net cash used in investing activities		(68.4	)		(12.4	)
Net cash used in financing activities		(230.1	)		(40.0	)
Net (decrease) increase in cash and cash equivalents		(174.4	)		47.5
Cash and cash equivalents at beginning of period		272.9			123.5
Cash and cash equivalents at end of period	$	98.5		$	171.0

Net Cash Provided By Operating Activities. 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), unrealized gains from derivative activities ($39.9 million and other non-cash expenses ($6.9 million). Offsetting these impacts were increases in working capital accounts totaling ($42.2 million).

Net cash provided by operating activities for the six months ended June 30, 2012 was $99.9 million. The most significant providers of cash were our net income ($52.0 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($16.3 million), loss on early retirement of derivatives ($136.8 million) and non-cash contingent consideration loss ($65.8 million). Offsetting these impacts were unrealized gains from derivative activities ($102.9 million), increases in accounts receivable ($57.4 million) and decreases in accounts payable and accrued expenses ($27.8 million).

Net Cash Used In Investing Activities. 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.

Net cash used in investing activities for the six months ended June 30, 2012 was $12.4 million, relating primarily to capital expenditures ($12.4 million).

Net Cash Used In Financing Activities. Net cash used in financing activities for the six months ended June 30, 2013 was $230.1 million, representing our distribution to unitholders in the first six months of 2013 for cash generated by us during our fourth quarter of 2012 and first quarter of 2013.

Net cash used in financing activities for the six months ended June 30, 2012 was $40.0 million, relating to an equity distribution to NT Holdings in the second quarter of 2012.

Working Capital

Working capital at June 30, 2013 was $155.7 million, consisting of $497.7 million in total current assets and $342.0 million in total current liabilities.

Capital Spending

Capital spending was $69.3 million for the six months ended June 30, 2013, of which approximately $45 million of discretionary capital spending was incurred primarily for expansion projects to improve our refinery capacity and light product yield. The maintenance capital spending of approximately $24 million for the six months ended June 30, 2013 related primarily to safety related enhancements, facility improvements and meeting regulatory requirements at the refinery.

We currently expect to spend approximately $50 to $60 million for non-discretionary capital projects in 2013, including approximately $20 to $30 million to upgrade our waste water treatment facility. The remaining non-discretionary projects relate to the ongoing replacement spending also referred to as maintenance capital. We also expect to spend approximately $40 to $50 million on discretionary projects which we estimate will have a payback of less than eighteen months.

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Distribution Policy

NTE LP expects within 60 days after the end of each quarter, to make cash distributions to unitholders of record on the applicable record date. Distributions will be equal to the amount of available cash that we generate in such quarter. Available cash for each quarter will generally equal our cash flow from operations for the quarter excluding working capital changes, less cash required for maintenance capital expenditures, reimbursement of expenses incurred by our general partner and its affiliates, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of NTE LP’s general partner deems necessary or appropriate, including reserves for our turnaround and related expenses. The amount of our quarterly distributions, if any, will vary based on our operating cash flow during such quarter. As a result, our 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) our operating performance, (ii) cash flows caused by, among other things, fluctuations in the prices of crude oil and other feedstocks and the prices we receive for finished products, (iii) our 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 our 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.

On February 11, 2013, NTE LP declared a quarterly distribution of $1.27 per unit to common unitholders of record on February 21, 2013. This distribution of $117 million in aggregate is based on available cash generated during the fourth quarter of 2012.

On May 13, 2013, NTE LP declared a quarterly distribution of $1.23 per unit to common unitholders of record on May 21, 2013. This distribution of $113 million in aggregate is based on available cash generated during the first quarter of 2013

On August 12, 2013, NTE LP declared a quarterly distribution of $0.68 per unit to common unitholders of record on August 20, 2013. This distribution of $63 million in aggregate is based on available cash generated during the second quarter of 2013.

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Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to 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 attempt to hedge 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., refining 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 refining gross product margin, based on our average refining throughput for the six months ended June 30, 2013 of 70,343 bpd, would result in a change of $25.7 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 hedging policy, we may seek to reduce the volatility of our cash flows by hedging an operationally reasonable volume of our gasoline and diesel. We may enter into hedging 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 J.P. Morgan Commodities Canada Corporation (“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 related to crude oil price volatility.

Basis Risk

The effectiveness of our derivative 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 may lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the pricing in our market.

Commodities Price and Basis Risk Management Activities

We have entered into hedge 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 hedge our crack spread risk with respect to significant percentages of the refinery’s projected monthly production of some or all of these refined products. As of June 30, 2013, we have hedged approximately two and a half million barrels of future gasoline and diesel production under commodity derivatives contracts that are either exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the form of commodity price swaps that reference benchmark indices such as NYMEX or U.S. Gulf Coast.

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Our open positions at June 30, 2013 will expire at various times during 2013. Based on our open positions of two and half million barrels, a $1.00 per barrel change in quoted market prices of our derivative instruments, assuming all other factors remain constant, could change the fair value of our derivative instruments and our net income (loss) by approximately $2.5 million.

We may enter into additional futures derivatives 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 percentages of production, we intend to hedge significantly less than that amount on an ongoing basis. We may use commodity derivatives contracts such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of the identified risks; however, it is our plan to hedge a lesser amount of production than we historically have in order to 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, 2013, the availability under the Amended ABL Facility was $192.1 million. This availability is net of $50.2 million in outstanding letters of credit. We had no borrowings under the Amended ABL Facility at June 30, 2013. Borrowings under the Amended ABL Facility bear interest, at our option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.00% and 1.50%) or (b) a LIBOR rate plus 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, we are also required to pay an annual commitment fee ranging from 0.375% to 0.500% and letter of credit fees. See Note 12 – “Debt,” to the unaudited consolidated financial statements included herein.

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 could potentially 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 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.

As required by Rule 13a-15(b) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), NTE LP has evaluated, under the supervision and with the participation of their respective management, including its principal executive officers and principal financial officers, the effectiveness of the design and operation of their disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by NTE LP in reports that it files or submits under the Exchange Act is accumulated and communicated to its management, including their principal executive officers and principal financial officers, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the Securities and Exchange Commission. Based upon the evaluation, our principal executive officers and principal financial officers have concluded that the disclosure controls and procedures were effective as of June 30, 2013 at the reasonable assurance level.

Changes in Internal Control Over Financial Reporting

There were no changes in the internal control over financial reporting for NTE LP (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the three months ended June 30, 2013 that have materially affected, or are reasonably likely to materially affect, NTE LP’s internal control over financial reporting.

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

None.

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 2012 Annual Report on Form 10-K, as supplemented by the risk factor below, and 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 Prospectus. These risks are not the only risks that we face. Additional risks and uncertainties not currently known to us or that we currently deem to be immaterial also may materially adversely affect our business, financial condition or results of operations.

The cost to purchase credits to comply with renewable fuel mandates have seen significant increases in 2013, and future costs to purchase such credits could have a material adverse effect on our results of operations and financial condition, and our ability to make distributions to our unitholders.

As previously discussed, we are subject to the RFS, which requires obligated parties to blend renewable fuels, such as ethanol, into petroleum fuels sold in the United States. One RIN is generated for each gallon of renewable fuel produced under the RFS. At the end of each year, obligated parties must surrender sufficient RINs to meet their renewable fuel obligations under the RFS. Our refinery currently does not generate enough RINS to meet the current year requirement for some fuel categories, so we must purchase RINS on the open market for these categories. Between December 31, 2012 and July 30, 2013, the price of conventional ethanol RINs has risen from approximately $0.07 per RIN to above $1.00 per RIN, representing a marked increase in compliance costs for obligated parties. The price of RINS has been unusually volatile in 2013, and such volatility could continue into 2014 as well. The costs to obtain RIN credits going forward could be material.

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

None.

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 13, 2013	By:	/s/ Hank Kuchta
		Hank Kuchta
		Chief Executive Officer and Director of
		Northern Tier Energy GP LLC
		(Principal Executive Officer and Duly Authorized Officer)
Date August 13, 2013	By:	/s/ David Bonczek
		David Bonczek
		Vice President and Chief Financial Officer of
		Northern Tier Energy GP LLC
		(Principal Financial Officer and Duly Authorized Officer)

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EXHIBIT INDEX

Exhibit Number	Description
3.1*	Certificate of Limited Partnership of Northern Tier Energy LP (Incorporated by reference to Exhibit 3.1 of Amendment No. 4 to Northern Tier Energy LP’s Registration Statement on Form S-1 (File No. 333-178457) filed on July 18, 2012).
3.2*	First Amended and Restated Agreement of Limited Partnership of Northern Tier Energy LP, dated July 31, 2012 (Incorporated by reference to Exhibit 3.1 of Northern Tier Energy LP’s Current Report on Form 8-K filed on August 2, 2012).
4.1*	Amended and Restated Registration Rights Agreement, dated July 31, 2012, by and among TPG Refining, L.P., ACON Refining Partners, L.L.C., NTI Management Company, L.P., NTR Partners LLC, NTR Partners II LLC, Northern Tier Investors, LLC, Northern Tier Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 4.1 of Northern Tier Energy LP’s Current Report on Form 8-K filed on August 2, 2012).
4.2*	Indenture, dated as of November 8, 2012, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, Northern Tier Energy LP, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.1 of Northern Tier Energy LLC’s Current Report on Form 8-K dated November 8, 2012).
10.1*	Settlement Agreement and Release dated May 4, 2012, by and between Marathon Petroleum Company LP and Northern Tier Energy LLC (Incorporated by reference to Exhibit 10.14 to Amendment No. 2 to Northern Tier Energy LP’s Registration Statement on Form S-1 (File No. 333-178457) filed on May 4, 2012).
10.2*	First Amendment to the Credit Agreement, dated as of July 17, 2012, by and among the financial institutions party thereto, as the lenders, J.P. Morgan Chase Bank, N.A., as administrative agent and collateral agent, Bank of America, N.A., as syndication agent, and Macquarie Capital (USA) Inc. and SunTrust Bank, as co-documentation agents, and Northern Tier Energy LLC and certain subsidiaries of Northern Tier Energy LLC party thereto (Incorporated by reference to Exhibit 10.13 to Amendment No. 6 to Northern Tier Energy LP’s Registration Statement on Form S-1 (File No. 333-178457) filed on July 18, 2012).
10.3*	Transaction Agreement, dated July 25, 2012, by and among Northern Tier Holdings LLC, Northern Tier Energy GP LLC, Northern Tier Energy LLC, Northern Tier Energy Holdings LLC, Northern Tier Retail Holdings LLC and Northern Tier Energy LP (Incorporated by reference to Exhibit 10.1 to Northern Tier Energy LP’s Current Report on Form 8-K filed on July 30, 2012).
10.4*	Northern Tier Energy LP 2012 Long-Term Incentive Plan (Incorporated by reference to Northern Tier Energy LP’s Current Report on Form 8-K filed on July 30, 2012).
31.1	Certification of Hank Kuchta, Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP.
31.2	Certification of David Bonczek, Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP.
32.1**	Certification pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) of Hank Kuchta, Chief Executive Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP.
32.2**	Certification pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) of David Bonczek, Chief Financial Officer of Northern Tier Energy GP LLC, the general partner of Northern Tier Energy LP.
101.INS**	XBRL Instance Document.
101.SCH**	XBRL Taxonomy Extension Schema Document.
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document.

* Previously filed.

** Furnished, not filed.

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