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, 2012

¨	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 333-178458

Northern Tier Energy LLC

(Exact name of registrant as specified in its charter)


DELAWARE		27-3005162
(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 office)		(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. ¨ Yes x 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. (Check one):

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

NORTHERN TIER ENERGY LLC

QUARTERLY REPORT ON FORM 10-Q

FOR THE THREE AND SIX MONTHS ENDED JUNE 30, 2012

TABLE OF CONTENTS


CAUTIONARY NOTE REGARDING FORWARD LOOKING STATEMENTS

PART 1. FINANCIAL INFORMATION			4
	ITEM 1.	Financial Statements	4
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
	ITEM 3.	Quantitative and Qualitative Disclosures about Market Risk	37
	ITEM 4.	Controls and Procedures	39
PART II – OTHER INFORMATION
	ITEM 1.	Legal Proceedings	39
	ITEM 1A.	Risk Factors	39
	ITEM 6.	Exhibits	39

SIGNATURES			40

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

Certain statements and information in this Quarterly Report on Form 10-Q 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 to fund expansions, acquisitions and our working capital needs and our ability to obtain debt or equity financing on satisfactory terms;

•

currently unknown liabilities in connection with the Marathon Acquisition (as defined herein);

•

environmental liabilities or events that are not covered by an indemnity, insurance or existing reserves;

•

dependence on one principal supplier for 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 Wall Street Reform and Consumer Protection 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; and

•

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

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 (2) “Risk Factors” in our final prospectus, dated May 14, 2012 (the “Prospectus),” included in our Registration Statement on Form S-4 (File No. 333-178458) and (3) our Quarterly Report on Form 10-Q for the period ended March 31, 2012, filed on June 28, 2012.

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.

Item 1.

Financial Statements

NORTHERN TIER ENERGY LLC

CONSOLIDATED BALANCE SHEETS

(in millions)


	June 30, 2012			December 31, 2011
	(Unaudited)
ASSETS

CURRENT ASSETS
Cash and cash equivalents	$	171.0		$	123.5
Receivables, less allowance for doubtful accounts		139.0			81.9
Inventories		150.1			154.1
Other current assets		68.0			65.5

Total current assets		528.1			425.0

NON-CURRENT ASSETS
Equity method investment		90.1			89.9
Property, plant and equipment, net		388.7			391.2
Intangible assets		35.4			35.4
Other assets		39.3			57.3


Total Assets	$	1,081.6		$	998.8


LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	171.4		$	207.4
Accrued liabilities		199.7			30.3
Derivative liability		20.4			109.9

Total current liabilities		391.5			347.6

NON-CURRENT LIABILITIES
Long-term debt		290.0			290.0
Lease financing obligation		12.7			11.9
Other liabilities		61.3			37.1

Total liabilities		755.5			686.6


Commitments and contingencies

EQUITY
Comprehensive loss		(0.4	)		(0.4	)
Member’s interest		326.5			312.6

Total Liabilities and Equity	$	1,081.6		$	998.8

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

NORTHERN TIER ENERGY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)

(in millions, unaudited)


	Three Months Ended						Six Months Ended
	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

REVENUE ^(a)	$	1,155.2		$	1,092.3		$	2,154.3		$	2,032.5

COSTS, EXPENSES AND OTHER
Cost of sales ^(a)		825.0			909.0			1,664.8			1,688.0
Direct operating expenses		61.5			63.3			122.2			125.2
Turnaround and related expenses		11.5			19.2			15.0			22.5
Depreciation and amortization		7.8			7.6			16.3			14.9
Selling, general and administrative		24.8			20.5			45.1			38.9
Formation costs		—			1.9			—			4.4
Contingent consideration loss (income)		0.1			(9.2	)		65.8			(41.0	)
Other income, net		(1.2	)		(0.7	)		(3.3	)		(1.8	)


OPERATING INCOME		225.7			80.7			228.4			181.4

Realized losses from derivative activities		(67.4	)		(81.7	)		(120.3	)		(133.9	)
Loss on early extinguishment of derivatives		(92.2	)		—			(136.8	)		—
Unrealized gains (losses) from derivative activities		191.3			(31.0	)		102.9			(293.9	)
Interest expense, net		(10.7	)		(10.2	)		(21.1	)		(20.2	)


INCOME (LOSS) BEFORE INCOME TAXES		246.7			(42.2	)		53.1			(266.6	)

Income tax (provision) benefit		(0.1	)		0.1			(0.1	)		—


NET INCOME (LOSS) AND COMPREHENSIVE INCOME (LOSS)	$	246.6		$	(42.1	)	$	53.0		$	(266.6	)


^(a) Excise taxes included in revenue and cost of sales	$	71.2		$	59.9		$	136.8		$	116.6

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

NORTHERN TIER ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions, unaudited)


	Six Months Ended
	June 30,			June 30,
Increase (decrease) in cash	2012			2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net income (loss)	$	53.0		$	(266.6	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		16.3			14.9
Non-cash interest expense		2.4			2.0
Equity-based compensation expense		0.9			0.7
Equity method investment, net		(0.3	)		—
Contingent consideration loss (income)		65.8			(41.0	)
Unrealized (gains) losses from derivative activities		(102.9	)		293.9
Loss on early extinguishment of derivatives		136.8			—
Changes in assets and liabilities, net:
Accounts receivable		(57.4	)		(3.6	)
Inventories		4.0			3.5
Other current assets		13.4			22.1
Accounts payable and accrued expenses		(27.8	)		108.0
Other, net		(4.3	)		(0.1	)

Net cash provided by operating activities		99.9			133.8


CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(12.4	)		(16.1	)
Acquisition, net of cash acquired		—			(112.8	)
Return of capital from investments		—			0.2

Net cash used in investing activities		(12.4	)		(128.7	)


CASH FLOWS FROM FINANCING ACTIVITIES
Borrowings from revolving credit arrangement		—			20.0
Repayments of revolving credit arrangement		—			(20.0	)
Distributions to Member		(40.0	)		—

Net cash used in financing activities		(40.0	)		—


CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents		47.5			5.1
Cash and cash equivalents at beginning of period		123.5			72.8

Cash and cash equivalents at end of period	$	171.0		$	77.9

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

NORTHERN TIER ENERGY LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	DESCRIPTION OF THE BUSINESS AND BASIS OF PRESENTATION

Description of the Business

Northern Tier Energy LLC (“NTE” 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. The Company is a Delaware limited liability company and, as of and for the three and six month periods ended June 30, 2012 and 2011 (the “Reporting Period”), was a wholly owned subsidiary of Northern Tier Holdings LLC (“NT Holdings” or the “Member”). On July 31, 2012, NT Holdings contributed all of its membership interests in the Company to Northern Tier Energy LP (“NTE LP”) in connection with the closing of the underwritten initial public offering (“IPO”) of NTE LP (see Note 3). In December 2010, NT Holdings, a wholly owned subsidiary of Northern Tier Investors LLC (“NT Investors”), issued preferred stock that was solely owned by an indirect subsidiary of Marathon Petroleum Corporation (“Marathon Petroleum”). Marathon Petroleum was a wholly owned subsidiary of Marathon Oil Corporation (“Marathon Oil”) until June 30, 2011. NT Investors, NT Holdings and the Company were formed by ACON Refining Partners L.L.C. and 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. 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. Effective December 1, 2010, the Company acquired the business from Marathon for approximately $608 million (the “Marathon Acquisition”).

The Company includes the operations of the St. Paul Park Refining Co. LLC (“SPPR”) and Northern Tier Retail LLC (“NTR”). The Company also includes Northern Tier Bakery LLC (“NTB”), SuperAmerica Franchising LLC (“SAF”), a 17% interest in MPL Investments Inc. (“MPLI”) and a 17% interest in Minnesota Pipe Line Company, LLC (“Minnesota Pipe Line”). MPLI owns 100% of the preferred interest in Minnesota Pipe Line which owns and operates a 455,000 barrel per day (“bpd”) crude oil pipeline in Minnesota (see Note 2). In connection with the IPO of NTE LP (see Note 3), the Company contributed all of its membership interests in NTR and NTB to Northern Tier Retail Holdings LLC (“NTRH”) in exchange for all of the membership interests in NTRH.

SPPR, which is located in St. Paul Park, Minnesota, has total crude oil throughput capacity of 74,000 barrels per calendar day. Refinery 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.

NTR operates 166 convenience stores under the SuperAmerica brand. SAF supports 67 franchised stores which also utilize the SuperAmerica brand. The SuperAmerica stores are primarily located in Minnesota and Wisconsin and sell gasoline, merchandise, and in some locations, diesel fuel. There is a wide range of merchandise sold at the stores including prepared foods, beverages and non-food items. The merchandise sold includes a significant number of proprietary items.

NTB prepares and distributes food products under the SuperMom’s Bakery brand primarily to SuperAmerica branded retail outlets.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with 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, 2012 are not necessarily indicative of the results that may be expected for the year ending December 31, 2012, or for any other period.

The condensed consolidated balance sheet at December 31, 2011 has been derived from the audited financial statements of the Company at that date but does not include all of the information and footnotes required by GAAP for complete financial statements. The accompanying condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto included herein.

2.	SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation and Combination

Northern Tier Energy LLC was formed on June 23, 2010. The Marathon Acquisition agreement was entered into on October 6, 2010 and closed on December 1, 2010. Accordingly, the accompanying financial statements present the consolidated accounts of such acquired businesses. All significant intercompany accounts have been eliminated in these consolidated financial statements.

The Company’s common equity interest in Minnesota Pipe Line is accounted for using the equity method of accounting in accordance with Financial Accounting Standards Board’s (“FASB”) Accounting Standards Codification (“ASC”) Topic 323. Equity income from Minnesota Pipe Line represents the Company’s proportionate share of net income available to common equity owners generated by Minnesota Pipe Line.

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 investment.

MPLI owns all of the preferred membership units of Minnesota Pipe Line. This investment in MPLI, which provides the Company no significant influence over Minnesota Pipe Line, 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, 2012 and December 31, 2011 and is included in other noncurrent assets on 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. In addition, significant estimates were used in accounting for the Marathon Acquisition under the purchase method of accounting.

Operating Segments

The Company has two reportable operating segments:

•

Refining – operates the St. Paul Park, Minnesota, refinery, terminal and related assets, and includes the Company’s interest in MPLI and Minnesota Pipe Line, and

•

Retail – operates 166 convenience stores primarily in Minnesota and Wisconsin. The Retail segment also includes the operations of NTB and SAF.

See Note 20 for further information on the Company’s operating segments.

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.

When property, plant and equipment depreciated on an individual basis are sold or otherwise disposed of, any gains or losses are reported in net income. Gains on the disposal of property, plant and equipment are recognized when earned, which is generally at the time of closing. 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 option 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 of its contracts are accounted for by marking them to market and recognizing any resulting gains or losses in its statements of income. These gains and losses are reported within operating activities on 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 revenues and costs and expenses in the consolidated statements of operations. These taxes totaled $71.2 million and $59.9 million for the three months ended June 30, 2012 and 2011, respectively, and $136.8 million and $116.6 million for the six months ended June 30, 2012 and 2011, respectively.

Income Taxes

During the Reporting Period, the Company and its subsidiaries 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. In connection with the IPO of NTE LP and subsequent to June 30, 2012, certain subsidiaries of the Company became taxable entities for federal income tax purposes (see Note 3).

Reclassification

Certain reclassifications have been made to the prior year financial information in order to conform to the Company’s current presentation.

Accounting Developments

On January 1, 2012 we adopted Accounting Standard Update (“ASU”) No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income”, (“ASU 2011-05”) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Company must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. Also effective January 1, 2012, we adopted ASU 2011-12 Comprehensive Income (Topic 220): Deferral of the Effective Date for Amendments to the Presentation of Reclassifications of Items Out of Accumulated Other Comprehensive Income in Accounting Standards Update No. 2011-05 (“ASU 2011-12”). ASU 2011-12 defers the effectiveness for the requirement to present on the face of our financial statements the effects of reclassifications out of accumulated other comprehensive income on the components of net income and other comprehensive income. Our presentation of comprehensive income in this quarterly report complies with these accounting standards.

In December 2011, the FASB issued ASU No. 2011-11, “Disclosures about Offsetting Assets and Liabilities” (“ASU 2011-11”). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. This new guidance is to be applied retrospectively. ASU 2011-11 will be effective for the Company’s quarterly and annual financial statements beginning with our first quarter 2013 reporting. The Company believes that the adoption of ASU 2011-11 will not have a material impact on its consolidated financial statements.

In July 2012, the FASB issued ASU No. 2012-02, “Intangibles – Goodwill and other” (“ASU 2012-02”). ASU 2012-02 provides guidance on annual impairment testing of indefinite-lived intangible assets. The standards update allows an entity to first

assess qualitative factors to determine if it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount. If based on its qualitative assessment an entity concludes it is more likely than not that the fair value of an indefinite-lived intangible asset is less than its carrying amount, quantitative impairment testing is required. However, if an entity concludes otherwise, quantitative impairment testing is not required. The standards update is effective for annual and interim impairment tests performed for fiscal years beginning after September 15, 2012, with early adoption permitted. The Company believes that the adoption of ASU 2012-02 will not have a material impact on its consolidated financial statements.

3.	INITIAL PUBLIC OFFERING OF NORTHERN TIER ENERGY LP

On December 13, 2011, a Registration Statement on Form S-1 was filed with the U.S. Securities and Exchange Commission (“SEC”) relating to a proposed underwritten IPO of Northern Tier Energy, Inc. On June 4, 2012, Northern Tier Energy, Inc. was converted into NTE 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). On July 31, 2012, 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. NTE LP will use the net proceeds from the IPO of approximately $245 million, after deducting the underwriting discount, and cash on hand of $57 million to: (i) redeem $29 million of NTE senior secured notes at a redemption price of 103% of the principal amount thereof, for an estimated $30 million, (ii) pay $40 million to Marathon, which represents the cash component of a settlement agreement NTE entered into with Marathon that was part of the Marathon Acquisition, (iii) pay $92 million to J. Aron & Company, an affiliate of Goldman, Sachs & Co., related to deferred payment obligations from the early extinguishment of derivatives, (iv) pay offering costs of approximately $16 million; and, (v) distribute approximately $124 million to Northern Tier Holdings, of which approximately $92 million will be used to redeem Marathon’s existing preferred interest in Northern Tier Holdings and $32 million will be distributed to ACON Refining, TPG Refining and entities in which certain members of our management team hold an ownership interest.

In connection with the closing of the IPO the following transactions have occurred or will occur:

•

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 19);

•

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

•

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

•

NTE LP contributed 0.01% of its membership interests in NTE to Northern Tier Energy Holdings LLC (“NTEH”) in exchange for all of the membership interests in NTEH.

•

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

•

Northern Tier Retail Holdings LLC, a wholly-owned subsidiary of NTE that holds all of the ownership interests in NTR and NTB, through which the Company conduct its retail business, will elect to be treated as a corporation for federal income tax purposes, subjecting that subsidiary to corporate-level tax; and

•

NTEH will elect to be treated as a corporation for federal income tax purposes, subjecting that subsidiary to corporate-level tax. NTEH will not have any independent operations.

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. Minnesota Pipe Line 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 transactions with Minnesota Pipe Line.

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. 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 $0.5 million for the three months ended June 30, 2012 and 2011, respectively, and $2.2 million and $1.0 million for the six months ended June 30, 2012 and 2011, respectively. Subsequent to June 30, 2012, the management services agreement was terminated in conjunction with the IPO of NTE LP (see Note 3). As a result of the IPO, the Company was required to pay the Investors’ a specified success fee. This fee is approximately $6 million and is a part of the total offering costs referenced in Note 3.

As of June 30, 2012 the Company had a receivable of $6.3 million from NTE LP related to offering costs paid by the Company on behalf of NTE LP. These offering costs relate to NTE LP’s IPO that was completed subsequent to June 30, 2012 (see Note 3). This receivable is included in Other current assets within the consolidated balance sheet at June 30, 2012.

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 six months ended June 30, 2011.

The cash component of the purchase price along with acquisition related costs were financed by an approximate $180 million cash investment by the Investors and aggregate borrowings of $290 million. See Note 12 for a description of the Company’s financing arrangements.

Concurrent with the Marathon Acquisition, the following transactions also occurred:

•

Certain Marathon assets (including real property interests and land related to 135 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 is leasing these properties from the real estate investment trust on a long-term basis.

•

A third-party purchased substantially all of the crude oil inventory associated with operations of the refinery directly from Marathon.

Throughout the Reporting Period the Company would have been required to pay Marathon the earn-out payments if the Company’s Adjusted EBITDA (as defined in the agreement, the “Agreement Adjusted EBITDA”) exceeded $165 million less, among other things, any rental expense related to the real estate lease arrangement (described below) during any year in each of the eight years following the Marathon Acquisition. Marathon would have received 40% of the amount by which Agreement Adjusted EBITDA exceeded the specified threshold in any year during the eight year period not to exceed $125 million over the term. The Marathon Acquisition agreement also included a margin support component that would have required Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA was below $145 million less, among other things, any rental expense related to the real estate lease arrangement (described below), in either of the first two twelve month periods ending November 30, 2011 or 2012 up to a maximum of $60 million. Any such payments made by Marathon would have increased the amount that the Company would have been required to pay Marathon over the earn-out period (see Note 19).

On May 4, 2012, NTE entered into a settlement agreement with Marathon. The 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, Marathon received $40 million of the net proceeds from the IPO of NTE LP and NT Holdings redeemed Marathon’s existing preferred interest with a portion of the net proceeds from the IPO of NTE LP and issued Marathon a new $45 million preferred interest in NT Holdings in consideration for relinquishing all claims with respect to earn-out payments under the contingent consideration agreement. The Company also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the margin support agreement. At June 30, 2012, the Company had recorded a $30 million receivable related to the margin support agreement for the twelve months ended November 30, 2011 and liabilities of $76.5 million related to the earn-out component. Upon the consummation of the NTE LP IPO, the Company reversed the amounts recorded for the margin support and earn-out agreements and recorded a liability of $85 million.

MPC agreed to provide the Company with administrative and support services subsequent to the Marathon Acquisition pursuant to a transition services agreement, including finance and accounting, human resources, and information systems services, as well as support services generally for a period of up to eighteen months in connection with the transition from being a part of MPC’s systems and infrastructure to having its own systems and infrastructure. The transition services agreement required the Company to pay MPC for the provision of the transition services, as well as to reimburse MPC for compensation paid to MPC employees providing such transition services. In addition, under the agreement, Marathon provided support services for the operation of the refining and retail business segments, using the employees that were ultimately expected to be transitioned to the Company. The Company was obligated to reimburse MPC for the compensation paid to MPC employees providing such operations services, plus the agreed burden rates. For the three and six months ended June 30, 2011, the Company recognized expenses of approximately $4.6 million and $10.1 million, respectively, related to administrative and support services. The Company also paid $6.7 million in December 2010 of which $1.7 million and $3.3 million was amortized during the three and six months ended June 30, 2011, respectively. The majority of transition services were completed as of December 31, 2011 and, as such, the six months ended June 30, 2012 include no transition service charges from Marathon.

6.	INCOME TAXES

During the Reporting Period, the Company was a pass through entity for federal income tax purposes. As a result, there were no federal income taxes incurred. For the both the three and six months ended June 30, 2012 and 2011, the Company incurred state income taxes of less than $0.1 million in all periods. In conjunction with the IPO of NTE LP, and subsequent to June 30, 2012, certain subsidiaries of the Company will become taxable entities for federal income tax purposes (see Note 3).

7.	INVENTORIES


	June 30,		December 31,
(in millions)	2012		2011
Crude oil and refinery feedstocks	$	5.5	$	9.1
Refined products		111.4		109.1
Merchandise		19.0		21.1
Supplies and sundry items		14.2		14.8

Total	$	150.1	$	154.1

The LIFO method accounted for 78% and 77% of total inventory value at June 30, 2012 and December 31, 2011, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value by $5.3 million and $20.0 million at June 30, 2012 and December 31, 2011, respectively.

8.	EQUITY METHOD INVESTMENT

The Company has a 17% common equity interest in Minnesota Pipe Line. The carrying value of this equity method investment was $90.1 million and $89.9 million at June 30, 2012 and December 31, 2011, respectively.

As of June 30, 2012 and December 31, 2011, the carrying amount of the equity method investment was $6.8 million and $6.9 million higher than the underlying net assets of the investee, respectively. The Company is amortizing this difference over the remaining life of Minnesota Pipe Line’s primary asset (the fixed asset life of the pipeline).

Distributions received from Minnesota Pipe Line were $2.2 million and $0.3 million for the three months ended June 30, 2012 and 2011, respectively and $5.6 million and $2.5 million for the six months ended June 30, 2012 and 2011, respectively. Equity income from Minnesota Pipe Line was $3.0 million and $0.9 million for the three months ended June 30, 2012 and 2011, respectively and $5.9 million and $2.3 million for the six months ended June 30, 2012 and 2011, respectively.

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	2012		2011
Land		$	8.7	$	8.7
Retail stores and equipment	2 - 22 years		51.4		50.4
Refinery and equipment	5 - 24 years		324.8		318.1
Software	5 years		15.9		14.7
Other equipment	2 - 7 years		3.4		1.9
Precious metals			10.5		10.5
Assets under construction			20.2		17.4

			434.9		421.7
Less: accumulated depreciation			46.2		30.5

Property, plant and equipment, net		$	388.7	$	391.2

PP&E included gross assets acquired under capital leases of $13.5 million and $12.5 million at June 30, 2012 and December 31, 2011, respectively, with related accumulated depreciation of $1.4 million and $1.4 million, respectively.

10.

INTANGIBLE ASSETS

Intangible assets were ascribed value as a result of the Marathon Acquisition and are comprised of franchise rights amounting to $19.8 million and trademarks amounting to $15.6 million at both June 30, 2012 and December 31, 2011. 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 refinery 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 income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 13) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end. At June 30, 2012 and December 31, 2011, the Company had open commodity derivative instruments consisting of crude oil futures to buy 12 million and 17 million barrels, respectively, and refined products futures and swaps to sell 12 million and 17 million barrels, respectively, primarily to protect the value of refining margins through 2012 and 2013.

For the three months ended June 30, 2012, the Company recognized gains of $31.7 million related to derivative activities, of which $191.3 million represented unrealized gains on open contracts, partially offset by $159.6 million of realized losses (including early extinguishments as noted below). For the three months ended June 30, 2011, the Company recognized losses of $112.7 million related to derivative activities, of which $81.7 million represented realized losses and $31.0 represented unrealized losses on open contracts. For the six months ended June 30, 2012 and 2011, there were losses related to derivative activities of $154.2 million and $427.8 million, respectively. Of these total losses, $257.1 million and $133.9 million represented realized losses on settled contracts (including early extinguishments as noted below) for the six months ended June 30, 2012 and 2011, respectively. Additionally, the Company recognized unrealized gains of $102.9 million and unrealized losses of $293.9 million on open contracts for the six months ended June 30, 2012 and 2011, respectively.

During the first and second quarter 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 cash payments for the early extinguishment of these derivative instruments have been deferred and will come due beginning in August 2012 and continue through January 2014. The early extinguishments are treated as a current period loss as of the date of extinguishment. During the three and six months ended June 30, 2012 the Company incurred $92.2 million and $136.8 million, respectively, of realized losses related to these early extinguishments. The losses in the second quarter of 2012 relate to the re-pricing of derivatives and bear no interest. Interest accrues on the $44.6 million of early extinguishment obligations incurred during the first quarter of 2012 at a weighted average interest rate of 5.5%. Interest expense related to these liabilities in the three and six months ended June 30, 2012 was $0.6 and $1.0 million, respectively. The deferred payment obligations related to these early extinguishment losses are included in the June 30, 2012 balance sheet as $118.0 million within current liabilities and $18.8 million in long-term liabilities under the Accrued liabilities and Other liabilities captions, respectively. The Company plans to use approximately $92 million of the proceeds from the IPO of NTE LP to repay a portion of these deferred payment obligations (see Note 3).

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, 2012 and December 31, 2011:


(in millions)	Balance Sheet Classification	June 30, 2012			December 31, 2011

Commodity swaps and futures	Current assets	$	15.6		$	—
Commodity swaps and futures	Noncurrent assets		3.4			—
Commodity swaps and futures	Current liabilities		(20.4	)		(109.9	)
Commodity swaps and futures	Noncurrent liabilities		(5.3	)		—

Net asset (liability) position		$	(6.7	)	$	(109.9	)

Under the Company’s crack spread risk management strategy, 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 has provided letters of credit for a fixed dollar amount under its asset-based revolving credit facility (as discussed in Note 12) to the counterparty on the derivative instruments utilized under the crack spread derivative strategy. The Company is not subject to any margin calls for these crack spread derivatives and the counterparty does not have the right to demand any additional collateral beyond the aforementioned fixed dollar letters of credit. Any outstanding collateral is released to the Company upon settlement of the related derivative instrument.

12.

DEBT

In connection with the Marathon Acquisition, the Company entered into various financing arrangements including $290.0 million of 10.50% Senior Secured Notes due December 1, 2017 (“Secured Notes”) and a $300 million secured asset-based revolving credit facility (“Initial ABL Facility”).

Secured Notes

The Secured Notes are 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. Separate condensed consolidating financial information is not included as the Company does not have independent assets or operations. The Company is required to make interest payments on June 1 and December 1 of each year, which commenced on June 1, 2011. There are no scheduled principal payments required prior to the notes maturing on December 1, 2017. Borrowings bear interest at 10.50%.

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. In connection with the IPO of NTE LP, the Company will redeem $29 million of the principal amount of the Secured Notes at a redemption price of 103% of the principal amount thereof, for an estimated $30 million (see Note 3). 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 Secured Notes contain a number of covenants that, among other things, restrict the ability, subject to certain exceptions, of the Company and its subsidiaries to sell or otherwise dispose of assets, including capital stock of subsidiaries, incur additional indebtedness or issue preferred stock, repay other indebtedness, 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, engage in certain transactions with affiliates, change the business conducted by itself and its subsidiaries, and enter into agreements that restrict dividends from restricted subsidiaries.

ABL Facility

Subsequent to June 30, 2012, the Company entered into an amendment of its Initial ABL Facility (see Note 21). During the Reporting Period, the Initial ABL Facility provided revolving credit financing through December 1, 2015 in an aggregate principal amount of up to $300 million (of which $150 million could have been utilized for the issuance of letters of credit and up to $30 million could have been short-term borrowings upon same-day notice, referred to as swingline loans) and could have been increased up to a maximum aggregate principal amount of $400 million, subject to borrowing base availability and lender approval. Availability under the Initial ABL Facility at any time would be the lesser of (a) the aggregate commitments under the Initial ABL Facility or (b) the borrowing base, less any outstanding borrowings and letters of credit. The borrowing base was calculated based on a percentage of eligible accounts receivable, petroleum inventory and other assets.

Borrowings under the Initial ABL Facility bore interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.75% and 2.25%) or (b) a LIBOR rate plus applicable margin (ranging between 2.75% and 3.25%). The alternate base rate was the greater of (a) the prime rate, (b) the Federal Funds Effective rate plus 50 basis points, or (c) 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 was also required to pay an annual commitment fee ranging from 0.375% to 0.625% and letter of credit fees.

As of June 30, 2012 and December 31, 2011, the availability under the Initial ABL Facility was $113.4 million and $108.0 million, respectively. This availability was net of $61.6 million in outstanding letters of credit at both June 30, 2012 and December 31, 2011. The Company had no borrowings under the Initial ABL Facility at June 30, 2012 or December 31, 2011.

The Initial ABL Facility had a minimum fixed charge coverage ratio financial covenant requirement of at least 1.0 to 1.0. The covenant was operative when the Company’s availability under the facility was less than the greater of (a) 15% of the lesser of the $300 million commitment amount or the borrowing base or (b) $22.5 million.

The Initial ABL Facility also contained a number of covenants that, among other things, restricted, subject to certain exceptions, 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.

13.

FAIR VALUE MEASUREMENTS

As defined in accounting guidance, 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. Accounting guidance 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.

The following table provides the assets and liabilities carried at fair value measured on a recurring basis at June 30, 2012 and December 31, 2011:


	Balance at June 30, 2012		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Unobservable inputs (Level 3)
(in millions)
ASSETS
Cash and cash equivalents	$	171.0	$	171.0	$	—	$	—
Other current assets
Derivative asset - current		15.6		—		15.6		—
Other assets
Derivative asset - long-term		3.4		—		3.4		—

	$	190.0	$	171.0	$	19.0	$	—

LIABILITIES
Derivative liability - current	$	20.4	$	—	$	20.4	$	—
Accrued liabilities
Contingent consideration - earn-out		43.0		—		—		43.0
Other liabilities
Derivative liability - long-term		5.3		—		5.3		—
Contingent consideration - earn-out		33.5		—		—		33.5

	$	102.2	$	—	$	25.7	$	76.5


	Balance at December 31, 2011		Quoted prices in active markets (Level 1)		Significant other observable inputs (Level 2)		Unobservable inputs (Level 3)
(in millions)
ASSETS
Cash and cash equivalents	$	123.5	$	123.5	$	—	$	—
Other assets
Contingent consideration - margin support		20.2		—		—		20.2

	$	143.7	$	123.5	$	—	$	20.2

LIABILITIES
Derivative liability - current	$	109.9	$	—	$	109.9	$	—
Other liabilities
Contingent consideration - earn-out		30.9		—		—		30.9

	$	140.8	$	—	$	109.9	$	30.9

During the Reporting Period, the Company determined the fair value of its contingent consideration arrangements (margin support and earn-out) 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 income as contingent consideration (loss) income. The Company recorded $0.1 million and $65.8 million of non-cash contingent consideration loss during the three and six months ended June 30, 2012, respectively, related to changes in the fair value of the Company’s Level 3 contingent consideration arrangements. During the three and six months ended June 30, 2011, the Company recorded $9.2 million and $41.0 million of contingent consideration income, respectively.

These contingent consideration agreements (margin support and earn out) were reported at fair value using Level 3 inputs due to such agreements not having observable market prices. The fair value of the agreements were determined based on a Monte Carlo simulation prepared by a third party service provider using management projections of future period EBITDA levels. Pursuant to a settlement agreement entered into with Marathon, which became effective after June 30, 2012, the Company has agreed to relinquish all claims under the margin support agreement and Marathon has agreed to relinquish all claims under the contingent consideration agreement (see Notes 5 and 19).

The significant unobservable inputs used in the fair value measurement of our Level 3 agreements were the 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.

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 six months ended June 30, 2012 and 2011, there were no adjustments to the fair value of such assets. The Company recorded assets acquired and liabilities assumed in the Marathon Acquisition at fair value.

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 Secured Notes disclosed below was determined based on quoted prices in active markets (Level 1).


	June 30, 2012				December 31, 2011
	Carrying		Fair		Carrying		Fair
	Amount		Value		Amount		Value
(in millions)
Secured Notes	$	290.0	$	314.3	$	290.0	$	316.5

14.

ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:


(in millions)	Six Months Ended June 30, 2012		Six Months Ended June 30, 2011

Asset retirement obligation balance at beginning of period	$	1.5	$	2.1
Revisions of previous estimates		0.3		—
Accretion expense		0.2		0.1

Asset retirement obligation balance at end of period	$	2.0	$	2.2

15.

EQUITY-BASED COMPENSATION

NT Investors sponsors an equity participation plan which provides for the granting of profit interest units to certain employees and independent non-employee directors of the Company. The plan has reserved approximately 29 million profit interest units for issuance under the plan which represent profit interests in NT Investors. 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. 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 awards are satisfied from distributions made to NT Investors and will not dilute cash available for distribution to the unitholders of NTE LP.

A summary of the NT Investors’ profit interest unit activity is set forth below:


	Number of NT Investor Profit Units (in millions)		Weighted Average Exercise Price		Average Remaining Contractual Term
Outstanding at December 31, 2011		24.2	$	1.87		9.2
Granted		1.5		2.57

Outstanding at June 30, 2012		25.7	$	1.91		8.6

The estimated weighted average fair value as of the grant date for NT Investor profit units granted during the six months ended June 30, 2012 and 2011 were $0.88 and $0.57, respectively, based upon the following assumptions:


	2012			2011

Expected life (years)		6.5			6.5
Expected volatility		55.5	%		40.6	%
Expected dividend yield		0.0	%		0.0	%
Risk-free interest rate		1.4	%		2.7	%

The weighted average expected life for the grants is calculated using the simplified method, which defines the expected life as the average of the contractual term of the options and the weighted average vesting period. Expected volatility for the grants is based primarily on the historical volatility of a representative group of peer companies for a period consistent with the expected life of the awards.

As of June 30, 2012, and 2011, the total unrecognized compensation cost for NT Investor profit interest units was $7.5 million and $6.8 million, respectively. This non-cash expense will be recognized on a straight-line basis through 2017.

16.

DEFINED BENEFIT 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 cash account of the participants equal to 5.0% of eligible compensation. Participants’ cash accounts also receive interest credits each year based upon the average thirty year United States Treasury bond rate published in September preceding the respective plan year. Participants become fully vested in their accounts after three years of service. The Plan was not in place during the six months ended June 30, 2011. The net periodic benefit cost related to the Cash Balance Plan for the six months ended June 30, 2012 of $0.8 million related primarily to current period service costs.

17.

SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:


	Six Months Ended
	June 30,		June 30,
(in millions)	2012		2011
Net cash from operating activities included:
Interest paid	$	16.7	$	15.2

Noncash investing and financing activities include:
Capital expenditures included in accounts payable	$	1.3	$	1.1

18.

LEASING ARRANGEMENTS

As described in Note 5, concurrent with the Marathon Acquisition, certain Marathon assets (including real property interests and land related to 135 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. During 2011, 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.

Additionally, in April 2012, the Company entered into capital lease with a third party for 12 trucks used in its Bakery operations. The carrying cost of this lease liability at June 30, 2012 was $1.0 million with $0.2 million classified as a short-term liability in accrued liabilities and $0.8 million classified as a long-term liability in Lease financing obligation.

19.

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.

Contingent Consideration

As described in Note 5, throughout the Reporting Period the Marathon Acquisition provided for contingent consideration, or earn-out payments, that could have resulted in additional payments of up to a total of $125 million to MPC over an eight year period ending December 1, 2018 based on operating performance. The Marathon Acquisition agreement also included a margin support component that required Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA was below $145 million less, among other things, any rental expense related to the real estate lease arrangement, in either of the first two twelve month periods ending November 30, 2011 or 2012 up to a maximum of $60 million. Any such payments made by Marathon would have increased the amount that the Company would have been required to pay Marathon over the earn-out period. See Note 13 for additional information relating to the fair value of contingent arrangements related to the Marathon Acquisition. In addition to the estimated values related to future periods discussed in Note 13, the Company had recorded a receivable of $30.0 million as of June 30, 2012 and December 31, 2011 relating to the margin support component of the contingent consideration arrangement for the first twelve months ended November 30, 2011. MPC disputed approximately $12 million of this amount.

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, 2012 and December 31, 2011, liabilities for remediation totaled $4.2 million and $4.7 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, were $0.3 million and $0.2 million at June 30, 2012 and December 31, 2011, respectively.

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.

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.

20.

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 MPLI and Minnesota Pipe Line, and

•

Retail – operates 166 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, 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	$	(14.2	)	$	225.7

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


(in millions)
Three months ended June 30, 2011	Refining		Retail		Other			Total

Revenues
Customer	$	686.7	$	405.6	$	—		$	1,092.3
Intersegment		291.8		—		—			291.8

Segment revenues		978.5		405.6		—			1,384.1
Elimination of intersegment revenues		—		—		(291.8	)		(291.8	)

Total revenues	$	978.5	$	405.6	$	(291.8	)	$	1,092.3


Income from operations	$	74.2	$	4.7	$	1.8		$	80.7

Income from equity method investment	$	0.9	$	—	$	—		$	0.9

Depreciation and amortization	$	5.5	$	2.1	$	—		$	7.6

Capital expenditures	$	7.5	$	0.6	$	2.0		$	10.1


(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	$	(89.2	)	$	228.4

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


(in millions)
Six months ended June 30, 2011	Refining		Retail		Other			Total

Revenues
Customer	$	1,286.2	$	746.3	$	—		$	2,032.5
Intersegment		537.5		—		—			537.5

Segment revenues		1,823.7		746.3		—			2,570.0
Elimination of intersegment revenues		—		—		(537.5	)		(537.5	)

Total revenues	$	1,823.7	$	746.3	$	(537.5	)	$	2,032.5


Income from operations	$	152.7	$	2.3	$	26.4		$	181.4

Income from equity method investment	$	2.3	$	—	$	—		$	2.3

Depreciation and amortization	$	10.6	$	4.0	$	0.3		$	14.9

Capital expenditures	$	12.5	$	0.7	$	2.9		$	16.1

Intersegment sales from the Refining segment to the Retail segment consist primarily of sales of refined products which are recorded based on contractual prices that are market based. Revenues from external customers are nearly all in the United States.

Total assets by segment were as follows:


(in millions)	Refining		Retail		Other		Total

At June 30, 2012	$	678.3	$	135.6	$	267.7	$	1,081.6


At December 31, 2011	$	646.6	$	139.5	$	212.7	$	998.8

All property, plant and equipment are located in the United States.

21.

SUBSEQUENT EVENTS

On July 17, 2012, the Company entered into an amendment of its Initial ABL Facility. The amendment to the Initial ABL Facility, 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 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 amendment to the revolving credit facility). In connection with the removal of this requirement, the amendment to the revolving credit 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, we must comply with a minimum Fixed Charge Coverage Ratio (as defined in the amendment to the revolving credit facility) of at least 1.0 to 1.0. As of July 14, 2012 (the most recent determination date), the borrowing base under the revolving credit facility was $195.4 million, availability under the revolving credit facility was $133.9 million (which is net of $61.6 million in outstanding letters of credit) and the Company had no borrowings under the revolving credit facility. As of July 14, 2012, the springing financial covenant described above would apply if availability under the revolving credit facility were less than $24.4 million, which means that we could increase borrowings under the revolving credit facility by $109.5 million before the Company would be required to comply with the minimum Fixed Charge Coverage Ratio.

Borrowings under the amended revolving credit 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) 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.

In connection with this amendment the Company will recognize a one-time, non-cash charge to interest expense of approximately $3.5 million during the third quarter of 2012 related to the write-off of previously capitalized deferred financing costs.

On July 31, 2012, NTE LP closed its IPO of 18,687,500 common units and began trading on the New York Stock Exchange under the ticker symbol: NTI. See Note 3 for further details.

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.

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, 2012, we had total revenues of $2.2 billion, operating income of $228.4 million, net income of $53.0 million and Adjusted EBITDA of $327.8 million. A definition, and reconciliation, of Adjusted EBITDA to net (loss) earnings, is included herein under the caption “Adjusted EBITDA.”

Refining Business

Our refining business primarily consists of a 74,000 barrels per day (“bpd”), or 84,500 barrels per stream day, refinery located in St. Paul Park, Minnesota. Our refinery has a Nelson complexity index of 11.5, which refers to the number, type and capacity of processing units at the refinery. We are one of only two refineries in Minnesota and one of four refineries in the Upper Great Plains area within the PADD II region. Our refinery’s complexity allows us to process a variety of light, heavy, sweet and sour crudes, many of which have historically priced at a discount to the NYMEX WTI price benchmark, meaning we can process lower cost crude oils into higher value refined products. The PADD II region covers 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. Our refining business also includes our 17% interest in the Minnesota Pipe Line Company and MPL Investments, which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

As of June 30, 2012, our retail business operated 166 convenience stores under the SuperAmerica brand and also supported 67 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 non-alcoholic beverages, beer, 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.

Consolidated Financial Data


	Three Months Ended,						Six Months Ended,
(in millions)	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

Revenue	$	1,155.2		$	1,092.3		$	2,154.3		$	2,032.5

Costs, expenses and other:
Cost of sales		825.0			909.0			1,664.8			1,688.0
Direct operating expenses		61.5			63.3			122.2			125.2
Turnaround and related expenses		11.5			19.2			15.0			22.5
Depreciation and amortization		7.8			7.6			16.3			14.9
Selling, general and administrative		24.8			20.5			45.1			38.9
Formation costs		—			1.9			—			4.4
Contingent consideration loss (income)		0.1			(9.2	)		65.8			(41.0	)
Other income, net		(1.2	)		(0.7	)		(3.3	)		(1.8	)

Operating income		225.7			80.7			228.4			181.4

Realized losses from derivative activities		(67.4	)		(81.7	)		(120.3	)		(133.9	)
Loss on early extinguishment of derivatives		(92.2	)		—			(136.8	)		—
Unrealized gains (losses) from derivative activities		191.3			(31.0	)		102.9			(293.9	)
Interest expense, net		(10.7	)		(10.2	)		(21.1	)		(20.2	)

Income (loss) before income taxes		246.7			(42.2	)		53.1			(266.6	)

Income tax (provision) benefit		(0.1	)		0.1			(0.1	)		—

Net income (loss)	$	246.6		$	(42.1	)	$	53.0		$	(266.6	)

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Revenue. Revenue for the three months ended June 30, 2012 was $1,155.2 million compared to $1,092.3 million for the three months ended June 30, 2011, an increase of 5.8%. Refining segment revenue increased 6.2% and retail segment revenue decreased 6.4% compared to the three months ended June 30, 2011. The refining segment benefited from a 5.3% increase in sales volumes versus the 2011 quarter due to higher refinery throughput. Retail revenue was negatively impacted by lower fuel sales volumes that decreased 5.8% from the prior year quarter due to reduced market demand. Excise taxes included in revenue totaled $71.2 million and $59.9 million for the three months ended June 30, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $825.0 million for the three months ended June 30, 2012 compared to $909.0 million for the three months ended June 30, 2011, a decrease of 9.2%, due primarily to lower priced crude oil as a result of favorable crude differentials in the second quarter of 2012. Excise taxes included in cost of sales were $71.2 million and $59.9 million for the three months ended June 30, 2012 and 2011, respectively.

Direct operating expenses. Direct operating expenses totaled $61.5 million for the three months ended June 30, 2012 compared to $63.3 million for the three months ended June 30, 2011, a decrease of 2.8%, due primarily to lower utility expenses at the refinery and lower operating expenses at our retail stores.

Turnaround and related expenses. Turnaround and related expenses totaled $11.5 million for the three months ended June 30, 2012 compared to $19.2 million for the three months ended June 30, 2011. Both periods include costs related to planned, partial turnarounds at our refinery. The 2012 turnaround of the alkylation unit was completed according to schedule in mid-May. The 2011 turnaround was principally to replace catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit.

Depreciation and amortization. Depreciation and amortization was $7.8 million for the three months ended June 30, 2012 compared to $7.6 million for the three months ended June 30, 2011, an increase of 2.6%. This increase was primarily due to depreciation of assets placed in service since June 30, 2011 at our refinery and related to our systems implementation project.

Selling, general and administrative expenses. Selling, general and administrative expenses were $24.8 million for the three months ended June 30, 2012 compared to $20.5 million for the three months ended June 30, 2011. This increase of $4.3 million from the prior year period relates primarily to higher employee compensation costs, risk management expenses and higher administrative costs for post go-live systems support during the process optimization phase of our standalone systems implementation.

Formation costs. Formation costs for the three months ended June 30, 2011 were $1.9 million. There were no formation costs in the 2012 period. All of the costs from the 2011 period are attributable to the Marathon Acquisition.

Contingent consideration loss (income). Contingent consideration loss was $0.1 million for the three months ended June 30, 2012 compared to contingent consideration income of $9.2 million for the three months ended June 30, 2011. Both the contingent consideration income and loss relate to updated financial performance estimates for the period of performance under the margin support and earn-out agreements with Marathon related primarily to changes in the forward markets for our refined products.

Other income, net. Other income, net was $1.2 million for the three months ended June 30, 2012 compared to $0.7 million for the three months ended June 30, 2011. This change is driven primarily by increases in equity income from our investment in the Minnesota Pipe Line Company.

Gains (losses) from derivative activities. For the three months ended June 30, 2012, we had realized losses of $67.4 million related to settled contracts compared to $81.7 million in the prior year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized gains on outstanding derivatives of $191.3 million for the three months ended June 30, 2012 compared to an unrealized loss of $31.0 million during the three months ended June 30, 2011. These derivatives were entered into to partially hedge the crack spreads for our refining business. In addition to these impacts, during the three months ended June 30, 2012 we entered into an arrangement to re-price a portion of our existing derivative instruments ahead of their respective expiration dates and incurred $92.2 million of realized losses related to these early extinguishments. We plan to settle a portion of this early extinguishment obligation out of the net proceeds of the IPO of NTE LP.

Interest expense, net. Interest expense, net was $10.7 million for the three months ended June 30, 2012 and $10.2 million for the three months ended June 30, 2011. These interest charges relate primarily to our senior secured notes as well as commitment fees and interest on the Initial ABL Facility and the amortization of deferred financing costs. The increase from the prior year quarter relates primarily to interest accruing on our deferred derivative obligations.

Income tax (provision) benefit. The net income tax (provision) benefit was less than $0.1 million for the three months ended June 30, 2012 and 2011. We operate as a pass-through entity for federal tax purposes and, as such, only state taxes have been recognized.

Net income (loss). Our net income was $246.6 million for the three months ended June 30, 2012 compared to a net loss of $42.1 million for the three months ended June 30, 2011. This improvement of $288.7 million was primarily attributable to a $160.9 million increase in operating income at our refinery segment due to favorable crack spreads and crude differentials in the quarter and a net gain of $144.4 million related to derivatives activities. These improvements were partially offset by a $9.3 million unfavorable impact in contingent consideration loss (income).

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Revenue. Revenue for the six months ended June 30, 2012 was $2,154.3 million compared to $2,032.5 million for the six months ended June 30, 2011, an increase of 6.0%. Refining segment revenue increased 6.0% and retail segment revenue decreased 3.0% compared to the six months ended June 30, 2011. The refining segment benefited from higher average prices across our principal products driven primarily by increased market prices for refined products and higher sales volumes. Retail revenue decreased primarily due to lower fuel sales volumes caused by reduced market demand. Excise taxes included in revenue totaled $136.8 million and $116.6 million for the six months ended June 30, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $1,664.8 million for the six months ended June 30, 2012 compared to $1,688.0 million for the six months ended June 30, 2011, a decrease of 1.4%, due primarily to lower priced crude oil as a result of favorable crude differentials in the second quarter of 2012. Excise taxes included in cost of sales were $136.8 million and $116.6 million for the six months ended June 30, 2012 and 2011, respectively.

Direct operating expenses. Direct operating expenses totaled $122.2 million for the six months ended June 30, 2012 compared to $125.2 million for the six months ended June 30, 2011, a decrease of 2.4%, due primarily to lower utility expenses at the refinery, which were driven by lower utility rates and reduced usage due to favorable weather conditions in the first quarter of 2012, and lower operating expenses at our retail stores.

Turnaround and related expenses. Turnaround and related expenses totaled $15.0 million for the six months ended June 30, 2012 compared to $22.5 million for the six months ended June 30, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 turnaround of the alkylation unit was completed according to schedule in mid-May. The 2011 turnaround was principally to replace catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit.

Depreciation and amortization. Depreciation and amortization was $16.3 million for the six months ended June 30, 2012 compared to $14.9 million for the six months ended June 30, 2011, an increase of 9.4%. This increase was primarily due to depreciation of assets placed in service since June 30, 2011 at our refinery and related to our systems implementation project.

Selling, general and administrative expenses. Selling, general and administrative expenses were $45.1 million for the six months ended June 30, 2012 compared to $38.9 million for the six months ended June 30, 2011. This increase of 15.9% from the prior year period relates primarily to higher administrative costs related to post go-live systems support during the process optimization phase of our standalone systems implementation and higher employee compensation costs and risk management expenses in the six months ended June 30, 2012.

Formation costs. Formation costs for the six months ended June 30, 2011 were $4.4 million. There were no formation costs in the 2012 period. All of the costs from the 2011 period are attributable to the Marathon Acquisition.

Contingent consideration loss (income). Contingent consideration loss was $65.8 million for the six months ended June 30, 2012 compared to contingent consideration income of $41.0 million for the six months ended June 30, 2011. Both the contingent consideration income and loss relate to updated financial performance estimates for the period of performance under the margin support and earn-out agreements with Marathon related primarily to changes in the forward markets for our refined products.

Other income, net. Other income, net was $3.3 million for the six months ended June 30, 2012 compared to $1.8 million for the six months ended June 30, 2011. This change is driven primarily by increases in equity income from our investment in the Minnesota Pipe Line Company.

Gains (losses) from derivative activities. For the six months ended June 30, 2012, we had realized losses of $120.3 million related to settled contracts compared to $133.9 million in the prior year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized gains on outstanding derivatives of $102.9 million for the six months ended June 30, 2012 compared to unrealized losses of $293.9 million during the six months ended June 30, 2011. These derivatives were entered into to partially hedge the crack spreads for our refining business. In addition to these impacts, during the six months ended June 30, 2012 we entered into arrangements to settle or re-price a portion of our existing derivative instruments ahead of their respective expiration dates and incurred $136.8 million of realized losses related to these early extinguishments. We plan to settle approximately $92 million of this early extinguishment obligation out of the net proceeds of the IPO of NTE LP.

Interest expense, net. Interest expense, net was $21.1 million for the six months ended June 30, 2012 and $20.2 million for the six months ended June 30, 2011. These interest charges relate primarily to our senior secured notes as well as commitment fees and interest on the Initial ABL Facility and the amortization of deferred financing costs. The increase from the prior year period relates primarily to interest accruing on our deferred derivative obligations.

Income tax provision. Income tax expense was less than $0.1 million for the six months ended June 30, 2012 and for the six months ended June 30, 2011. We operate as a pass-through entity for federal tax purposes and, as such, only state taxes have been recognized.

Net income (loss). Our net income was $53.0 million for the six months ended June 30, 2012 compared to a net loss of $266.6 million for the six months ended June 30, 2011. This improvement of $319.6 million was primarily attributable to a $160.9 million increase in operating income at our refinery segment due to favorable crack spreads and crude differentials in the second quarter of 2012 and a reduction in losses related to derivative activities of $273.6 million. These improvements were partially offset by a $106.8 million unfavorable impact in contingent consideration income (loss).

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, 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


	Three Months Ended June 30, 2011
(in millions)	Refining		Retail		Other/Elim		Combined
Revenue:
Sales and other revenue	$	686.7	$	405.6	$	—	$	1,092.3
Intersegment sales		291.8		—		(291.8)		—

Segment revenue	$	978.5	$	405.6	$	(291.8)	$	1,092.3


Cost of sales:
Cost of sales	$	839.5	$	69.5	$	—	$	909.0
Intersegment purchases		—		291.8		(291.8)		—

Segment cost of sales	$	839.5	$	361.3	$	(291.8)	$	909.0


	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


	Six Months Ended June 30, 2011
(in millions)	Refining		Retail		Other/Elim		Combined
Revenue:
Sales and other revenue	$	1,286.2	$	746.3	$	—	$	2,032.5
Intersegment sales		537.5		—		(537.5)		—

Segment revenue	$	1,823.7	$	746.3	$	(537.5)	$	2,032.5


Cost of sales:
Cost of sales	$	1,558.5	$	129.5	$	—	$	1,688.0
Intersegment purchases		—		537.5		(537.5)		—

Segment cost of sales	$	1,558.5	$	667.0	$	(537.5)	$	1,688.0

Refining Segment


	Three Months Ended,						Six Months Ended,
(in millions)	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

Revenue	$	1,039.2		$	978.5		$	1,933.7		$	1,823.7

Costs, expenses and other:
Cost of sales		751.5			839.5			1,523.5			1,558.5
Direct operating expenses		31.7			32.5			63.0			64.8
Turnaround and related expenses		11.5			19.2			15.0			22.5
Depreciation and amortization		6.1			5.5			12.1			10.6
Selling, general and administrative		6.4			8.8			12.5			17.4
Other income, net		(3.1	)		(1.2	)		(6.0	)		(2.8	)

Operating income	$	235.1		$	74.2		$	313.6		$	152.7


Key Operating Statistics
Total refinery production (bpd) (1)		82,069			73,113			79,253			78,877
Total refinery throughput (bpd)		81,906			72,828			78,659			78,768
Refined products sold (bpd) (2)		88,773			84,305			83,348			82,537

Per barrel of throughput:
Refinery gross margin (3)	$	38.60		$	20.97		$	28.65		$	18.60
Direct operating expenses (4)	$	4.25		$	4.90		$	4.40		$	4.55
Per barrel of refined products sold:
Refinery gross margin (3)	$	35.61		$	18.12		$	27.04		$	17.75
Direct operating expenses (4)	$	3.92		$	4.24		$	4.15		$	4.34

Refinery product yields (bpd):
Gasoline		38,186			37,335			38,544			39,400
Distillate (5)		26,742			21,980			25,451			22,883
Asphalt		12,455			9,678			10,389			9,647
Other (6)		4,686			4,120			4,869			6,947

Total		82,069			73,113			79,253			78,877


Refinery throughput (bpd):
Crude oil		80,796			69,802			77,020			74,048
Other feedstocks (7)		1,110			3,026			1,639			4,720

Total		81,906			72,828			78,659			78,768


Market Statistics:
Crude Oil Average Pricing:
West Texas Intermediate ($/barrel)	$	93.35		$	102.34		$	98.15		$	98.50
PADD II / Group 3 Average Pricing:
Unleaded 87 Gasoline ($/barrel)	$	120.53		$	128.60		$	121.11		$	119.79
Ultra Low Sulfur Diesel ($/barrel)	$	123.64		$	131.15		$	127.30		$	125.55

(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)

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

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

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

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

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

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Revenue. Revenue for the three months ended June 30, 2012 was $1,039.2 million compared to $978.5 million for the three months ended June 30, 2011, an increase of 6.2%. This increase was primarily due to a 5.3% increase in sales volumes for refined products in the three months ended June 30, 2012. The higher refined product volumes in the second quarter of 2012 is primarily attributable to higher refinery throughput. Excise taxes included in revenue were $68.8 million and $57.3 million for the three months ended June 30, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $751.5 million for the three months ended June 30, 2012 compared to $839.5 million for the three months ended June 30, 2011, a 10.5% decrease. This decrease was primarily due to lower raw material costs driven principally by lower benchmark market prices of crude oil and favorable crude price differentials compared to these benchmarks in the three months ended June 30, 2011. Excise taxes included in cost of sales were $68.8 million and $57.3 million for the three months ended June 30, 2012 and 2011, respectively. Refinery gross product margin per barrel of throughput was $38.60 for the three months ended June 30, 2012 compared to $20.97 for the three months ended June 30, 2011, an increase of $17.63, or 84.1%, which is mostly attributable to improved market crack spreads and improved differentials per barrel to market for both our crude cost and refined products sold.

Direct operating expenses. Direct operating expenses totaled $31.7 million for the three months ended June 30, 2012 compared to $32.5 million for the three months ended June 30, 2011, a 2.5% decrease. This decrease was due primarily to lower utility expenses at the refinery driven by reduced natural gas prices.

Turnaround and related expenses. Turnaround and related expenses totaled $11.5 million for the three months ended June 30, 2012 compared to $19.2 million for the three months ended June 30, 2011. Both periods include costs related to planned, partial turnarounds. The 2012 turnaround of the alkylation unit was completed according to schedule in mid-May. The 2011 turnaround was principally to replace catalyst in the distillate and gas oil hydrotreaters and to conduct basic maintenance on the No. 1 crude unit.

Depreciation and amortization. Depreciation and amortization was $6.1 million for the three months ended June 30, 2012 compared to $5.5 million for the three months ended June 30, 2011, an increase of 10.9%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since June 30, 2011, the most significant of which was our boiler replacement project which was placed in service in the fourth quarter of 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.4 million and $8.8 million for the three months ended June 30, 2012 and 2011, respectively, a decrease of 27.3%. This decrease was due to the termination of our transition services agreement with Marathon in the fourth quarter of 2011, as a result of which we did not incur expenses related to the agreement in the three months ended June 30, 2012. We are no longer using Marathon’s systems infrastructure.

Other income, net. Other income, net was $3.1 million for the three months ended June 30, 2012 compared to $1.2 million for the three months ended June 30, 2011. This increase is driven primarily by an increase in equity income from our investment in the Minnesota Pipe Line Company, which increased its tariff rates in the third quarter of 2011.

Operating income. Income from operations was $235.1 million for the three months ended June 30, 2012 compared to $74.2 million for the three months ended June 30, 2011. This increase from the prior year period is primarily due to favorable crack spreads and crude differentials in the second quarter of 2012 and higher throughput rates and sales volumes in the 2012 period.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Revenue. Revenue for the six months ended June 30, 2012 was $1,933.7 million compared to $1,823.7 million for the six months ended June 30, 2011, an increase of 6.0%. This increase was primarily due to a 4.4% increase in average prices across our refined products sold and higher sales volumes in the six months ended June 30, 2012. Excise taxes included in revenue were $132.3 million and $111.7 million for the six months ended June 30, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $1,523.5 million for the six months ended June 30, 2012 compared to $1,558.5 million for the six months ended June 30, 2011, a 2.2% decrease. This decrease was primarily due to lower raw material costs driven principally by favorable crude differentials in the six months ended June 30, 2012 compared to the 2011 period. Excise taxes included in cost of sales were $132.3 million and $111.7 million for the six months ended June 30, 2012 and 2011, respectively. Refinery gross product margin per barrel of throughput was $28.65 for the six months ended June 30, 2012 compared to $18.60 for the six months ended June 30, 2011, an increase of $10.05, or 54.0%, which is mostly attributable to improved crack spreads and improved differentials to market for both crude cost and refined products sold primarily in the second quarter of 2012.

Direct operating expenses. Direct operating expenses totaled $63.0 million for the six months ended June 30, 2012 compared to $64.8 million for the six months ended June 30, 2011, a 2.8% decrease. This decrease was due primarily to lower utility expenses at the refinery, which resulted from decreases in natural gas prices across the first six months of 2012 and reduced overall usage primarily during the first quarter of 2012.

Depreciation and amortization. Depreciation and amortization was $12.1 million for the six months ended June 30, 2012 compared to $10.6 million for the six months ended June 30, 2011, an increase of 14.2%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since June 30, 2011, the most significant of which was our boiler replacement project which was placed in service in the fourth quarter of 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses were $12.5 million and $17.4 million for the six months ended June 30, 2012 and 2011, respectively, a decrease of 28.2%. This decrease was due to the termination of our transition services agreement with Marathon in the fourth quarter of 2011, as a result of which we did not incur expenses related to the agreement in the six months ended June 30, 2012. We are no longer using Marathon’s systems infrastructure.

Other income, net. Other income, net was $6.0 million for the six months ended June 30, 2012 compared to $2.8 million for the six months ended June 30, 2011. This increase is driven primarily by an increase in equity income from our investment in the Minnesota Pipe Line Company, which increased its tariff rates in the third quarter of 2011.

Operating income. Income from operations was $313.6 million for the six months ended June 30, 2012 compared to $152.7 million for the six months ended June 30, 2011. This increase from the prior year period of $160.9 million is primarily due to favorable crack spreads, crude differentials and higher throughput rates and sales volumes during the second quarter of 2012.

Retail Segment


	Three Months Ended,						Six Months Ended,
(in millions)	June 30, 2012			June 30, 2011			June 30, 2012			June 30, 2011

Revenue	$	379.6		$	405.6		$	724.2		$	746.3

Costs, expenses and other:
Cost of sales		337.1			361.3			644.9			667.0
Direct operating expenses		29.8			30.9			59.2			60.5
Depreciation and amortization		1.6			2.1			3.8			4.0
Selling, general and administrative		6.3			6.6			12.3			12.5

Operating income	$	4.8		$	4.7		$	4.0		$	2.3


Operating data:
Company-owned stores:
Fuel gallons sold (in millions)		77.5			82.3			151.6			160.4
Fuel margin per gallon (1)	$	0.22		$	0.22		$	0.20		$	0.19
Merchandise sales (in millions)	$	90.7		$	86.3		$	169.6		$	161.6
Merchandise margin % (2)		24.9	%		25.3	%		25.3	%		25.4	%
Number of stores at period end		166			166			166			166
Franchisee stores:
Fuel gallons sold (in millions)		11.2			12.1			22.0			24.3
Royalty income (in millions)	$	0.5		$	0.5		$	1.0		$	0.9
Number of stores at period end		67			67			67			67
Market Statistics:
PADD II gasoline prices ($/gallon)	$	3.70		$	3.84		$	3.64		$	3.57

(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.

(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.

Three Months Ended June 30, 2012 Compared to the Three Months Ended June 30, 2011

Revenue. Revenue for the three months ended June 30, 2012 was $379.6 million compared to $405.6 million for the three months ended June 30, 2011, a decrease of 6.4%. This decrease was primarily due to a reduction in fuel sales driven primarily by lower sales volumes. We experienced a 5.8% decrease in fuel gallons sold in our retail segment compared to the prior year period. The volume reduction in the 2012 period is primarily due to lower retail demand for gasoline. Excise taxes included in revenue were $2.4 million for the three months ended June 30, 2012 and $2.6 million for the three months ended June 30, 2011.

Cost of sales. Cost of sales totaled $337.1 million for the three months ended June 30, 2012 and $361.3 million for the three months ended June 30, 2011, a decrease of 6.7% primarily due to lower fuel volumes in the 2012 quarter. Excise taxes included in cost of sales were $2.4 million for the three months ended June 30, 2012 and $2.6 million for the three months ended June 30, 2011. For company-operated stores, retail fuel margin per gallon was $0.22 for both the three months ended June 30, and 2011.

Direct operating expenses. Direct operating expenses totaled $29.8 million for the three months ended June 30, 2012 compared to $30.9 million for the three months ended June 30, 2011, a decrease of 3.6% from the 2011 period due to lower credit card costs and lower outside contractor expenses.

Depreciation and amortization. Depreciation and amortization was $1.6 million for the three months ended June 30, 2012 compared to $2.1 million for the three months ended June 30, 2011, a decrease of $0.5 million. During 2011, our continuing involvement ended for a subset of our retail stores which did not meet the criteria for sales-leaseback treatment initially. As such, the related fair value of the assets for these stores was removed from the consolidated balance sheet and was no longer depreciated. This reduction in depreciation was partially offset by increases related to our capital expenditures since June 30, 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.3 million and $6.6 million for the three months ended June 30, 2012 and 2011, respectively, which represents a decrease of $0.3 million from the 2011 period.

Operating income. Operating income was $4.8 million for the three months ended June 30, 2012 compared to $4.7 million for the three months ended June 30, 2011, an increase of $0.1 million. The increase is primarily attributable to reduced expense levels in the second quarter offsetting the impacts from the decreased fuel volumes in the 2012 quarter.

Six Months Ended June 30, 2012 Compared to the Six Months Ended June 30, 2011

Revenue. Revenue for the six months ended June 30, 2012 was $724.2 million compared to $746.3 million for the six months ended June 30, 2011, a decrease of 3.0%. This decrease was primarily due to a reduction in fuel sales driven primarily by lower sales volumes. We experienced a 5.5% decrease in fuel gallons sold in our retail segment compared to the prior year. The volume reduction in the 2012 period is primarily due to lower retail demand for gasoline. Excise taxes included in revenue were $4.5 million for the six months ended June 30, 2012 and $4.9 million for the six months ended June 30, 2011.

Cost of sales. Cost of sales totaled $644.9 million for the six months ended June 30, 2012 and $667.0 million for the six months ended June 30, 2011, a decrease of 3.3%. Excise taxes included in cost of sales were $4.5 million for the six months ended June 30, 2012 and $4.9 million for the six months ended June 30, 2011. For company-operated stores, retail fuel margin per gallon was $0.20 for the six months ended June 30, 2012 compared to $0.19 per gallon for the six months ended June 30, 2011.

Direct operating expenses. Direct operating expenses totaled $59.2 million for the six months ended June 30, 2012 compared to $60.5 million for the six months ended June 30, 2011, a decrease of 2.1% from the 2011 period due to lower credit card costs and lower outside contractor expenses.

Depreciation and amortization. Depreciation and amortization was $3.8 million for the six months ended June 30, 2012 compared to $4.0 million for the six months ended June 30, 2011, a decrease of 5.0%. During 2011, our continuing involvement ended for a subset of our retail stores which did not meet the criteria for sales-leaseback treatment initially. As such, the related fair value of the assets for these stores was removed from the consolidated balance sheet and was no longer depreciated. This reduction in depreciation was partially offset by increases related to our capital expenditures since June 30, 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses were $12.3 million and $12.5 million for the six months ended June 30, 2012 and 2011, respectively, which represents a decrease of 1.6% from the 2011 period.

Operating income. Operating income was $4.0 million for the six months ended June 30, 2012 compared to $2.3 million for the six months ended June 30, 2011, an improvement of $1.7 million. The improvement is primarily attributable to increased fuel margins per gallon and higher merchandise revenues during the first quarter of 2012.

Adjusted EBITDA

Our management uses Adjusted EBITDA as a measure of operating performance to assist in comparing performance from period to period on a consistent basis and to readily view operating trends, as a measure for planning and forecasting overall expectations and for evaluating actual results against such expectations, and in communications with the board of directors, 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 Member. The revolving credit facility and other contractual obligations also include similar measures as a basis for certain covenants under those agreements which may differ from the Adjusted EBITDA definition described below.

Adjusted EBITDA is not a presentation made in accordance with GAAP and our computation of Adjusted EBITDA may vary from others in our industry. In addition, Adjusted EBITDA contains some, but not all, adjustments that are taken into account in the calculation of the components of various covenants in the agreements governing the notes, the revolving credit 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 costs, bargain purchase gain 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 Minnesota Pipe Line Company investment, but includes 17% of the calculated EBITDA of the Minnesota Pipe Line Company;

•

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, 2012
	Refining		Retail		Other			Total
(in millions)
Net income	$	235.1	$	4.8	$	6.7		$	246.6
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		17.6			265.2
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
Realized losses on derivative activities		—		—		67.4			67.4

Adjusted EBITDA	$	253.4	$	6.4	$	(13.5	)	$	246.3


	Three Months Ended June 30, 2011
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	74.2	$	4.7	$	(121.0	)	$	(42.1	)
Adjustments:
Interest expense		—		—		10.2			10.2
Income tax benefit		—		—		(0.1	)		(0.1	)
Depreciation and amortization		5.5		2.1		—			7.6

EBITDA subtotal		79.7		6.8		(110.9	)		(24.4	)
Minnesota Pipe Line proportionate EBITDA		0.9		—		—			0.9
Turnaround and related expenses		19.2		—		—			19.2
Equity-based compensation expense		—		—		0.4			0.4
Unrealized losses on derivative activities		—		—		31.0			31.0
Contingent consideration income		—		—		(9.2	)		(9.2	)
Formation costs		—		—		1.9			1.9
Realized losses on derivative activities		—		—		81.7			81.7

Adjusted EBITDA	$	99.8	$	6.8	$	(5.1	)	$	101.5


	Six Months Ended June 30, 2012
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	313.6	$	4.0	$	(264.6	)	$	53.0
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		(243.0	)		90.5
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
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


	Six Months Ended June 30, 2011
	Refining		Retail		Other			Total
(in millions)
Net income (loss)	$	152.7	$	2.3	$	(421.6	)	$	(266.6	)
Adjustments:
Interest expense		—		—		20.2			20.2
Depreciation and amortization		10.6		4.0		0.3			14.9

EBITDA subtotal		163.3		6.3		(401.1	)		(231.5	)
Minnesota Pipe Line proportionate EBITDA		1.8		—		—			1.8
Turnaround and related expenses		22.5		—		—			22.5
Equity-based compensation expense		—		—		0.7			0.7
Unrealized losses on derivative activities		—		—		293.9			293.9
Contingent consideration income		—		—		(41.0	)		(41.0	)
Formation costs		—		—		4.4			4.4
Realized losses on derivative activities		—		—		133.9			133.9

Adjusted EBITDA	$	187.6	$	6.3	$	(9.2	)	$	184.7

Other Non-GAAP Performance Measures

Refinery 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.

Refinery gross product margin per barrel is a financial measurement calculated by subtracting refinery costs of sales from total refinery revenues and dividing the difference by the total throughput or total refined products sold for the respective periods presented. Refinery gross product margin is a non-GAAP performance measure that we believe is important to investors in evaluating our refinery performance as a general indication of the amount above our cost of products that we are able to sell refined products. Each of the components used in these calculations (revenues and cost of sales) can be reconciled directly to our statements of operations. Our calculation of refinery 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 for the three and six months ended June 30, 2011 and 2012:


	Three Months Ended,				Six Months Ended,
(in millions)	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011

Refinery revenue	$	1,039.2	$	978.5	$	1,933.7	$	1,823.7
Refinery cost of sales		751.5		839.5		1,523.5		1,558.5

Refinery gross product margin	$	287.7	$	139.0	$	410.2	$	265.2

Retail fuel gross margin and retail merchandise gross margin are non-GAAP performance measures that we believe are important to investors in evaluating our retail performance. Our calculation of retail fuel margin and retail merchandise margin may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.

The following table shows the reconciliation of retail gross margin to retail segment operating income for the three and six months ended June 30, 2011 and 2012:


	Three Months Ended,				Six Months Ended,
(in millions)	June 30, 2012		June 30, 2011		June 30, 2012		June 30, 2011

Retail gross margin:
Fuel margin	$	16.9	$	17.8	$	30.2	$	29.9
Merchandise margin		22.6		21.8		43.0		41.0
Other margin		3.0		4.7		6.1		8.4


Retail gross margin		42.5		44.3		79.3		79.3
Expenses:
Direct operating expenses		29.8		30.9		59.2		60.5
Depreciation and amortization		1.6		2.1		3.8		4.0
Selling, general and administrative		6.3		6.6		12.3		12.5


Retail segment operating income	$	4.8	$	4.7	$	4.0	$	2.3

Liquidity and Capital Resources

Our primary sources of liquidity have traditionally been cash generated from our operating activities and the borrowing availability under our revolving credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing and selling sufficient quantities of refined products and merchandise at margins sufficient to cover fixed and variable expenses.

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 working capital, capital expenditures, any debt service and other cash requirements for at least the next twelve months.

We 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. The cash payments for the settlement of these derivative instruments have been deferred and will begin to come due in December 2012. 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 plan to use a portion of the net proceeds of the NTE LP offering to settle this obligation. As of June 30, 2012, $118.0 million of the liability related to these actions is included in current liabilities and $18.8 million is included in non-current liabilities with the final amount to be paid in December 2013.

On July 17, 2012, the Company entered into an amendment of its existing revolving credit facility. The amendment to the revolving credit facility, 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 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 amendment to the revolving credit facility). In connection with the removal of this requirement, the amendment to the revolving credit 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, we must comply with a minimum Fixed Charge Coverage Ratio (as defined in the amendment to the revolving credit facility) of at least 1.0 to 1.0. As of July 14, 2012, the borrowing base under the revolving credit facility was $195.4 million, availability under the revolving credit facility was $133.9 million (which is net of $61.6 million in outstanding letters of credit) and the Company had no borrowings under the revolving credit facility. As of July 14, 2012, the springing financial covenant described above would apply if availability under the revolving credit facility were less than $24.4 million, which means that we could increase borrowings under the revolving credit facility by $109.5 million before the Company would be required to comply with the minimum Fixed Charge Coverage Ratio.

Cash Flows

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


	Six Months Ended,
	June 30, 2012			June 30, 2011
(in millions)
Net cash provided by operating activities	$	99.9		$	133.8
Net cash used in investing activities		(12.4	)		(128.7	)
Net cash used in financing activities		(40.0	)		—

Net increase in cash and cash equivalents		47.5			5.1
Cash and cash equivalents at beginning of period		123.5			72.8

Cash and cash equivalents at end of period	$	171.0		$	77.9

Net Cash Provided By Operating Activities. 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 operating income ($228.4 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($16.3 million) and non-cash contingent consideration loss ($65.8 million). Offsetting these impacts were realized losses from derivative activities ($120.3 million), increases in accounts receivable ($57.4 million) and decreases in accounts payable and accrued expenses ($27.8 million).

Net cash provided by operating activities for the six months ended June 30, 2011 was $133.8 million. The most significant providers of cash were operating income ($181.4 million) adjusted for non-cash adjustments, such as depreciation and amortization ($14.9 million) and contingent consideration income ($41.0 million). Additionally, cash was provided by reduced other current assets ($22.1 million) and increased accounts payable and accrued expenses ($108.0 million). Offsetting these sources of cash were realized losses from derivative activities ($133.9 million).

Net Cash Used In Investing Activities. Net cash used in investing activities for the six months ended June 30, 2012 was $12.4 million, relating solely to capital expenditures.

Net cash used in investing activities for the six months ended June 30, 2011 was $128.7 million, relating primarily to capital expenditures ($16.1 million) and cash paid to Marathon as part of the Marathon Acquisition ($112.8 million).

Net Cash Used In Financing Activities. Net cash used in financing activities for the six months ended June 30, 2012 was $40.0 million, relating to an equity distribution to Northern Tier Holdings in the second quarter of 2012.

Working Capital

Working capital at June 30, 2012 was $136.6 million, consisting of $528.1 million in total current assets and $391.5 million in total current liabilities.

Capital Spending

Capital spending was $12.4 million for the six months ended June 30, 2012, respectively, which primarily included safety related enhancements and facility improvements at the refinery and the implementation of our new information and accounting systems. We currently expect to spend approximately $40 million in capital expenditures during 2012.

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., refinery gross product margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The timing, direction and overall change in refined product prices versus crude oil prices will impact profit margins and could have a significant impact on our earnings and cash flows. Assuming all other factors remained constant, a $1 per barrel change in our average refinery gross product margin, based on our average refinery throughput for the six months ended June 30, 2012 of 78,659 bpd, would result in a change of $28.7 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 will seek to reduce the volatility of our cash flows by hedging a significant and operationally reasonable volume of our gasoline and diesel production. We 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 JPM CCC allows us to take title to, and price, our crude oil at the refinery, as opposed to the crude oil origination point, reducing the time we are exposed to market fluctuations before the finished refined products are sold. Furthermore, this agreement enables us to mitigate potential working capital fluctuations relating to crude oil price volatility.

Basis Risk

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

Commodities Price and Basis Risk Management Activities

We have entered into the 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 agreement, 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, 2012, we have hedged approximately 12 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.

During the first quarter of 2012, we settled contracts covering approximately 3 million barrels of our remaining 2012 gasoline and diesel production and recognized a loss of $44.6 million. Our required payment of the majority of the loss from these settled contracts has been deferred until 2013. In addition, during the second quarter of 2012, we reset the price of our remaining contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92 million. We plan to use approximately $92 million of the net proceeds of the initial public offering of NTE LP to settle a portion of these obligations.

Our open positions at June 30, 2012 will expire at various times during 2012 and 2013. We prepared a sensitivity analysis to estimate our exposure to market risk associated with our derivative instruments. This analysis may differ from actual results. Based on our open positions of 12 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 (loss) earnings by approximately $12 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 rates, 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, 2012, the availability under the Initial ABL Facility was $113.4 million. This availability is net of $61.6 million in outstanding letters of credit. We had no borrowings under the Initial ABL Facility at June 30, 2012. Borrowings under the Initial ABL Facility bore interest, at our election, at either an alternative base rate, plus an applicable margin (which ranges between 1.75% and 2.25% pursuant to a grid based on average excess availability) or a LIBOR rate, plus an applicable margin (which ranges between 2.75% and 3.25% pursuant to a grid based on average excess availability). See note 12 – “Debt,” to the unaudited consolidated financial statements included herein.

On July 17, 2012, the Company entered into an amendment of its Initial ABL Facility. Borrowings under the amended revolving credit 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) 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.

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

Credit Risk

We are subject to risk of losses resulting from nonpayment or nonperformance by our 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.

Item 4. Controls and Procedures

(a)

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”), we have evaluated, under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our 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 Form 10-Q. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, 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 SEC. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of June 30, 2012 at the reasonable assurance level.

(b)

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the six months ended June 30, 2012 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

None

Item 1A. Risk Factors

There have been no material changes in our risk factors from those disclosed in our form S-4/A filed on May 11, 2012 or in our quarterly report on Form 10-Q for the three months ended March 31, 2012, filed on June 28, 2012.

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.

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.


Date	August 9, 2012	By:	/s/ Mario E. Rodriguez
			Mario E. Rodriguez
			Chief Executive Officer and Director (Principal Executive Officer)

Date	August 9, 2012	By:	/s/ David Bonczek
			David Bonczek
			Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)

EXHIBIT INDEX


Exhibit Number		Description

10.1*		Settlement Agreement and Release by and between Marathon Petroleum Company LP and Northern Tier Energy LLC (Incorporated by reference to Exhibit 10.14 to Northern Tier Energy Inc.’s Registration Statement on Form S-1 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 10.1 to the Current Report on Form 8-K filed on July 18, 2012).

10.3*		Transaction Agreement 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 the Current Report on Form 8-K filed on July 30, 2012).

31.1		Certification of Mario E. Rodriguez, Chief Executive Officer of Northern Tier Energy LLC

31.2		Certification of David Bonczek, Chief Financial Officer of Northern Tier Energy LLC

32.1**		Certification pursuant to Section 1350 of Chapter 63 of Title 18 of the United States Code (18 U.S.C. 1350) of Mario E. Rodriguez, Chief Executive Officer

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

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.

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Northern Tier Energy LLC 10-Q