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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: March 31, 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		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 QUARTER ENDED MARCH 31, 2012

TABLE OF CONTENTS


CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS			3

PART I – FINANCIAL INFORMATION
	ITEM 1.	Financial Statements	4
	ITEM 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	21
	ITEM 3.	Quantitative and Qualitative Disclosures About Market Risk	36
	ITEM 4.	Controls and Procedures	37

PART II – OTHER INFORMATION
	ITEM 1.	Legal Proceedings	38
	ITEM 1A.	Risk Factors	38
	ITEM 2.	Unregistered Sales of Equity Securities and Use of Proceeds	38
	ITEM 3.	Defaults Upon Senior Securities	38
	ITEM 4.	Mine Safety Disclosures	38
	ITEM 5.	Other Information	38
	ITEM 6.	Exhibits	38

SIGNATURES			39

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 and (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).

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)


	March 31, 2012			December 31, 2011
	(Unaudited)
ASSETS
CURRENT ASSETS
Cash and cash equivalents	$	64.1		$	123.5
Receivables, less allowance for doubtful accounts		126.6			81.9
Inventories		163.6			154.1
Other current assets		59.5			65.5

Total current assets		413.8			425.0

NON-CURRENT ASSETS
Equity method investment		89.2			89.9
Property, plant and equipment, net		388.4			391.2
Intangible assets		35.4			35.4
Other assets		35.9			57.3

Total Assets	$	962.7		$	998.8

LIABILITIES AND EQUITY

CURRENT LIABILITIES
Accounts payable	$	176.2		$	207.4
Accrued liabilities		77.4			30.3
Derivative liability		185.5			109.9

Total current liabilities		439.1			347.6

NON-CURRENT LIABILITIES
Long-term debt		290.0			290.0
Lease financing obligation		11.9			11.9
Derivative liability		12.5			—
Other liabilities		90.2			37.1

Total liabilities		843.7			686.6

Commitments and contingencies

EQUITY
Comprehensive loss		(0.4	)		(0.4	)
Member’s interest		119.4			312.6

Total Liabilities and Equity	$	962.7		$	998.8

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

NORTHERN TIER ENERGY LLC

CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE LOSS

(in millions, unaudited)


	Three Months Ended
	March 31, 2012			March 31, 2011
REVENUE ^(a)	$	999.1		$	940.2

COSTS, EXPENSES AND OTHER
Cost of sales^(a)		839.8			779.0
Direct operating expenses		60.7			61.9
Turnaround and related expenses		3.5			3.3
Depreciation and amortization		8.5			7.3
Selling, general and administrative		20.3			18.4
Formation costs		—			2.5
Contingent consideration loss (income)		65.7			(31.8	)
Other income, net		(2.1	)		(1.1	)

OPERATING INCOME		2.7			100.7

Realized losses from derivative activities		(52.9	)		(52.2	)
Loss on early extinguishment of derivatives		(44.6	)		—
Unrealized losses from derivative activities		(88.4	)		(262.9	)
Interest expense, net		(10.4	)		(10.0	)

LOSS BEFORE INCOME TAXES		(193.6	)		(224.4	)

Income tax provision		—			(0.1	)

NET LOSS AND COMPREHENSIVE LOSS	$	(193.6	)	$	(224.5	)


^(a) Excise taxes included in revenue and cost of sales	$	65.6		$	56.7

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

NORTHERN TIER ENERGY LLC

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions, unaudited)


	Three Months Ended
Increase (decrease) in cash	March 31, 2012			March 31, 2011
CASH FLOWS FROM OPERATING ACTIVITIES
Net loss	$	(193.6	)	$	(224.5	)
Adjustments to reconcile net loss to net cash (used in) provided by operating activities:
Depreciation and amortization		8.5			7.3
Stock-based compensation expense		0.4			0.3
Contingent consideration loss (income)		65.7			(31.8	)
Unrealized loss from derivative activities		88.4			262.9
Loss on early extinguishment of derivatives		44.6			—
Changes in assets and liabilities, net:
Accounts receivable		(45.0	)		18.5
Inventories		(9.5	)		(40.0	)
Other current assets		8.8			19.9
Accounts payable and accrued expenses		(23.5	)		81.0
Other, net		0.4			0.7

Net cash (used in) provided by operating activities		(54.8	)		94.3

CASH FLOWS FROM INVESTING ACTIVITIES
Capital expenditures		(5.4	)		(6.0	)
Acquisition, net of cash acquired		—			(112.8	)
Return of capital from investments		0.8			1.0

Net cash used in investing activities		(4.6	)		(117.8	)

CASH FLOWS FROM FINANCING ACTIVITIES
Other financing activities, net		—			—

Net cash provided by financing activities		—			—

CASH AND CASH EQUIVALENTS
Change in cash and cash equivalents		(59.4	)		(23.5	)
Cash and cash equivalents at beginning of period		123.5			72.8

Cash and cash equivalents at end of period	$	64.1		$	49.3

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 is a wholly owned subsidiary of Northern Tier Holdings LLC (“NT Holdings” or the “Member”). NT Holdings is wholly owned by Northern Tier Investors LLC (“NTI”). Additionally, NT Holdings has issued preferred stock that is 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. NTI, 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 subsidiaries of Marathon Petroleum. Effective December 1, 2010, the Company acquired the business from Marathon for approximately $608 million (the “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).

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 three months ended March 31, 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 in the Prospectus.

2. SUMMARY OF PRINCIPAL ACCOUNTING POLICIES

Principles of Consolidation and Combination

The Company was incorporated on June 23, 2010. NTI entered into the Acquisition agreement with Marathon on October 6, 2010 and closed the Acquisition 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 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. Income from equity method investment represents the Company’s proportionate share of net income available to common 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 7 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 March 31, 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 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, including 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 19 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 $65.6 million and $56.7 million for the three months ended March 31, 2012 and 2011, respectively.

Income Taxes

The Company and its subsidiaries are limited liability companies and are therefore pass-through entities for income tax purposes. As a result, the Company does not incur federal income taxes.

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.

3. 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 Acquisition (see Note 4), 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 Acquisition, the Company entered into a management services agreement with the Investors pursuant to which they provide the Company with ongoing management, advisory and consulting services. The Investors also receive 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 also pays the Investors’ specified success fees in connection with advice they provide in relation with certain corporate transactions. The Company incurred management fees relating to these services of $0.5 million for both the three months ended March 31, 2012 and 2011.

4. ACQUISITION

As previously described in Note 1, effective December 1, 2010, the Company acquired the business from MPC for $608 million. The 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 $608 million purchase price, $361 million was paid in cash as of December 31, 2010 and $80 million was satisfied by issuing MPC a perpetual payment in kind preferred interest in NT Holdings. The residual purchase price of $113 million (excluding the contingent earn-out consideration) was paid during the three months ended March 31, 2011.

The Company would be required to pay Marathon the earn-out payments if the Company’s Adjusted EBITDA (as defined in the agreement, the “Agreement Adjusted EBITDA”) exceeds $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 next eight years following the Acquisition. Agreement Adjusted EBITDA adjusts for, among other items, (i) any unrealized gains or losses relating to derivative activities, (ii) any gains or losses generated by the liquidation of any LIFO inventory layers, (iii) any losses related to lower of cost or market inventory adjustments, and (iv) any gains on the sale of property, plant or equipment and certain other assets. Marathon would receive 40% of the amount by which Agreement Adjusted EBITDA exceeds the specified threshold in any year during the eight years following the Acquisition not to exceed $125 million over the eight years following the Acquisition. The Acquisition agreement also includes a margin support component that would require Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA is 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 we may be required to pay Marathon over the earn-out period (see Note 18). Subsequent fair value adjustments to these collective contingent consideration arrangements (earn-out arrangement and margin support arrangement) will be recorded in the statement of income based on quarterly remeasurements. See Note 12 for further information on the Company’s fair value measurements and Note 20 regarding a potential settlement of the arrangements reached subsequent to March 31, 2012.

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 11 for a description of the Company’s financing arrangements.

Concurrent with the 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 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.

MPC agreed to provide the Company with administrative and support services subsequent to the 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 months ended March 31, 2011, the Company recognized expenses of approximately $7.7 million related to administrative and support services. The Company also paid $6.7 million in December 2010 of which $1.7 million was amortized during the three months ended March 31, 2011. The majority of transition services were completed as of December 31, 2011 and, as such, the three months ended March 31, 2012 include no transition service charges from Marathon.

5. INCOME TAXES

For the period subsequent to the Acquisition, the Company is a pass through entity for federal income tax purposes. As a result, there are no federal income taxes incurred. For the three months ended March 31, 2012 and 2011, the Company incurred state income taxes of less than $0.1 million and $0.1 million, respectively.

6. INVENTORIES


(in millions)	March 31, 2012		December 31, 2011
Crude oil and refinery feedstocks	$	5.5	$	9.1
Refined products		123.7		109.1
Merchandise		20.7		21.1
Supplies and sundry items		13.7		14.8

Total	$	163.6	$	154.1

The LIFO method accounted for 79% and 77% of total inventory value at March 31, 2012 and December 31, 2011, respectively. Current acquisition costs were estimated to exceed the LIFO inventory value by $12.8 million and $20.0 million at March 31, 2012 and December 31, 2011, respectively.

7. EQUITY METHOD INVESTMENT

The Company has a 17% common interest in Minnesota Pipe Line. The carrying value of this equity method investment was $89.2 million and $89.9 million at March 31, 2012 and December 31, 2011, respectively.

As of March 31, 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 $3.4 million and $2.2 million for the three months ended March 31, 2012 and 2011, respectively. Equity income from Minnesota Pipe Line was $2.8 million and $1.4 million for the three months ended March 31, 2012 and 2011, respectively.

8. PROPERTY, PLANT AND EQUIPMENT

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


(in millions)	Estimated Useful Lives	March 31, 2012		December 31, 2011
Land		$	8.7	$	8.7
Retail stores and equipment	2 - 22 years		50.9		50.4
Refinery and equipment	5 - 24 years		324.8		318.1
Software	5 years		15.8		14.7
Other equipment	2 - 7 years		2.3		1.9
Precious metals			10.5		10.5
Assets under construction			14.2		17.4

			427.2		421.7
Less: accumulated depreciation			38.8		30.5

Property, plant and equipment, net		$	388.4	$	391.2

PP&E included gross assets acquired under capital leases of $12.0 million and $12.5 million at March 31, 2012 and December 31, 2011, respectively, with related accumulated depreciation of $0.9 million and $1.4 million, respectively.

9. INTANGIBLE ASSETS

Intangible assets were ascribed value as a result of the Acquisition and are comprised of franchise rights amounting to $19.8 million and trademarks amounting to $15.6 million at both March 31, 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.

10. 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 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 caption on the consolidated statements of income. Observable quoted prices for similar assets or liabilities in active markets (Level 2 as described in Note 12) are considered to determine the fair values for the purpose of marking to market the derivative instruments at each period end. At March 31, 2012 and December 31, 2011, the Company had open commodity derivative instruments consisting of crude oil futures to buy 15 million and 17 million barrels, respectively, and refined products futures and swaps to sell 15 million and 17 million barrels, respectively, primarily to protect the value of refining margins through 2012 and 2013. For the three months ended March 31, 2012 and 2011, there were losses related to derivative activities of $185.9 million and $315.1 million, respectively. Of these total losses, $97.5 million and $52.2 million represented realized losses on settled contracts (including early extinguishments as noted below) and $88.4 million and $262.9 million represented unrealized losses on open contracts for the three months ended March 31, 2012 and 2011, respectively.

The Company has entered into arrangements to settle 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 December 2012 and continue through December 2013. The early extinguishments are treated as a current period loss as of the date of extinguishment. During the three months ended March 31, 2012, the Company incurred $44.6 million of realized losses related to these early extinguishments. Interest accrues on the early extinguishment liability at a weighted average interest rate of 5.5%. Interest expense related to these liabilities in the quarter ended March 31, 2012 was $0.4 million.

The following table summarizes the fair value amounts of the Company’s outstanding derivative instruments by location on the balance sheet as of March 31, 2012 and December 31, 2011:


(in millions)	Balance Sheet Classification	March 31, 2012		December 31, 2011
Commodity swaps and futures	Current liabilities	$	185.5	$	109.9
Commodity swaps and futures	Noncurrent liabilities		12.5		—

		$	198.0	$	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 as of March 31, 2012 of at least A- by Standard and Poor’s and A2 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 11) 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.

11. DEBT

In connection with the 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 (“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. 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

The ABL Facility provides for revolving credit financing through December 1, 2015 in an aggregate principal amount of up to $300 million (of which $150 million may be utilized for the issuance of letters of credit and up to $30 million may be short-term borrowings upon same-day notice, referred to as swingline loans) and may be increased up to a maximum aggregate principal amount of $400 million, subject to borrowing base availability and lender approval. Availability under the ABL Facility at any time will be the lesser of (a) the aggregate commitments under the ABL Facility or (b) the borrowing base, less any outstanding borrowings and letters of credit. The borrowing base is calculated based on a percentage of eligible accounts receivable, petroleum inventory and other assets.

Borrowings under the ABL Facility bear interest, at the Company’s option, at either (a) an alternative base rate, plus an applicable margin (ranging between 1.75% and 2.25%) or (b) a LIBOR rate plus applicable margin (ranging between 2.75% and 3.25%). 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 0.625% and letter of credit fees.

As of March 31, 2012 and December 31, 2011, the availability under the ABL Facility was $156.7 million and $108.0 million, respectively. This availability is net of $61.6 million in outstanding letters of credit at both March 31, 2012 and December 31, 2011. The Company had no borrowings under the ABL Facility at March 31, 2012 or December 31, 2011.

The ABL Facility has a minimum fixed charge coverage ratio financial covenant requirement of at least 1.0 to 1.0. The covenant is operative when the Company’s availability under the facility is 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 ABL Facility also contains a number of covenants that, among other things, restrict, 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.

12. 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 March 31, 2012 and December 31, 2011:


	Balance at March 31, 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	$	64.1	$	64.1	$	—	$	—
Other assets
Contingent consideration - margin support		2.8		—		—		2.8

	$	66.9	$	64.1	$	—	$	2.8

LIABILITIES
Derivative liability - current	$	185.5	$	—	$	185.5	$	—
Derivative liability - long-term		12.5		—		12.5		—
Accrued liabilities
Contingent consideration - earn-out		31.7		—		—		31.7
Other liabilities
Contingent consideration - earn-out		47.5		—		—		47.5

	$	277.2	$	—	$	198.0	$	79.2


	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

The Company determines 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 are recorded in the statements of income as contingent consideration income, net. The Company recorded a $65.7 million non-cash charge during the three months ended March 31, 2012 and $31.8 million of contingent consideration income during the three months ended March 31, 2011 related to changes in the fair value of the Company’s Level 3 contingent consideration arrangements.

Our contingent consideration agreements (margin support and earn out) are reported at fair value using Level 3 inputs due to such agreements not having observable market prices. The fair value of the agreements are determined based on a Monte Carlo simulation prepared by a third party service provider using management projections of future period EBITDA levels.

The significant unobservable inputs used in the fair value measurement of our Level 3 agreements are the management projections of EBITDA. In developing these management projections, the Company uses the forward market prices for various crude oil types, other feedstocks and refined products and applies 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 result 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 three months ended March 31, 2012 and 2011, there were no adjustments to the fair value of such assets. The Company recorded assets acquired and liabilities assumed in the 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).


	March 31, 2012				December 31, 2011
(in millions)	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Secured Notes	$	290.0	$	319.7	$	290.0	$	316.5

13. ASSET RETIREMENT OBLIGATIONS

The following table summarizes the changes in asset retirement obligations:


(in millions)	Three months Ended March 31, 2012		Three months Ended March 31, 2011
Asset retirement obligation balance at beginning of period	$	1.5	$	2.1
Accretion expense (included in depreciation and amortization)		0.1		0.1

Asset retirement obligation balance at end of period	$	1.6	$	2.2

14. STOCK-BASED COMPENSATION

NTI sponsors an equity participation plan which provides for the grant of profit interest units to certain employees and independent non-employee directors of the Company. The plan has reserved approximately 29 million units for issuance under the plan. The exercise price for a unit shall not be less than 100% of the fair market value of our equity units on the date of grant. 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.

A summary of profit interest unit activity is set forth below:


	Number of Units (in millions)		Weighted Average Exercise Price		Weighted Average Remaining Contractual Term
Outstanding at December 31, 2011		24.2	$	1.87		9.2
Granted		1.2		2.70

Outstanding at March 31, 2012		25.4	$	1.91		8.8

The estimated weighted average fair value as of the grant date for units granted during the three months ended March 31, 2012 and 2011 were $0.88 and $0.35, 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 March 31, 2012 and 2011, the total unrecognized compensation cost for profit interest units was $7.7 million and $6.7 million, respectively. This non-cash expense will be recognized on a straight-line basis through 2016.

15. DEFINED BENEFIT PLAN

During 2011, the Company also began to sponsor 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 three months ended March 31, 2011. The net periodic benefit cost related to the Cash Balance Plan for the three months ended March 31, 2012 of $0.4 million related primarily to current period service costs.

16. SUPPLEMENTAL CASH FLOW INFORMATION

Supplemental cash flow information is as follows:


	Three Months Ended
(in millions)	March 31, 2012		March 31, 2011
Net cash from operating activities included:
Interest paid	$	1.1	$	1.0
Noncash investing and financing activities include:
Capital expenditures included in accounts payable	$	—	$	0.8

17. LEASING ARRANGEMENTS

As described in Note 4, concurrent with the 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 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.

18. 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 4, the Acquisition provides for contingent consideration, or earn-out payments, that could result 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 Acquisition agreement also includes a margin support component that requires Marathon to pay the Company up to $30 million per year to the extent the Agreement Adjusted EBITDA is 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 will increase the amount that we may be required to pay Marathon over the earn-out period. See Note 12 for additional information relating to the fair value of contingent arrangements related to the Acquisition. In addition to the estimated values related to future periods discussed in Note 12, the Company has recorded a receivable of $30.0 million as of March 31, 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 has disputed approximately $12 million of this amount. Subsequent to March 31, 2012, the Company reached a potential settlement on this dispute (see Note 20).

Environmental Matters

The Company is subject to federal, state, local and foreign laws and regulations relating to the environment. These laws generally provide for control of pollutants released into the environment and require responsible parties to undertake remediation of hazardous waste disposal sites. Penalties may be imposed for noncompliance. At March 31, 2012 and December 31, 2011, liabilities for remediation totaled $4.7 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 March 31, 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 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.

19. 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, including 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)	Refining		Retail			Other			Total
Three months ended March 31, 2012

Revenues
Customer	$	654.5	$	344.6		$	—		$	999.1
Intersegment		240.0		—			—			240.0

Segment revenues		894.5		344.6			—			1,239.1
Elimination of intersegment revenues		—		—			(240.0	)		(240.0	)

Total revenues	$	894.5	$	344.6		$	(240.0	)	$	999.1

Income (loss) from operations	$	78.7	$	(0.4	)	$	(75.6	)	$	2.7

Income from equity method investment	$	2.8	$	—		$	—		$	2.8

Depreciation and amortization	$	5.8	$	1.8		$	0.9		$	8.5

Capital expenditures	$	4.9	$	0.3		$	0.2		$	5.4


(in millions)	Refining		Retail			Other			Total
Three months ended March 31, 2011

Revenues
Customer	$	599.5	$	340.7		$	—		$	940.2
Intersegment		245.7		—			—			245.7

Segment revenues		845.2		340.7			—			1,185.9
Elimination of intersegment revenues		—		—			(245.7	)		(245.7	)

Total revenues	$	845.2	$	340.7		$	(245.7	)	$	940.2

Income (loss) from operations	$	78.5	$	(2.4	)	$	24.6		$	100.7

Income from equity method investment	$	1.4	$	—		$	—		$	1.4

Depreciation and amortization	$	5.1	$	1.9		$	0.3		$	7.3

Capital expenditures	$	5.0	$	0.1		$	0.9		$	6.0

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

Total assets by segment were as follows:


(in millions)	Refining		Retail		Other		Total
At March 31, 2012	$	682.8	$	133.7	$	146.2	$	962.7

At December 31, 2011	$	655.2	$	219.8	$	123.8	$	998.8

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

20. SUBSEQUENT EVENTS

On June 4, 2012, Northern Tier Energy LP, an affiliate of the Company, was formed. Northern Tier Energy LP has a registration statement on Form S-1 filed with the Securities and Exchange Commission in anticipation of an initial public offering.

On May 4, 2012, the Company entered into a settlement agreement with Marathon in connection with the contingent consideration agreement (see Note 18). Under the terms of this settlement agreement, Marathon will receive $40 million of the net proceeds from Northern Tier Energy LP’s initial public offering, and NT Holdings will redeem Marathon’s existing preferred interest with a portion of the net proceeds from this offering and issue 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 has also agreed, pursuant to the settlement agreement, to relinquish all claims to margin support payments under the contingent consideration agreement. The settlement agreement is contingent upon the consummation of Northern Tier Energy LP’s initial public offering by no later than December 31, 2012.

On May 22, 2012 the Company paid an equity distribution in cash to NT Holdings in the amount of $40.0 million.

During the second quarter of 2012, the Company reset the price of its derivative contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92 million. The Company plans to use a portion of the net proceeds of the initial public offering of Northern Tier Energy LP to settle this obligation. If this offering is not completed, the loss from resetting the price of the derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

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

The following information should be read in conjunction with our unaudited condensed consolidated financial statements and accompanying notes included in this report. The following information and such unaudited condensed consolidated financial statements should also be read in conjunction with the consolidated and combined financial statements and related notes, together with our discussion and analysis of financial condition and results of operations, included in the Prospectus.

The following discussion contains “forward-looking statements” that reflect our future plans, estimates, beliefs and expected performance. Our actual results may differ materially from those currently anticipated and expressed in such forward-looking statements as a result of a number of factors. We caution that assumptions, expectations, projections, intentions or beliefs about future events may, and often do, vary from actual results and the differences can be material. See “Cautionary Note Regarding Forward-Looking Statements.”

Overview

We are an independent downstream energy 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 three months ended March 31, 2012, we had total revenues of $1.0 billion, operating income of $2.7 million, a net loss of $193.6 million and Adjusted EBITDA of $81.5 million. A definition, and reconciliation, of Adjusted EBITDA to net (loss) earnings, is included herein.

Refining Business

Our refining business primarily consists of a 74,000 bpd (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 oil from Western Canada and North Dakota, as well as the ability to distribute our refined products throughout the midwestern United States. Our refinery produces a broad slate of refined products including gasoline, diesel, jet fuel and asphalt, which are then marketed to resellers and consumers primarily in the PADD II region. Approximately 83% and 79% of our total refinery production for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, comprised higher value, light refined products, including gasoline and distillates. Our refinery crude capacity utilization rates have ranged from approximately 80% to approximately 90% over the last five years.

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. Approximately 70% and 83% of our gasoline and diesel volumes for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, were sold via our light products terminal located at the refinery to our company-operated and franchised SuperAmerica branded convenience stores, Marathon branded convenience stores and other resellers. We have a contract with Marathon to supply substantially all of the gasoline and diesel requirements for 90 independently owned and operated Marathon branded convenience stores.

Our refining business also includes our 17% interest in Minnesota Pipe Line and MPLI, which owns and operates the Minnesota Pipeline, a 455,000 bpd crude oil pipeline system that transports crude oil (primarily from Western Canada and North Dakota) for approximately 300 miles from the Enbridge pipeline hub at Clearbrook, Minnesota to our refinery. The Minnesota Pipeline has historically transported the majority of the crude oil used and processed in our refinery.

Retail Business

As of March 31, 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 immediately consumable items such as non-alcoholic beverages, beer, prepared food and a large variety of snacks and prepackaged items. Our refinery supplied substantially all of the gasoline and diesel sold in our company-operated and franchised convenience stores for the three months ended March 31, 2012 and 2011.

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.

Outlook

Transportation fuels demand in the Upper Great Plains of the PADD II region currently exceeds supply from local refineries. Therefore, demand is fulfilled by products that are imported into the region mostly via pipeline from other parts of the Midwest, the Rocky Mountains and the U.S. Gulf Coast. Overall refined product demand declined in 2008 as a result of prevailing economic conditions and began to improve in the first quarter of 2010. While there continues to be significant global macroeconomic risk that may affect the pace of growth in the United States, we have experienced improved overall product demand in our geographic area of operations relative to prior years.

Our operating performance has benefited from the widening of the price relationship between the traditional crude oil pricing benchmark, NYMEX WTI, and the international waterborne crude oil pricing benchmark, Brent. We purchase crude oil which is priced based off NYMEX WTI. Refined products prices are set by global markets and are typically priced off Brent. Therefore, we have enjoyed a benefit during the year ended December 31, 2011 and the first quarter of 2012 from the overall widening of the price differential between our cost of crude oil and the price of the products we sell. The widening differential may have been attributable to several factors, including geopolitical events in the Middle East, the suspension of crude oil exports from Libya, new U.N. sanctions on Iran’s oil exports, and limited pipeline and other infrastructure to transport crude oil from Cushing, Oklahoma, where NYMEX WTI is settled, to alternative markets. More recently, during the beginning of the second quarter of 2012, the discount to which NYMEX WTI trades relative to Brent has narrowed due to a number of factors, including recently announced changes in the pipeline infrastructure serving Cushing, Oklahoma. The narrowing of this margin may affect the prices at which we sell our refined products relative to our cost of crude oil and may therefore cause a reduction in our refining margins.

Major Influences on Results of Operations

Refining

Our earnings and cash flows from our refining business segment are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Refining is primarily a margin-based business, and in order to increase profitability, it is important for the refinery to maximize the yields of high value finished products and to minimize the costs of feedstock and operating expenses. Feedstocks are petroleum products, such as crude oil and natural gas liquids that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on several factors, many of which are beyond our control, including the supply of, and demand for, crude oil, gasoline and other refined products, which depend on changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, availability of and access to transportation infrastructure, the availability of imports, the marketing of competitive fuel, and the extent of government regulation, among other factors.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a negative impact on product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. In addition to current market conditions, there are long-term factors that may impact the demand for refined products. These factors include mandated renewable fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

In order to assess our operating performance, we compare our refinery gross product margin against an industry refining margin benchmark. The industry refining margin benchmark we use is referred to as Group 3 3:2:1 crack spread, which is calculated by assuming that three barrels of benchmark light sweet crude oil is converted into two barrels of reformulated gasoline and one barrel of ultra low sulfur diesel. Because we calculate the benchmark refining margin using the market value of PADD II Group 3 conventional gasoline and ultra low sulfur diesel against the market value of NYMEX WTI, we refer to the benchmark as the Group 3 3:2:1 crack spread. The Group 3 3:2:1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold at PADD II Group 3 prices the benchmark production of gasoline and ultra low sulfur diesel.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include employee and contract labor, maintenance and energy. Our predominant variable direct operating cost is energy, which is comprised primarily of fuel and other utility services. The costs of fuel, principally natural gas, and other utility services, principally electricity, used by our refinery and other operations have historically been volatile.

Consistent, safe and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform needed maintenance, contractual commitments, feedstock logistics and other factors. Periodically, we have planned maintenance turnarounds at our refinery, which are expensed as incurred. The refinery generally undergoes a major facility turnaround every five to six years, and the last full plant turnaround was completed in 2007. The length of the turnaround is contingent upon the scope of work to be completed. A major turnaround of either of the two main refinery units (fluid catalytic cracking unit and alkylation unit) generally takes two to four weeks to complete, and is planned and accomplished in a manner that allows for reduced production during maintenance instead of a complete shutdown. We completed a partial turnaround in April 2011, principally to replace a catalyst in the distillate and gas oil hydrotreaters, and to conduct basic maintenance on the No. 1 crude unit. At the end of March 2012, we started a planned turnaround of the alkylation unit that was completed according to schedule in mid May 2012. The next major turnaround is scheduled for 2013.

Because petroleum feedstocks and products are essentially commodities, we have no control over the changing market. Therefore, the lower the target inventory we are able to maintain, the lesser is the impact of commodity price volatility on our petroleum product inventory position. Our inventory of crude oil and refined products is valued at the lower of cost or market value under the LIFO cost flow assumption. For periods in which the market price declines below our LIFO cost basis, we are subject to significant fluctuations in the recorded value of our inventory and related cost of products sold. No such impacts occurred in the quarters ended March 31, 2012 and 2011.

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

In addition, we may hedge a portion of our gasoline and distillate production with the purpose of ensuring we can meet our fixed cost obligations, service our outstanding debt and other liabilities and meet our capital expenditure obligations. We have entered into agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. As market conditions permit, we have the capacity to hedge our crack spread risk with respect to a portion of the refinery’s projected monthly production of these refined products. Consistent with that policy, as of March 31, 2012, we had hedged approximately 15 million barrels of future gasoline and diesel production, of which 10 million barrels related to 2012 production and the remainder to 2013 production. We intend to hedge significantly less than what we hedged at the time of the Marathon Acquisition on an ongoing basis. Consequently, we plan to increase our exposure to the gross refining margins that we would realize at our refinery on an unhedged basis over time.

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 contracts for the period of July 2012 through December 2012 and recognized a loss of approximately $92 million. We plan to use a portion of the net proceeds of the initial public offering of Northern Tier Energy LP to settle this obligation. If this offering is not completed, the loss from resetting the price of our derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

Our refining business experiences seasonal effects. Demand for gasoline is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic. Decreased demand during the winter months can lower gasoline prices. As a result, our operating results of our refining business for the first and fourth calendar quarters are generally lower than those for the second and third calendar quarters of each year.

Retail

Our earnings and cash flows from our retail business segment are primarily affected by the volumes and margins of gasoline and diesel sold, and by the sales and margins of merchandise sold at our convenience stores. Seasonal fluctuations in traffic also affect sales of motor fuels and merchandise in our convenience stores. As a result, the operating results of our retail segment are generally lower for the first quarter of the year. Weather conditions in our operating area also have a significant effect on our retail operating results. Customers are more likely to purchase higher profit margin items at our convenience stores, such as fast foods, fountain drinks and other beverages and more gasoline during the spring and summer months, thereby typically generating higher revenues and gross margins for us in these periods. Margins for transportation fuel sales are equal to the sales price (which includes the motor fuel taxes) less the delivered cost of the fuel and motor fuel taxes, and are measured on a cents per gallon basis. Fuel margins are impacted by local supply, demand and competition. Margins for retail merchandise sold are equal to retail merchandise sales less the delivered cost of the merchandise, net of any supplier discounts and inventory shrinkage, and are measured as a percentage of merchandise sales. Merchandise sales are impacted by convenience or location, branding and competition. Franchisees are required to pay us an initial license fee (generally, $10,000 for licensees located in Minnesota and Wisconsin and $2,000 for licensees located in South Dakota) and a royalty fee for all products and merchandise sold at the convenience store, including motor fuel and diesel. The initial term of the license is generally 10 years, which is renewable by the licensee for a renewal term of 10 years, subject to the licensee satisfying certain conditions. The license agreements also require that, if a franchise store is located within our distribution area, then the franchise store must purchase a high minimum percentage (often 85% to 100%) of its motor fuel supply, including gasoline and distillate, from us. However, if a franchise store is not located within our distribution area, then the franchise store is not required to purchase any portion of its motor fuel supply from us. As of March 31, 2012, 32 of the 67 existing franchise stores are located within our distribution area and, thus, are required to purchase a high minimum percentage of their motor fuel supply from us.

Results of Operations

We operate our business in two segments: the refining segment and the retail segment. Each of these segments is organized and managed based upon the nature of the products and services they offer. Through the refining segment, we operate the St. Paul Park, Minnesota, refinery, terminal and related assets, and through the retail segment, we operate 166 convenience stores primarily in Minnesota. The retail segment also includes the operations of SuperMom’s Bakery and SAF, through which we conduct our franchising 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.

We refer to our financial statement line items in the explanation of our period over period changes in results of operations. Below are general definitions of what those line items include and represent.

Revenue. Revenue primarily includes the sale of refined products in our refining segment and sales of fuel and merchandise to retail consumers in our retail segment. All sales are recorded net of customer discounts and rebates and inclusive of federal and state excise taxes. Refining revenue includes intersegment sales of refined products to the retail segment. For purposes of presenting sales on a consolidated basis, such intersegment transactions are eliminated. Retail revenue primarily includes sales of fuel and merchandise to customers inclusive of related excise taxes and net of any applicable discounts. Also included in retail revenue is royalty income, revenues from car wash operations and SuperMom’s Bakery sales to third parties.

Cost of sales. Refining cost of sales primarily include costs of crude and refinery feedstocks purchased, ethanol and other refined products purchased and excise taxes paid to various government authorities. Retail cost of sales consists of cost of fuel, merchandise and other products, costs of sales for SuperMom’s Bakery merchandise sales to third parties and excise taxes paid to various government authorities. Retail cost of sales includes intersegment purchases of refined products from the refining segment. For purposes of presenting cost of sales on a consolidated basis, such intersegment transactions are eliminated.

Direct operating expenses. Direct operating expenses include the operating expenses of the refinery and costs of operating the convenience stores and the bakery. Refining direct operating expenses primarily include direct costs of labor, maintenance materials and services, chemicals and catalysts, utilities and other direct operating expenses of the refinery. Retail direct operating expenses consist primarily of salaries, labor and benefits, bankcard processing fees, contracted services, repair and maintenance, utilities and rent expense.

Turnaround and related expenses. Turnaround and related expenses represent the costs of required major maintenance projects on refinery processing units. A turnaround is a standard industry operation to refurbish and maintain a refinery and usually requires the shutdown and inspection of major processing units. Processing units require major maintenance every five to six years.

Depreciation and amortization. Depreciation and amortization represents an allocation to expense within the statement of operations of the carrying value of capital and intangible assets. The value is allocated based on the straight-line method over the estimated useful life of the related asset.

Selling, general and administrative. Selling, general and administrative expenses primarily include corporate costs, administrative expenses, shared service costs and marketing expenses.

Formation costs. Formation costs represent costs incurred in the creation of Northern Tier Energy LLC and its subsidiaries.

Contingent consideration (income) expense. Contingent consideration income (expense) relates to changes in the estimated fair value of our margin support and earn-out arrangements with Marathon.

Other income (expense), net. Other income (expense), net primarily represents income (expense) from our equity method investment in Minnesota Pipe Line and dividend income from our cost method investment in MPLI.

Gain (loss) from derivative activities. Gain (loss) from derivative activities primarily includes impacts from our crack spread risk mitigation strategy initiated in October 2010 in anticipation of the Marathon Acquisition to mitigate market price risk. Included in gain (loss) from derivative activities are realized gains or losses related to settled contracts during the period and unrealized gains or losses on outstanding derivatives to partially hedge the crack spread margins for our refining business. The offsetting benefits related to these unrealized losses should be realized over future periods as improved crack spreads are realized. Going forward, we plan to hedge a lesser amount of our production than we hedged at the time of the Acquisition.

Interest expense, net. Interest expense relates primarily to interest incurred on the notes as well as commitment fees and interest on the ABL Facility and the amortization of deferred financing costs.

The historical financial data presented below are not necessarily indicative of the results to be expected for any future period.

Consolidated Financial Data


	Three Months Ended,
(in millions)	March 31, 2012			March 31, 2011
Revenue	$	999.1		$	940.2

Costs, expenses and other:
Cost of sales		839.8			779.0
Direct operating expenses		60.7			61.9
Turnaround and related expenses		3.5			3.3
Depreciation and amortization		8.5			7.3
Selling, general and administrative		20.3			18.4
Formation costs		—			2.5
Contingent consideration loss (income)		65.7			(31.8	)
Other income, net		(2.1	)		(1.1	)

Operating income		2.7			100.7

Realized losses from derivative activities		(52.9	)		(52.2	)
Early extinguishment of derivatives		(44.6	)		—
Unrealized losses from derivative activities		(88.4	)		(262.9	)
Interest expense, net		(10.4	)		(10.0	)

Loss before income taxes		(193.6	)		(224.4	)

Income tax provision		—			(0.1	)

Net loss	$	(193.6	)	$	(224.5	)

Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

Revenue. Revenue for the three months ended March 31, 2012 was $999.1 million compared to $940.2 million for the three months ended March 31, 2011, an increase of 6.3%. Refining segment revenue increased 5.8% and retail segment revenue increased 1.1% compared to the three months ended March 31, 2011. The refining segment benefited from higher average prices across our principal products driven primarily by increased market prices for refined products offset by lower volumes. Retail revenue also benefited from higher average fuel prices and higher merchandise sales that were partially offset by lower fuel sales volumes. Excise taxes included in revenue totaled $65.6 million and $56.7 million for the three months ended March 31, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $839.8 million for the three months ended March 31, 2012 compared to $779.0 million for the three months ended March 31, 2011, an increase of 7.8%, due primarily to higher priced crude oil and other feedstock costs. Excise taxes included in cost of sales were $65.6 million and $56.7 million for the three months ended March 31, 2012 and 2011, respectively.

Direct operating expenses. Direct operating expenses totaled $60.7 million for the three months ended March 31, 2012 compared to $61.9 million for the three months ended March 31, 2011, a decrease of 1.9%, 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.

Turnaround and related expenses. Turnaround and related expenses totaled $3.5 million for the three months ended March 31, 2012 compared to $3.3 million for the three months ended March 31, 2011. Both periods include costs related to preparation for partial turnarounds planned for the second quarter of each year.

Depreciation and amortization. Depreciation and amortization was $8.5 million for the three months ended March 31, 2012 compared to $7.3 million for the three months ended March 31, 2011, an increase of 16.4%. This increase was primarily due to depreciation of assets placed in service since March 31, 2011 at our refinery and related to our systems implementation project.

Selling, general and administrative expenses. Selling, general and administrative expenses were $20.3 million for the three months ended March 31, 2012 compared to $18.4 million for the three months ended March 31, 2011. This increase of 10.3% from the prior year period relates primarily to higher administrative costs as we continue to incur a significant level of third party systems support during the process optimization portion of our standalone systems implementation.

Formation costs. Formation costs for the three months ended March 31, 2011 were $2.5 million, all attributable to the Marathon Acquisition. We did not incur any such costs in the three months ended March 31, 2012.

Contingent consideration loss (income). Contingent consideration loss was $65.7 million for the three months ended March 31, 2012 compared to contingent consideration income of $31.8 million for the three months ended March 31, 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 $2.1 million for the three months ended March 31, 2012 compared to $1.1 million for the three months ended March 31, 2011. This change was driven primarily by increases in equity income from our investment in Minnesota Pipe Line.

Loss from derivative activities. For the three months ended March 31, 2012, we had realized losses of $52.9 million related to settled contracts compared to $52.2 million in the prior year period. Offsetting benefits related to these losses were recognized through improved operating margins. We incurred unrealized losses on outstanding derivatives of $88.4 million for the three months ended March 31, 2012 compared to $262.9 million during the three months ended March 31, 2011. These derivatives were entered into to partially hedge the crack spread margins for our refining business. The offsetting benefits related to these unrealized losses should be realized over future periods as improved operating margins are realized. In addition to these losses, during the three months ended March 31, 2012, we entered into arrangements to settle a portion of our existing derivative instruments ahead of their respective expiration dates and incurred $44.6 million of realized losses related to these early extinguishments. The cash payments for these early extinguishments have been deferred and will come due between December 2012 and December 2013.

Interest expense, net. Interest expense, net was $10.4 million for the three months ended March 31, 2012 and $10.0 million for the three months ended March 31, 2011. These interest charges relate primarily to the issuance of our senior secured notes as well as commitment fees and interest on the ABL Facility and the amortization of deferred financing costs.

Income tax provision. Income tax expense was less than $0.1 million for the three months ended March 31, 2012 and for the three months ended March 31, 2011. We operate as a pass-through entity for federal tax purposes and, as such, only state taxes have been recognized.

Net loss. Our net loss was $193.6 million for the three months ended March 31, 2012 compared to a net loss of $224.5 million for the three months ended March 31, 2011. This reduction in the loss of 13.8% was primarily attributable to the decrease of $129.2 million related to derivatives activities, which were partially offset by losses from our contingent consideration arrangement with Marathon in the 2012 quarter compared to income in the 2011 quarter.

Segment Financial Data

The segment financial data for the refining segment discussed below under “—Refining Segment” include intersegment sales of refined products to the retail segment. Similarly, the segment financial data for the retail segment discussed below under “—Retail Segment” contain intersegment purchases of refined products from the refining segment.

For purposes of presenting our consolidated results, such intersegment transactions are eliminated, as shown in the following tables.


	Three Months Ended March 31, 2012
(in millions)	Refining		Retail		Other/Elim			Consolidated
Revenue:
Sales and other revenue	$	654.5	$	344.6	$	—		$	999.1
Intersegment sales		240.0		—		(240.0	)		—

Segment revenue	$	894.5	$	344.6	$	(240.0	)	$	999.1

Cost of sales:
Cost of sales	$	772.0	$	67.8	$	—		$	839.8
Intersegment purchases		—		240.0		(240.0	)		—

Segment cost of sales	$	772.0	$	307.8	$	(240.0	)	$	839.8


	Three Months Ended March 31, 2011
(in millions)	Refining		Retail		Other/Elim			Combined
Revenue:
Sales and other revenue	$	599.5	$	340.7	$	—		$	940.2
Intersegment sales		245.7		—		(245.7	)		—

Segment revenue	$	845.2	$	340.7	$	(245.7	)	$	940.2

Cost of sales:
Cost of sales	$	719.0	$	60.0	$	—		$	779.0
Intersegment purchases		—		245.7		(245.7	)		—

Segment cost of sales	$	719.0	$	305.7	$	(245.7	)	$	779.0

Refining Segment


	Three Months Ended,
	March 31,			March 31,
(in millions)	2012			2011
Revenue	$	894.5		$	845.2

Costs, expenses and other:
Cost of sales		772.0			719.0
Direct operating expenses		31.3			32.3
Turnaround and related expenses		3.5			3.3
Depreciation and amortization		5.8			5.1
Selling, general and administrative		6.1			8.6
Other income, net		(2.9	)		(1.6	)

Operating income	$	78.7		$	78.5

Key Operating Statistics
Total refinery production (bpd) (1)		76,437			84,704
Total refinery throughput (bpd)		76,004			84,774
Refined products sold (bpd) (2)		77,923			81,686

Per barrel of throughput:
Refinery gross margin (3)	$	17.71		$	16.54
Direct operating expenses (4)	$	4.53		$	4.23
Per barrel of refined products sold:
Refinery gross margin (3)	$	17.28		$	17.17
Direct operating expenses (4)	$	4.41		$	4.39

Refinery product yields (bpd):
Gasoline		38,902			41,489
Distillate (5)		24,160			23,795
Asphalt		8,323			9,615
Other (6)		5,052			9,805

Total		76,437			84,704

Refinery throughput (bpd):
Crude oil		73,245			78,341
Other feedstocks (7)		2,759			6,433

Total		76,004			84,774

(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 is a per barrel 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 per barrel 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 per barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. For a reconciliation of refinery gross product margin per barrel to refining segment revenue, the most directly comparable GAAP measure, see “Other Non-GAAP Performance Measures.”

(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 March 31, 2012 Compared to the Three Months Ended March 31, 2011

Revenue. Revenue for the three months ended March 31, 2012 was $894.5 million compared to $845.2 million for the three months ended March 31, 2011, an increase of 5.8%. This increase was primarily due to an increase in average prices across our principal refined products sold offset by lower sales volumes in the three months ended March 31, 2012. The lower volumes in the three months ended March 31, 2012 are due to reduced throughput during the first two months of the quarter in response to weak demand locally during those months. Excise taxes included in revenue were $63.5 million and $54.4 million for the three months ended March 31, 2012 and 2011, respectively.

Cost of sales. Cost of sales totaled $772.0 million for the three months ended March 31, 2012 compared to $719.0 million for the three months ended March 31, 2011, a 7.4% increase. This increase was primarily due to an increase in raw material costs driven principally by higher prices of crude oil in the three months ended March 31, 2012. Excise taxes included in cost of sales were $63.5 million and $54.4 million for the three months ended March 31, 2012 and 2011, respectively. Refinery gross product margin per barrel of throughput was $17.71 for the three months ended March 31, 2012 compared to $16.54 for the three months ended March 31, 2011, an increase of $1.17, or 7.1%, which is mostly attributable to improved market crack spreads in the three months ended March 31, 2012.

Direct operating expenses. Direct operating expenses totaled $31.3 million for the three months ended March 31, 2012 compared to $32.3 million for the three months ended March 31, 2011, a 3.1% decrease. This decrease was due primarily to lower utility expenses at the refinery, which resulted from lower utility rates and reduced overall usage in the three months ended March 31, 2012.

Depreciation and amortization. Depreciation and amortization was $5.8 million for the three months ended March 31, 2012 compared to $5.1 million for the three months ended March 31, 2011, an increase of 13.7%. This increase was primarily due to increased assets placed in service as a result of our capital expenditures since March 31, 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 $6.1 million and $8.6 million for the three months ended March 31, 2012 and 2011, respectively, a decrease of 29.1%. 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 March 31, 2012. We are no longer using Marathon’s systems infrastructure.

Other income, net. Other income, net was $2.9 million for the three months ended March 31, 2012 compared to $1.6 million for the three months ended March 31, 2011. This increase was driven primarily by an increase in equity income from our investment in Minnesota Pipe Line.

Operating income. Income from operations was $78.7 million for the three months ended March 31, 2012 compared to $78.5 million for the three months ended March 31, 2011. This increase from the prior year period is due to increased equity income from Minnesota Pipe Line. Overall expense levels were essentially flat.

Retail Segment


	Three Months Ended,
	March 31,			March 31,
(in millions)	2012			2011
Revenue	$	344.6		$	340.7

Costs, expenses and other:
Cost of sales		307.8			305.7
Direct operating expenses		29.4			29.6
Depreciation and amortization		1.8			1.9
Selling, general and administrative		6.0			5.9

Operating loss	$	(0.4	)	$	(2.4	)

Operating data:
Fuel gallons sold (in millions)		74.1			78.1
Fuel margin per gallon (1)	$	0.18		$	0.15
Merchandise sales (in millions)	$	78.8		$	75.3
Merchandise margin % (2)		25.8	%		25.5	%
Number of stores at period end		166			166

(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. For a reconciliation of retail fuel gross margin to retail segment operating income (loss), the most directly comparable GAAP measure, see “Other Non-GAAP Performance Measures.”

(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. For a reconciliation of merchandise margin to retail segment operating income, the most directly comparable GAAP measure, see “Other Non-GAAP Performance Measures.”

Three Months Ended March 31, 2012 Compared to the Three Months Ended March 31, 2011

Revenue. Revenue for the three months ended March 31, 2012 was $344.6 million compared to $340.7 million for the three months ended March 31, 2011, an increase of 1.1%. This increase was primarily due to an increase in merchandise sales of $3.5 million which was partially offset by a reduction in fuel sales driven primarily by lower sales volumes. We experienced a 5.1% decrease in fuel gallons sold in our retail segment compared to the prior year period mostly attributable to higher priced gasoline. Excise taxes included in revenue were $2.1 million for the three months ended March 31, 2012 and $2.3 million for the three months ended March 31, 2011.

Cost of sales. Cost of sales totaled $307.8 million for the three months ended March 31, 2012 and $305.7 million for the three months ended March 31, 2011, an increase of 0.7%. Cost of sales as a percentage of revenue was 89.3% and 89.7% for the three months ended March 31, 2012 and 2011, respectively. Excise taxes included in cost of sales were $2.1 million for the three months ended March 31, 2012 and $2.3 million for the three months ended March 31, 2011. For company-operated stores, retail fuel margin per gallon was $0.18 for the three months ended March 31, 2012 compared to $0.15 per gallon for the three months ended March 31, 2011. The increased fuel margin per gallon in the 2012 period is due to generally favorable local market conditions.

Direct operating expenses. Direct operating expenses totaled $29.4 million for the three months ended March 31, 2012 compared to $29.6 million for the three months ended March 31, 2011, a decrease of 0.7% from the 2011 period.

Depreciation and amortization. Depreciation and amortization was $1.8 million for the three months ended March 31, 2012 compared to $1.9 million for the three months ended March 31, 2011, a decrease of 5.3%. During 2011, our continuing involvement ended for a subset of our retail stores for which we had not achieved 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 March 31, 2011.

Selling, general and administrative expenses. Selling, general and administrative expenses were $6.0 million and $5.9 million for the three months ended March 31, 2012 and 2011, respectively, which represents an increase of 1.7% from the 2011 period.

Operating loss. Operating loss was $0.4 million for the three months ended March 31, 2012 compared to $2.4 million for the three months ended March 31, 2011, an improvement of $2.0 million. The improvement is primarily attributable to increased fuel margins per gallon and higher merchandise revenues.

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 our board of directors, creditors, analysts and investors concerning our financial performance. The ABL Facility and our 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 ABL Facility, earn-out, margin support and management services. Adjusted EBITDA should not be considered as an alternative to operating earnings or net (loss) earnings as measures of operating performance. In addition, Adjusted EBITDA is not presented as and should not be considered an alternative to cash flows from operations as a measure of liquidity. Adjusted EBITDA is defined as EBITDA before turnaround and related expenses, stock-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 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 investment, but includes 17% of the calculated EBITDA of Minnesota Pipe Line;

•

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 (loss) earnings as reflected in the results of operations tables and segment footnote disclosures to Adjusted EBITDA for the periods presented:


	Three Months Ended March 31, 2012
(in millions)	Refining		Retail			Other			Total
Net (loss) earnings	$	78.7	$	(0.4	)	$	(271.9	)	$	(193.6	)
Adjustments:
Interest expense		—		—			10.4			10.4
Depreciation and amortization		5.8		1.8			0.9			8.5

EBITDA subtotal		84.5		1.4			(260.6	)		(174.7	)
Minnesota Pipe Line proportionate EBITDA		0.7		—			—			0.7
Turnaround and related expenses		3.5		—			—			3.5
Stock-based compensation expense		—		—			0.4			0.4
Unrealized losses on derivative activities		—		—			88.4			88.4
Contingent consideration		—		—			65.7			65.7
Early extinguishment of derivatives		—		—			44.6			44.6
Realized losses on derivative activities		—		—			52.9			52.9

Adjusted EBITDA	$	88.7	$	1.4		$	(8.6	)	$	81.5


	Three Months Ended March 31, 2011
(in millions)	Refining		Retail			Other			Total
Net (loss) earnings	$	78.5	$	(2.4	)	$	(300.6	)	$	(224.5	)
Adjustments:
Interest expense		—		—			10.0			10.0
Income tax provision		—		—			0.1			0.1
Depreciation and amortization		5.1		1.9			0.3			7.3

EBITDA subtotal		83.6		(0.5	)		(290.2	)		(207.1	)
Minnesota Pipe Line proportionate EBITDA		0.9		—			—			0.9
Turnaround and related expenses		3.3		—			—			3.3
Stock-based compensation expense		—		—			0.3			0.3
Unrealized losses on derivative activities		—		—			262.9			262.9
Contingent consideration		—		—			(31.8	)		(31.8	)
Formation costs		—		—			2.5			2.5
Realized losses on derivative activities		—		—			52.2			52.2

Adjusted EBITDA	$	87.8	$	(0.5	)	$	(4.1	)	$	83.2

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.

The following table shows the reconciliation of refining gross product margin per barrel of throughput for the three months ended March 31, 2011 and 2012:


	Three Months Ended,
	March 31,		March 31,
(in millions, except per bbl)	2012		2011
Refinery revenue	$	894.5	$	845.2
Refinery cost of sales		772.0		719.0

Refinery gross product margin	$	122.5	$	126.2

Throughput (barrels)		6.9		7.6

Refinery gross product margin per barrel of throughput	$	17.71	$	16.54

Retail fuel margin and retail merchandise 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 loss for the three months ended March 31, 2011 and 2012:


	Three Months Ended,
	March 31,			March 31,
(in millions)	2012			2011
Retail gross margin:
Fuel margin	$	12.1		$	13.3
Merchandise margin		24.7			21.7

Retail gross margin		36.8			35.0
Expenses:
Direct operating expenses		29.4			29.6
Depreciation and amortization		1.8			1.9
Selling, general and administrative		6.0			5.9

Retail segment operating loss	$	(0.4	)	$	(2.4	)

Liquidity and Capital Resources

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

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 ABL 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.

During the second quarter of 2012, we paid a $40.0 million equity distribution in cash to NT Holdings.

We may use a variety of derivative instruments to enhance the stability of our cash flows. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements. 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. As of March 31, 2012, $7.9 million of this liability is included in current liabilities and $36.7 million is included in non-current liabilities with the final amount to be paid in December 2013.

Cash Flows

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


	Three Months Ended,
	March			March
	31, 2012			31, 2011
(in millions)
Net cash (used in) provided by operating activities	$	(54.8	)	$	94.3
Net cash used in investing activities		(4.6	)		(117.8	)
Net cash provided by (used in) financing activities		—			—

Net decrease in cash and cash equivalents		(59.4	)		(23.5	)
Cash and cash equivalents at beginning of period		123.5			72.8

Cash and cash equivalents at end of period	$	64.1		$	49.3

Net Cash (Used In) Provided By Operating Activities. Net cash used in operating activities for the three months ended March 31, 2012 was $54.8 million. The most significant providers of cash were our operating income ($2.7 million) adjusted for non-cash adjustments, such as depreciation and amortization expense ($8.5 million) and non-cash contingent consideration loss ($65.7 million). Offsetting these impacts were realized losses from derivative activities ($52.9 million), increases in accounts receivable ($45.0 million) and decreases in accounts payable and accrued expenses ($23.5 million).

Net cash provided by operating activities for the three months ended March 31, 2011 was $94.3 million. The most significant providers of cash were operating income ($100.7 million) adjusted for non-cash adjustments, such as depreciation and amortization ($7.3 million) and contingent consideration income ($31.8 million). Additionally, cash was provided by reduced accounts receivables ($18.5 million) and other current assets ($19.9 million) and increased accounts payable and accrued expenses ($81.0 million). Offsetting these sources of cash were realized losses from derivative activities ($52.2 million) and increased inventory ($40.0 million).

Net Cash Used In Investing Activities. Net cash used in investing activities for the three months ended March 31, 2012 was $4.6 million, relating primarily to capital expenditures ($5.4 million) offset by return of capital on our equity and cost basis investments ($0.8 million).

Net cash used in investing activities for the three months ended March 31, 2011 was $117.8 million, relating primarily to capital expenditures ($6.0 million) and cash paid to Marathon Oil as part of the Marathon Acquisition ($112.8 million).

Working Capital

Working capital at March 31, 2012 was negative $25.3 million, consisting of $413.8 million in total current assets and $439.1 million in total current liabilities. The working capital at March 31, 2012 was impacted by the short-term derivative liability for unrealized losses of $185.5 million related to our crack spread risk mitigation program. It is expected that these unrealized losses will be offset by future margin improvements that will be realized from sales of refined products at improved crack spreads over the next two years.

Capital Spending

Capital spending was $5.4 million for the three months ended March 31, 2012, 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 various market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps, forward agreements and other financial instruments to mitigate the effects of the identified risks. In general, we may attempt to mitigate risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures and similar requirements.

Commodity Price Risk

As a refiner of petroleum products, we have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, we must achieve a positive spread between the cost of raw materials and the value of finished products (i.e., refinery gross product margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable. The timing, direction and overall change in refined product prices versus crude oil prices will impact profit margins and could have a significant impact on our earnings and cash flows. Assuming all other factors remained constant, a $1 per barrel change in our average refinery gross product margin, based on our average refinery throughput for the three months ended March 31, 2012 of 76,004 bpd, would result in a change of $27.8 million in our overall gross margin on an annual basis.

The prices of crude oil, refined products and other commodities are subject to fluctuations in response to changes in supply, demand, market uncertainty and a variety of additional factors that are beyond our control. We monitor these risks and, where appropriate under our risk mitigation policy, we will seek to reduce the volatility of our cash flows by hedging an operationally reasonable volume of our gasoline and diesel production. We enter into derivative transactions designed to mitigate the impact of commodity price fluctuations on our business by locking in or fixing a percentage of the anticipated or planned gross margin in future periods. We will not enter into financial instruments for purposes of speculating on commodity prices. However, we may execute derivative financial instruments pursuant to our hedging policy that are not considered to be hedges within the applicable accounting guidelines.

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

Basis Risk

The effectiveness of our risk mitigation strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors, for example the location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure. In hedging NYMEX or U.S. Gulf Coast (or any other relevant benchmark) crack spreads, we experience location basis as the settlement price of NYMEX refined products (related more to New York Harbor cash markets) or U.S. Gulf Coast refined products (related more to U.S. Gulf Coast cash markets) may be different than the prices of refined products in our Upper Great Plains pricing area. The risk associated with not hedging the basis when using NYMEX or U.S. Gulf Coast forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX or U.S. Gulf Coast while pricing in our market remains flat or decreases, then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the pricing in our market.

Commodities Price and Basis Risk Management Activities

We have entered into derivative contract agreements that govern all cash-settled commodity transactions that we enter into with J. Aron & Company and Macquarie Bank Limited for the purpose of managing our risk with respect to the crack spread created by the purchase of crude oil for future delivery and the sale of refined petroleum products, including gasoline, diesel, jet fuel and heating fuel, for future delivery. Under the agreements, as market conditions permit, we have the capacity to mitigate our crack spread risk with respect to a reasonable percentage of the refinery’s projected monthly production of some or all of these refined products. As of March 31, 2012, we have hedged approximately 15 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.

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 a portion of the net proceeds of the initial public offering of Northern Tier Energy LP to settle this obligation. If this offering is not completed, the loss from resetting the price of our derivative contracts will be paid to the counterparty on the same monthly schedule as the original contracts were scheduled to settle.

Our open positions at March 31, 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 15 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 $15 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 March 31, 2012, the availability under the ABL Facility was $156.7 million. This availability is net of $61.6 million in outstanding letters of credit. We had no borrowings under the ABL Facility at March 31, 2012. Borrowings under the ABL Facility bear 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 11 – “Debt,” to the unaudited consolidated financial statements included herein.

We have interest rate exposure on a portion of the cost of crude oil payable to JPM CCC for the crude oil inventory that they purchase for delivery to our refinery under the crude oil supply and logistics agreement. This exposure is offset with the credits we receive from JPM CCC for the trade terms granted by suppliers to them on crude oil purchases intended for our refinery. Our interest rate exposure is the spread between 3-months and 1-month LIBOR. A widening of the spread between these two rates 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 or submit 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 Securities and Exchange Commission. Based upon the evaluation, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures were effective as of March 31, 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 three months ended March 31, 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 the Prospectus. Those risks and uncertainties are not the only ones facing us and there may be additional matters of which we are unaware or that we currently consider immaterial. All of those risks or uncertainties could adversely affect our business, financial condition and/or results of operations.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

The exhibits listed in the accompanying Exhibit Index are filed or incorporated by reference as part of this report and such Exhibit Index is incorporated herein by reference.

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 June 28, 2012	By:	/s/ Mario E. Rodriguez
		Mario E. Rodriguez
		Chief Executive Officer and Director

Date June 28, 2012	By:	/s/ David Bonczek
		David Bonczek
		Vice President and Chief Financial Officer

EXHIBIT INDEX


Exhibit Number		Description

3.1		Certificate of Formation of Northern Tier Energy LLC (Incorporated by reference to Exhibit 3.1 of Northern Tier Energy LLC’s Registration Statement on Form S-4 filed on December 13, 2011).

3.2		Limited Liability Company Agreement of Northern Tier Energy LLC dated as of October 6, 2010 (Incorporated by reference to Exhibit 3.2 of Northern Tier Energy LLC’s Registration Statement on Form S-4 filed on December 13, 2011).

4.1		Indenture, dated as of December 1, 2010, by and among Northern Tier Energy LLC, Northern Tier Finance Corporation, the subsidiary guarantors party thereto and Deutsche Bank Trust Company Americas (Incorporated by reference to Exhibit 4.2 of Northern Tier Energy, Inc.’s Registration Statement on Form S-1 filed on December 13, 2011).

10.1		Amended and Restated Management Services Agreement, dated as of January 1, 2012, by and among Northern Tier Energy, LLC, TPG VI Management, LLC and ACON Funds Management L.L.C. (Incorporated by reference to Exhibit 10.11 of Amendment No. 1 to Northern Tier Energy, Inc.’s Registration Statement on Form S-1 filed on February 10, 2012).

10.2†		Amended and Restated Crude Oil Supply Agreement dated March 29, 2012, by and between J.P. Morgan Commodities Canada Corporation and St. Paul Park Refining Co. LLC (Incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-4 filed on May 14, 2012).

10.3		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).

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 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 Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Extension Presentation Linkbase Document.

*	Furnished, not filed.

†	Certain portions have been omitted pursuant to a confidential treatment request. Omitted information has been separately filed with the Securities and Exchange Commission.

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Northern Tier Energy LLC 10-Q