1st Quarter 2011 (10-Q)

Source Quarterly 10-Q
Company CVR Energy, Inc. 
Tags Financial & Operating Data
Date May 12, 2011

UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

     
 (Mark One)     
þ    QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE SECURITIES EXCHANGE ACT OF 1934
  
    For the quarterly period ended March 31, 2011  
    OR 
o    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
 OF THE SECURITIES EXCHANGE ACT OF 1934
 
    For the transition period from          to          

Commission file number: 001-33492

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)

     
Delaware    61-1512186 
(State or Other Jurisdiction of
 Incorporation or Organization)
 
  (I.R.S. Employer
 Identification No.)
 
2277 Plaza Drive, Suite 500
 Sugar Land, Texas
(Address of Principal Executive Offices) 
  77479
(Zip Code) 

(Registrant’s telephone number, including area code)

(281) 207-3200

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 þ     No o

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 or 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).  Yes o     No o

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):

       
Large accelerated filer o  Accelerated filer þ  Non-accelerated filer o  Smaller reporting company o 

(Do not check if a smaller reporting company)

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

There were 86,413,781 shares of the registrant’s common stock outstanding at May 6, 2011.

      

   

CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended March 31, 2011

 

         
    Page No. 
 
PART I. FINANCIAL INFORMATION 
 Item 1.   Financial Statements    
    Condensed Consolidated Balance Sheets — March 31, 2011 (unaudited) and December 31, 2010    
    Condensed Consolidated Statements of Operations — Three Months Ended March 31, 2011 and 2010 (unaudited)    
    Condensed Consolidated Statements of Cash Flows — Three Months Ended March 31, 2011 and 2010 (unaudited)    
    Notes to the Condensed Consolidated Financial Statements — March 31, 2011 (unaudited)    
 Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations   31  
 Item 3.   Quantitative and Qualitative Disclosures About Market Risk   61  
 Item 4.   Controls and Procedures   61  
 
PART II. OTHER INFORMATION 
 Item 1.   Legal Proceedings   62  
 Item 1A.   Risk Factors   62  
 Item 6.   Exhibits   62  
 Signatures      64  
EX-10.1 
EX-10.2 
EX-10.3 
EX-10.4 
EX-10.5 
EX-10.9 
EX-31.1 
EX-31.2 
EX-32.1 
EX-32.2 
EX-99.1 

 

   


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GLOSSARY OF SELECTED TERMS

The following are definitions of certain industry terms used in this Form 10-Q.

2-1-1 crack spread — The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate. The 2-1-1 crack spread is expressed in dollars per barrel.

ammonia — Ammonia is a direct application fertilizer and is primarily used as a building block for other nitrogen products for industrial applications and finished fertilizer products.

backwardation market — Market situation in which futures prices are lower in succeeding delivery months. Also known as an inverted market. The opposite of contango.

barrel — Common unit of measure in the oil industry which equates to 42 gallons.

blendstocks — Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, fluid catalytic cracking unit or FCCU gasoline, ethanol, reformate or butane, among others.

bpd — Abbreviation for barrels per day.

bulk sales — Volume sales through third party pipelines, in contrast to tanker truck quantity sales.

capacity — Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical capacity. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints.

catalyst — A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process.

coker unit — A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke.

common units — The class of interests issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies.

contango market — Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation.

corn belt — The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.

crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.

distillates — Primarily diesel fuel, kerosene and jet fuel.

ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.

farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.

   


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feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.

independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.

light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.

Magellan — Magellan Midstream Partners L.P., a publicly traded company whose business is the transportation, storage and distribution of refined petroleum products.

MMBtu — One million British thermal units or Btu:  a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.

natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and are products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.

PADD II — Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.

plant gate price — the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs.

petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.

refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.

sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.

spot market — A market in which commodities are bought and sold for cash and delivered immediately.

sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.

throughput — The volume processed through a unit or a refinery or transported on a pipeline.

turnaround — A periodically required standard procedure to inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for the refinery and every two years for the nitrogen fertilizer plant.

UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.

wheat belt — The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas.

WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or  API gravity, between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an  API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.

yield — The percentage of refined products that is produced from crude oil and other feedstocks.

   


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PART I. FINANCIAL INFORMATION

  
Item 1. Financial Statements 

CVR Energy, Inc. and Subsidiaries

   CONDENSED CONSOLIDATED BALANCE SHEETS

   
         
  March 31,
 
  December 31,
 
 
  2011   2010  
  (unaudited)     
  (in thousands, 
 
 
  except share data)  
 
ASSETS 
 Current assets:         
 Cash and cash equivalents  165,896   200,049  
 Accounts receivable, net of allowance for doubtful accounts of $845 and $722, respectively   113,988    80,169  
 Inventories   395,076    247,172  
 Prepaid expenses and other current assets   51,061    28,616  
 Deferred income taxes   39,825    43,351  
         
 Total current assets   765,846    599,357  
 Property, plant, and equipment, net of accumulated depreciation   1,063,831    1,081,312  
 Intangible assets, net   336    344  
 Goodwill   40,969    40,969  
 Deferred financing costs, net   12,949    10,601  
 Insurance receivable   3,570    3,570  
 Other long-term assets   4,461    4,031  
         
 Total assets  1,891,962   1,740,184  
         
 
LIABILITIES AND EQUITY 
 Current liabilities:         
 Note payable and capital lease obligations  1,495   8,014  
 Accounts payable   226,073    155,220  
 Personnel accruals   19,451    29,151  
 Accrued taxes other than income taxes   24,919    21,266  
 Income taxes payable   23,141    7,983  
 Deferred revenue   26,726    18,685  
 Other current liabilities   41,840    25,396  
         
 Total current liabilities   363,645    265,715  
 Long-term liabilities:         
 Long-term debt, net of current portion   469,075    468,954  
 Accrued environmental liabilities, net of current portion   2,344    2,552  
 Deferred income taxes   299,177    298,943  
 Other long-term liabilities   3,898    3,847  
         
 Total long-term liabilities   774,494    774,296  
 Commitments and contingencies         
 Equity:         
 CVR stockholders’ equity:         
 Common Stock $0.01 par value per share, 350,000,000 shares authorized, 86,435,672 and 86,435,672 shares issued, respectively   864    864  
 Additional paid-in-capital   475,732    467,871  
 Retained earnings   266,867    221,079  
 Treasury stock, 21,891 and 21,891 shares, respectively, at cost   (243   (243 
 Accumulated other comprehensive income, net of tax       
         
 Total CVR stockholders’ equity   743,223    689,573  
         
 Noncontrolling interest   10,600    10,600  
         
 Total equity   753,823    700,173  
         
 Total liabilities and equity  1,891,962   1,740,184  
         
   

See accompanying notes to the condensed consolidated financial statements.

   


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CVR Energy, Inc. and Subsidiaries

   CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

   
         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)
 
 
  (in thousands, except share data)  
 
 Net sales  1,167,265   894,512  
 Operating costs and expenses:         
 Cost of product sold (exclusive of depreciation and amortization)   936,822    802,890  
 Direct operating expenses (exclusive of depreciation and amortization)   68,326    60,562  
 Insurance recovery — business interruption   (2,870   —  
 Selling, general and administrative expenses (exclusive of depreciation and amortization)   33,262    21,394  
 Net costs associated with flood   108    —  
 Depreciation and amortization   22,011    21,260  
         
 Total operating costs and expenses   1,057,659    906,106  
         
 Operating income (loss)   109,606    (11,594 
 Other income (expense):         
 Interest expense and other financing costs   (13,190   (9,922 
 Interest income   274    416  
 Gain (loss) on derivatives, net   (22,106   1,490  
 Loss on extinguishment of debt   (1,908   (500 
 Other income, net   231    42  
         
 Total other income (expense)   (36,699   (8,474 
         
 Income (loss) before income tax expense (benefit)   72,907    (20,068 
 Income tax expense (benefit)   27,119    (7,705 
         
 Net income (loss)  45,788   (12,363 
         
 Basic earnings (loss) per share  0.53   (0.14 
 Diluted earnings (loss) per share  0.52   (0.14 
 Weighted-average common shares outstanding:         
 Basic   86,413,781    86,329,237  
 Diluted   87,783,857    86,329,237  
   

See accompanying notes to the condensed consolidated financial statements.

   


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CVR Energy, Inc. and Subsidiaries

   CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

   
         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)  
  (in thousands)  
 
 Cash flows from operating activities:         
 Net income (loss)  45,788   (12,363 
 Adjustments to reconcile net income (loss) to net cash provided by operating activities:         
 Depreciation and amortization   22,011    21,260  
 Allowance for doubtful accounts   123    265  
 Amortization of deferred financing costs   907    462  
 Amortization of original issue discount   121    —  
 Deferred income taxes   3,760    2,667  
 Loss on disposition of assets   639    343  
 Loss on extinguishment of debt   1,908    500  
 Share-based compensation   19,101    7,279  
 Unrealized (gain) loss on derivatives   3,258    (3,180 
 Changes in assets and liabilities:         
 Accounts receivable   (33,942   (16,073 
 Inventories   (147,904   19,226  
 Prepaid expenses and other current assets   (16,954   (469 
 Insurance receivable   (8,600   —  
 Insurance proceeds from flood   —    (390 
 Business interruption insurance proceeds   2,315    —  
 Other long-term assets   (577   10,878  
 Accounts payable   73,157    (10,319 
 Accrued income taxes   15,158    19,791  
 Deferred revenue   8,041    3,602  
 Other current liabilities   (4,101   —  
 Payable to swap counterparty   —    (74 
 Accrued environmental liabilities   (208   —  
 Other long-term liabilities   51    56  
         
 Net cash (used in) provided by operating activities   (15,948   43,461  
         
 Cash flows from investing activities:         
 Capital expenditures   (7,337   (11,416 
 Proceeds from the sale of assets   19    —  
 Insurance proceeds from UAN reactor rupture   225    —  
         
 Net cash used in investing activities   (7,093   (11,416 
         
 Cash flows from financing activities:         
 Revolving debt payments   —    (40,000 
 Revolving debt borrowings   —    40,000  
 Principal payments on term debt   —    (26,199 
 Payment of financing costs   (4,701   (5,195 
 Payment of capital lease obligation   (4,796   (20 
 Deferred costs of CVR Partners initial public offering   (1,615   —  
         
 Net cash used in financing activities   (11,112   (31,414 
         
 Net increase (decrease) in cash and cash equivalents   (34,153   631  
 Cash and cash equivalents, beginning of period   200,049    36,905  
         
 Cash and cash equivalents, end of period  165,896   37,536  
         
 Supplemental disclosures:         
 Cash paid for income taxes, net of refunds (received)  8,200   (53 
 Cash paid for interest, net of capitalized interest of $86,000 and $881,000 in 2011 and 2010, respectively   680    10,505  
 Cash funding of margin account for other derivative activities, net of withdrawals (received)   9,237    (3,102 
 Non-cash investing and financing activities:         
 Accrual of construction in progress additions   (2,304   (1,457 
   

See accompanying notes to the condensed consolidated financial statements.

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2011
(unaudited)

   
  
(1)   Organization and History of the Company and Basis of Presentation 
   

Organization

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries.

The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer of high value transportation fuels in the mid-continental United States. In addition, the Company, through its majority-owned subsidiaries, acts as an independent producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

CVR is subject to the rules and regulations of the New York Stock Exchange where its shares are traded under the symbol “CVI.” As of December 31, 2010, approximately 40% of its outstanding shares were beneficially owned by GS Capital Partners V, L.P. and related entities (“GS” or “Goldman Sachs Funds”) and Kelso Investment Associates VII, L.P. and related entities (“Kelso” or “Kelso Funds”). On February 8, 2011, GS and Kelso completed a registered public offering, whereby GS sold into the public market its remaining ownership interests in CVR Energy. Additionally, Kelso reduced its interests in the Company and as of the date of this Report beneficially owns approximately 9% of all shares outstanding.

Nitrogen Fertilizer Limited Partnership

In conjunction with the consummation of CVR’s initial public offering in 2007, CVR transferred Coffeyville Resources Nitrogen Fertilizers, LLC (“CRNF”), its nitrogen fertilizer business, to a then newly created limited partnership, CVR Partners, LP (the “Partnership”), in exchange for a managing general partner interest (“managing GP interest”), a special general partner interest (“special GP interest,” represented by special GP units) and a de minimis limited partner interest (“LP interest,” represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest, including the associated incentive distribution rights (“IDRs”), to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by its then controlling stockholders and senior management, at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing GP interest was $10,600,000. This interest has been classified as a noncontrolling interest included as a separate component of equity in the Condensed Consolidated Balance Sheets at March 31, 2011 and December 31, 2010. In connection with the April 2011 initial public offering of the Partnership (the “Offering”), as discussed in further detail below, the IDRs were purchased by the Partnership and the IDRs were subsequently extinguished. In addition, the noncontrolling interest representing the managing GP interest was purchased by Coffeyville Resources, LLC, our subsidiary (“CRLLC”). The payment for the IDRs was paid to owners of CALLC III, which included the Goldman Sachs Funds, the Kelso Funds and members of CVR senior management. As a result of the Offering, the Company recorded a noncontrolling interest for the common units sold into the public market which represented approximately 30.2% interest in the Partnership at the time of the Offering. The Company’s noncontrolling interest reflected on the consolidated balance sheet of CVR will be impacted by net income and distributions of the Partnership.

As of March 31, 2011 and until the completion of the Offering by the Partnership, CVR owned all of the interests in the Partnership (other than the managing GP interest and the IDRs) and was entitled to all cash distributed by the Partnership, except with respect to IDRs. At March 31, 2011, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interest outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   

managing general partner owned the managing GP interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing GP interest and the IDRs.

In addition, as of March 31, 2011, the Partnership and its subsidiary were guarantors under CRLLC’s asset backed revolving credit facility (“ABL credit facility”) and senior secured notes. In connection with the Offering, the Partnership was subsequently released from its obligations as a guarantor under the ABL credit facility and senior secured notes, as described further in Note 12 (“Long-Term Debt”).

On April 13, 2011, the Partnership completed its initial public offering of 22,080,000 common units priced at $16.00 per unit (such amount includes commitments issued pursuant to the exercise of the underwriters’ over-allotment option). The common units, which are listed on the New York Stock Exchange, began trading on April 7, 2011 under the symbol “UAN”.

The gross proceeds to the Partnership from the Offering (including the gross proceeds from the exercise of the underwriter’s over-allotment option) were approximately $353,280,000 prior to underwriting discount and other offering costs. In connection with the Offering, the Partnership paid approximately $24,730,000 in underwriting fees and incurred approximately $4,000,000 of other offering costs. Approximately $5,741,000 of the underwriter fee was paid to an affiliate of GS acting as joint book-running managers. Until completion of the February 2011 secondary offering, an affiliate of GS was a stockholder and related party of the Company. As a result of the Offering and as of the date of this Report, CVR indirectly owns 69.8% of the Partnership’s outstanding common units and 100% of the Partnership’s general partner with its non-economic general partner interest.

In connection with the Offering, the Partnership’s limited partner interests were converted into common units, the Partnership’s special general partner interests were converted into common units, and the partnership’s special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, as discussed above, the managing general partner sold its IDRs to the Partnership, these interests were extinguished, and CALLC III sold the managing general partner to CRLLC for a nominal amount. As a result of the Offering, the Partnership has two types of partnership interests outstanding:

   
 •  common units representing limited partner interests; and 
 
 •  a general partner interest, which is not entitled to any distributions, and which is held by the Partnership’s general partner. 

The proceeds from the offering were utilized as follows:

   
 •  approximately $18.4 million was distributed to CRLLC to satisfy the Partnership’s obligation to reimburse it for certain capital expenditures made on behalf of the nitrogen fertilizer business prior to October 24, 2007; 
 
 •  approximately $117.1 million was distributed to CRLLC through a special distribution in order to among other things, fund the offer to purchase CRLLC’s senior secured notes required upon the consummation of the Offering; 
 
 •  $26.0 million was used to purchase and extinguish the IDR’s owned by the general partner; 
 
 •  approximately $4.4 million to pay financing fees and associated legal and professional fees resulting from the new credit facility; and 
 
 •  the balance of the proceeds will be utilized for general partnership purposes, including the funding of the UAN expansion that is expected to require an investment of approximately $135 million, of which approximately $31 million has been spent as of March 31, 2011. 

Following the Offering, the Partnership will make quarterly cash distributions to unitholders. The partnership agreement does not require that the Partnership make cash distributions on a quarterly or other

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   

basis. In connection with the Offering, the board of directors of the general partner adopted a distribution policy, which it may change at any time.

The Partnership is operated by CVR’s senior management pursuant to an amended and restated services agreement, effective April 13, 2011, among CVR, the general partner and the Partnership. The Partnership’s general partner, CVR GP, LLC, manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The general partner is owned by CRLLC, a wholly-owned subsidiary of CVR. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the unitholders and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business. CVR, the Partnership, their respective subsidiaries and the general partner are parties to a number of agreements to regulate certain business relations between them. Certain of these agreements were amended in connection with the Offering.

Basis of Consolidation

In accordance with Accounting Standards Codification (“ASC”) Topic 810-10 —  Consolidations-Variable Interest Entities, (“ASC 810-10”), as of March 31, 2011, management has determined that the Partnership is a variable interest entity (“VIE”) and as such evaluated the qualitative criteria under ASC 810-10 to make this determination. ASC 810-10 requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. The primary beneficiary is identified as the enterprise that has a) the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and b) the obligation to absorb losses of the entity that could potentially be significant to the VIE or the right to receive benefits from the entity that could potentially be significant to the VIE. The standard requires an ongoing analysis to determine whether the variable interest gives rise to a controlling financial interest in the VIE.

The conclusion that CVR is the primary beneficiary of the Partnership and is required to consolidate the Partnership as a VIE is based primarily on the fact that the general partner’s officers manage the day-to-day operations and activities of the Partnership. These officers of the general partner are also officers of CVR Energy. As such, they have the power to direct the activities of the Partnership that most significantly impacts the entity’s economic performance.

As a result of the Offering, the basis of consolidation of the Partnership into CVR Energy is based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy; and, therefore has the ability to control the activities of the Partnership. Additionally, the Partnership’s general partner, CVR GP, LLC, manages the operations and activities of the Partnership, subject to the terms and conditions specified in the partnership agreement. The operations of the general partner in its capacity as general partner are managed by its board of directors. Actions by the general partner that are made in its individual capacity will be made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The general partner is not elected by the unitholders and is not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business. Based upon the general partnership’s role and rights as afforded by the partnership agreement and the limited rights afforded to the limited partners the consolidated financial statements of CVR Energy will include the assets, liabilities, cash flows, revenues and expenses of the Partnership.

The limited rights of the limited partners are demonstrated by the fact that the limited partners have no right to elect the general partner or the general partner’s directors on an annual or other continuing basis. The general partner can only be removed by a vote of the holders of at least 662/3% of the outstanding common units, including any common units owned by the general partner and its affiliates (including CRLLC, a wholly-owned subsidiary of CVR Energy) voting together as a single class. Upon completion of the Offering,

   


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the general partner and its affiliates, through CRLLC, own an aggregate of approximately 69.8% of the outstanding common units. This gives CRLLC the ability to prevent removal of the general partner.

Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (“GAAP”) and in accordance with the rules and regulations of the Securities and Exchange Commission (“SEC”). The condensed consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries. The ownership interests of noncontrolling investors in its subsidiaries are recorded as a noncontrolling interest included as a separate component of equity for all periods presented. All intercompany account balances and transactions have been eliminated in consolidation. Certain information and footnotes required for complete financial statements under GAAP have been condensed or omitted pursuant to SEC rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2010 audited consolidated financial statements and notes thereto included in CVR’s Annual Report on Form 10-K for the year ended December 31, 2010, which was filed with the SEC on March 7, 2011.

In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of March 31, 2011 and December 31, 2010, the results of operations and cash flows for the three months ended March 31, 2011 and 2010.

Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2011 or any other interim period. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

The Company evaluated subsequent events, if any, that would require an adjustment or would require disclosure to the Company’s condensed consolidated financial statements through the date of issuance of these condensed consolidated financial statements.

   
  
(2)   Recent Accounting Pronouncements 
   

In July 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-20, which amends ASC Topic 310, “Receivables” to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. This ASU will require an entity to disclose (1) the inherent credit risk in its financing receivables, (2) how the credit risk is analyzed and assessed in calculating the allowance for credit losses and (3) the changes and reasons for those changes in the allowance for credit losses. The provisions of ASU No. 2010-20 are effective for interim and annual reporting periods ending on or after December 31, 2010. The adoption of this standard did not impact the Company’s financial position or results of operations.

In January 2010, the FASB issued ASU No. 2010-06, “Improving Disclosures about Fair Value Measurements,” an amendment to ASC Topic 820, “Fair Value Measurements and Disclosures.” This amendment requires an entity t (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements and (iii) enhance disclosures of assets and liabilities subject to fair value measurements. The provisions of ASU No. 2010-06 are effective for the Company for interim and annual reporting beginning after December 15, 2009, with one new disclosure effective after December 15, 2010. The Company adopted this ASU as of

   


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January 1, 2010. The adoption of this standard did not impact the Company’s financial position or results of operations.

   
  
(3)   Share-Based Compensation 
   

Prior to CVR’s initial public offering in October 2007, CVR’s subsidiaries were held and operated by Coffeyville Acquisition LLC (“CALLC”) and its subsidiaries. Management of CVR holds an equity interest in CALLC. CALLC issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering in October 2007, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”). In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. CALLC was historically the primary reporting company and CVR’s predecessor. In addition, in connection with the transfer of the managing GP interest of the Partnership to CALLC III in October 2007, CALLC III issued non-voting override units to certain management members of CALLC III.

CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with standards issued by the FASB regarding the treatment of share-based compensation, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. CVR has been allocated non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.

In accordance with these standards, CVR, CALLC, CALLC II and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. In addition, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees, for acquiring, or in conjunction with selling goods or services, which requires remeasurement at each reporting period through the performance commitment period, or in CVR’s case, through the vesting period.

For the three months ended March 31, 2011, the estimated fair value of the CALLC III override units were determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and also considered the proposed initial public offering of the Partnership, including the purchase of the IDRs and the managing GP interest. For the three months ended March 31, 2010, the estimated fair value of the override units of CALLC III were determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections, which were considered representative of the nature of interests held by CALLC III in the Partnership.

At March 31, 2011, the estimated fair value of the override units of CALLC was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are vested. The probability-weighted expected return method was also used to determine the estimated fair value of the override units of CALLC and CALLC II for the three months ended March 31, 2010.

In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR’s common stock, pursuant to a registered public offering. As a result of this offering, CALLC reduced its beneficial ownership in the Company to approximately 9% of its outstanding shares as of the date of this Report and CALLC II is no longer a stockholder of the Company. Subsequent to

   


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CALLC II’s divestiture of its ownership interest in the Company, no additional share-based compensation expense was incurred with respect to override units and phantom units associated with CALLC II.

The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC III.

                     
           *Compensation Expense Increase
 
 
           (Decrease) for the
 
 
  Benchmark
 
  Original
 
     Three Months Ended
 
 
  Value
 
  Awards
 
     March 31,  
Award Type  (per Unit)   Issued   Grant Date   2011   2010  
           (in thousands)  
 
 Override Operating Units(a)  11.31    919,630    June 2005   —   415  
 Override Operating Units(b)  34.72    72,492    December 2006    —    15  
 Override Value Units(c)  11.31    1,839,265    June 2005    4,987    3,181  
 Override Value Units(d)  34.72    144,966    December 2006    515    93  
 Override Units(e)  10.00    138,281    October 2007    —    —  
 Override Units(f)  10.00    642,219    February 2008    135     
                     
           Total   5,637   3,706  
                     
   
 As CVR’s common stock price increases or decreases, compensation expense associated with the unvested CALLC override units increases or is reversed in correlation with the calculation of the fair value under the probability-weighted expected return method. 

Valuation Assumptions

Significant assumptions used in the valuation of the Override Operating Units (a) and (b) were as follows:

         
  (a) Override Operating
 
 (b) Override
 
  Units
 
 Operating Units
 
  March 31, 2010  March 31, 2010 
 
 Estimated forfeiture rate   None    None  
 CVR closing stock price  8.75   8.75  
 Estimated weighted-average fair value (per unit)  15.01   2.52  
 Marketability and minority interest discounts   20.0   20.0 
 Volatility   50.0   50.0 

On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. As of March 31, 2011, these units were fully vested.

Significant assumptions used in the valuation of the Override Value Units (c) and (d) were as follows:

                 
  (c) Override Value
 
  (d) Override
 
 
  Units
 
  Value Units
 
 
  March 31,   March 31,  
  2011   2010   2011   2010  
 
 Estimated forfeiture rate   None    None    None    None  
 Derived service period   6 years    6 years    6 years    6 years  
 CVR closing stock price  23.16   8.75   23.16   8.75  
 Estimated weighted-average fair value (per unit)  22.61   9.61   13.70   2.50  
 Marketability and minority interest discounts   5.0   20.0   5.0   20.0 
 Volatility   47.1   50.0   47.1   50.0 
   


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Unless the override unit committee of the board of directors of CALLC or CALLC III, respectively, takes action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason, except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture as follows:

     
  Forfeiture
 
Minimum Period Held  Percentage 
 
 2 years   75 
 3 years   50 
 4 years   25 
 5 years   

(e) Override Units— Using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flow projections and included expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. As of March 31, 2011 these units were fully vested.

(f) Override Units— Using a probability-weighted expected return method which utilized CALLC III’s cash flow projections and included expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:

     
  March 31, 
  2011  2010 
 
 Estimated forfeiture rate  None  None 
 Derived Service Period  Based on forfeiture schedule  Based on forfeiture schedule 
 Estimated fair value (per unit)  $2.82  $0.08 
 Marketability and minority interest discount  5.0%  20.0% 
 Volatility  47.0%  59.7% 

Based upon the estimated fair value at March 31, 2011, there was approximately $818,000 of unrecognized compensation expense related to non-voting override units. This expense is expected to be recognized over a remaining period of less than one year. To the extent the price of CVR’s common stock increases additional share-based compensation expense will be incurred with respect to unvested override units.

Phantom Unit Appreciation Plan

CVR, through a wholly-owned subsidiary, has two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the compensation committee. Holders of service phantom points have rights to receive distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when CALLC and CALLC II holders of override value units receive distributions. There are no other rights or guarantees and the plans expire on July 25, 2015, or at the discretion of CVR. As of March 31, 2011, the issued Profits Interest (combined phantom points and override units) represented 15.0% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was

   


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comprised of approximately 11.1% of override interest and approximately 3.9% of phantom interest. The expense associated with these awards is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of the Company’s common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled. CVR has recorded approximately $9,849,000 and $18,689,000 in personnel accruals as of March 31, 2011 and December 31, 2010, respectively. Compensation expense for the three months ended March 31, 2011 and 2010 related to the Phantom Unit Plans was $11,240,000 and $3,399,000, respectively. Using the Company’s closing stock price at March 31, 2011 and 2010, to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were valued as follows:

         
  March 31, 
  2011  2010 
 
 Service Phantom interest (per point)  13.14   14.49  
 Performance Phantom interest (per point)  22.62   9.41  

As described above, in February 2011, CALLC and CALLC II completed an additional sale of CVR common stock into the public market pursuant to a registered public offering. As a result of this offering, the Company made a payment to phantom unitholders of approximately $20,079,000 in the first quarter of 2011.

Based upon the estimated fair value at March 31, 2011, there was approximately $107,000 of unrecognized compensation expense related to the Phantom Unit Plans. This is expected to be recognized over a remaining period of less than one year. To the extent the price of CVR’s common stock increases, additional share-based compensation expense will be incurred with respect to the remaining phantom unit awards.

Long-Term Incentive Plan

CVR has a Long-Term Incentive Plan (“LTIP”) which permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of March 31, 2011, only restricted shares of CVR common stock and stock options had been granted under the LTIP. Individuals who are eligible to receive awards and grants under the LTIP include the Company’s employees, officers, consultants, advisors and directors.

Stock Options

As of March 31, 2011, there have been a total of 32,350 stock options granted, of which 24,718 have vested. However, 6,301 vested options have expired resulting in a net total of 18,417 outstanding options that have vested. Additionally, 3,149 unvested stock options were forfeited in the second quarter of 2010. There were no options vested, forfeited or granted in the first quarter of 2011. The fair value of stock options is estimated on the date of grant using the Black-Scholes option pricing model. As of March 31, 2011, there was approximately $5,000 of total unrecognized compensation cost related to stock options to be recognized over a weighted-average period of less than one year.

   


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Restricted Stock

A summary of restricted stock grant activity and changes during the three months ended March 31, 2011 is presented below:

         
     Weighted-
 
 
     Average
 
 
     Grant-Date
 
 
Restricted Stock  Shares   Fair Value  
 
 Outstanding at January 1, 2011 (non-vested)   1,369,182   10.94  
 Vested   —    —  
 Granted   —    —  
 Forfeited   (2,400   4.14  
         
 Outstanding at March 31, 2011 (non-vested)   1,366,782   10.95  
         

Through the LTIP, shares of non-vested restricted stock have been granted to employees of the Company. Non-vested restricted shares, when granted, are valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. These shares generally vest over a three-year period. As of March 31, 2011, there was approximately $11,180,000 of total unrecognized compensation cost related to non-vested restricted shares to be recognized over a weighted-average period of approximately two years.

Compensation expense recorded for the three months ended March 31, 2011 and 2010 related to the non-vested restricted stock and stock options was $2,224,000 and $173,000, respectively.

In connection with the Offering, the board of directors of the general partner adopted the CVR Partners, LP Long-Term Incentive Plan (“CVR Partners’ LTIP”). Individuals who are eligible to receive awards under the CVR Partners’ LTIP include CVR Partners’, its subsidiaries’, and its parent’s employees, officers, consultants and directors. The CVR Partners’ LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. In connection with the Offering, phantom units were issued to certain board members of the general partner. These phantom units are expected to vest six months following the grant date.

   
  
(4)   Inventories 
   

Inventories consist primarily of domestic and foreign crude oil, blending stock and components, work-in-progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of the first-in, first-out (“FIFO”) cost or market for fertilizer products, refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bear process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

   


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Inventories consisted of the following:

         
  March 31,
 
  December 31,
 
 
  2011   2010  
  (in thousands)  
 
 Finished goods  119,081   110,788  
 Raw materials and precious metals   218,726    89,333  
 In-process inventories   34,575    22,931  
 Parts and supplies   22,694    24,120  
         
  395,076   247,172  
         
   
  
(5)   Property, Plant, and Equipment 
   

A summary of costs for property, plant, and equipment is as follows:

         
  March 31,
 
  December 31,
 
 
  2011   2010  
  (in thousands)  
 
 Land and improvements  19,367   19,228  
 Buildings   26,830    25,663  
 Machinery and equipment   1,364,320    1,363,877  
 Automotive equipment   8,647    8,747  
 Furniture and fixtures   9,589    9,279  
 Leasehold improvements   1,253    1,253  
 Construction in progress   44,150    42,674  
         
   1,474,156    1,470,721  
 Accumulated depreciation   410,325    389,409  
         
  1,063,831   1,081,312  
         

Capitalized interest recognized as a reduction in interest expense for the three months ended March 31, 2011 and 2010, totaled approximately $86,000 and $881,000, respectively. Buildings and equipment that are under a capital lease obligation approximated $332,000 as of March 31, 2011. Amortization of assets held under capital leases is included in depreciation expense.

   
  
(6)   Cost Classifications 
   

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of $632,000 and $728,000 for the three months ended March 31, 2011 and 2010, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of $20,876,000 and $20,018,000 for the three months ended March 31, 2011 and 2010, respectively.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and costs associated with maintaining the corporate and administrative office in Texas and the administrative office in Kansas. Selling, general and

   


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administrative expenses exclude depreciation and amortization of $503,000 and $514,000 for the three months ended March 31, 2011 and 2010, respectively.

   
  
(7)   Note Payable and Capital Lease Obligations 
   

The Company entered into an insurance premium finance agreement in July 2010 to finance a portion of the purchase of its 2010/2011 property insurance policies. The original balance of the note provided by the Company under such agreement was $5,000,000. The Company began to repay this note in equal installments commencing October 1, 2010. As of March 31, 2011 and December 31, 2010, the Company owed $1,250,000 and $3,125,000, respectively, related to this note.

From time to time the Company enters lease agreements for purposes of acquiring assets used in the normal course of business. The majority of the Company’s leases are accounted for as operating leases. During 2010, the Company entered two lease agreements for information technology equipment that are accounted for as capital leases. The initial capital lease obligation of these agreements totaled $415,000. The two capital leases entered into during 2010 have terms of 12 and 36 months. As of March 31, 2011, the outstanding capital lease obligation associated with these leases totaled $245,000.

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease had an initial lease term of one year with an option to renew for three additional one-year periods. During the second quarter of 2010, the Company renewed the lease for a one-year period commencing June 5, 2010. The Company was obligated to make quarterly lease payments that total $80,000 annually. The Company also had the option to purchase the property during the term of the lease, including the renewal periods. The capital lease obligation was $4,587,000 as of December 31, 2010. In March 2011, the Company exercised its purchase option and paid approximately $4,739,000 to satisfy the lease obligation.

   
  
(8)   Insurance Claims 
   

Nitrogen Fertilizer Incident

On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. Repairs to the facility as a result of the rupture were substantially complete as of December 31, 2010.

Total gross costs recorded as of March 31, 2011 due to the incident was approximately $10,893,000 for repairs and maintenance and other associated costs. Approximately $371,000 of these costs was recognized during the three months ended March 31, 2011. The repairs and maintenance costs incurred are included in direct operating expenses (exclusive of depreciation and amortization). Of the costs incurred approximately $4,445,000 was capitalized.

The Company maintains property damage insurance policies which have an associated deductible of $2,500,000. The Company anticipates that substantially all of the repair costs in excess of the $2,500,000 deductible should be covered by insurance. These insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Company has incurred relating to the damage and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. In connection with the incident, the Company recorded an insurance receivable of $4,500,000, of which $4,275,000 of insurance proceeds was received in December 2010 and the remaining $225,000 was received in January 2011. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

In the first quarter of 2011, the Company submitted a partial business interruption claim for damages and losses, as afforded by its insurance policies. The Company’s insurance carriers agreed to make interim

   


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payments totaling $2,870,000. Through March 31, 2011, the Company had received insurance proceeds totaling $2,315,000 related to its business interruption claim and received the remaining $555,000 in April 2011. The proceeds received and to be received as of March 31, 2011 have been included on the Condensed Consolidated Statements of Operations under Insurance recovery -business interruption.

Refinery Incident

On December 28, 2010 the crude oil refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit (“FCCU”), which led to reduced crude throughput. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. Total gross repair and other costs recorded related to the incident as of March 31, 2011 was approximately $8,005,000. Of this amount approximately $7,390,000, was recorded during the three months ended March 31, 2011. As documented above, the Company maintains property damage insurance policies which have an associated deductible of $2,500,000. The Company anticipates that substantially all of the costs in excess of the deductible should be covered by insurance. As of March 31, 2011, the Company recorded an insurance receivable related to the incident of approximately $5,505,000. The recording of the insurance receivable resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).

   
  
(9)   Income Taxes 
   

The Company recognizes liabilities, interest and penalties for potential tax issues based on its estimate of whether, and the extent to which, additional taxes may be due as determined under ASC Topic 740 —  Income Taxes. As of March 31, 2011, the Company had unrecognized tax benefits of approximately $245,000 which, if recognized, would impact the Company’s effective tax rate. Unrecognized tax benefits that are not expected to be settled within the next twelve months are included in other long-term liabilities in the condensed consolidated balance sheet; unrecognized tax benefits that are expected to be settled within the next twelve months are included in income taxes payable. The Company has not accrued any amounts for interest or penalties related to uncertain tax positions. The Company’s accounting policy with respect to interest and penalties related to tax uncertainties is to classify these amounts as income taxes.

CVR and its subsidiaries file U.S. federal and various state income and franchise tax returns. At March 31, 2011, the Company’s tax filings are generally open to examination in the United States for the tax years ended December 31, 2008 through December 31, 2010 and in various individual states for the tax years ended December 31, 2007 through December 31, 2010.

The Company’s effective tax rate for the three months ended March 31, 2011 was 37.2%, as compared to the Company’s combined federal and state expected statutory tax rate of 39.7%. The Company’s effective tax rate for the three months ended March 31, 2010 was 38.4%.

   


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(10)   Earnings Per Share 
   

Basic and diluted earnings per share are computed by dividing net income (loss) by weighted-average common shares outstanding. The components of the basic and diluted earnings (loss) per share calculation are as follows:

         
  For the Three Months
 
 
  Ended March 31,  
  2011   2010  
  (in thousands, except share data)  
 
 Net income (loss)  45,788   (12,363 
 Weighted-average common shares outstanding   86,413,781    86,329,237  
 Effect of dilutive securities:         
 Non-vested common stock   1,366,782    —  
 Stock options   3,294    —  
         
 Weighted-average common shares outstanding assuming dilution   87,783,857    86,329,237  
         
 Basic earnings (loss) per share  0.53   (0.14 
 Diluted earnings (loss) per share  0.52   (0.14 

Outstanding stock options totaling 19,606 and 32,350 common shares were excluded from the diluted earnings per share calculation for the three months ended March 31, 2011 and 2010, respectively, as they were antidilutive. For the three months ended March 31, 2010, 176,727 shares of non-vested common stock were excluded from the diluted earnings (loss) per share calculation, as they were antidilutive.

   
  
(11)   Commitments and Contingencies 
   

Leases and Unconditional Purchase Obligations

The minimum required payments for the Company’s lease agreements and unconditional purchase obligations are as follows:

         
     Unconditional
 
 
  Operating
 
  Purchase
 
 
  Leases   Obligations(1)  
  (in thousands)  
 
 Nine months ending December 31, 2011  4,662   67,125  
 Year ending December 31, 2012   6,456    86,825  
 Year ending December 31, 2013   4,599    86,899  
 Year ending December 31, 2014   2,434    86,979  
 Year ending December 31, 2015   1,129    81,285  
 Thereafter   578    407,681  
         
  19,858   816,794  
         
   
(1)  This amount includes approximately $543.5 million payable ratably over ten years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM receives transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. On September 15, 2009, the Company filed a Statement of Claim in the Court of the Queen’s Bench of Alberta, Judicial District of Calgary, to dispute the validity of the petroleum transportation service agreements. The Company and TransCanada settled this claim in March 2011. CRRM began receiving crude oil under the agreements on the terms discussed above in the first quarter of 2011. 
   


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The Company leases various equipment, including rail cars, and real properties under long-term operating leases, expiring at various dates. For the three months ended March 31, 2011 and 2010, lease expense totaled $1,275,000 and $1,192,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at the Company’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. The Company also has other customary operating leases and unconditional purchase obligations primarily related to pipeline, storage, utilities and raw material suppliers. These leases and agreements are entered into in the normal course of business.

Litigation

From time to time, the Company is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. These provisions are reviewed at least quarterly and adjusted to reflect the impacts of negotiations, settlements, rulings, advice of legal counsel, and other information and events pertaining to a particular case. It is possible that management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying condensed consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

Samson Resources Company, Samson Lone Star, LLC and Samson Contour Energy E&P, LLC (together, “Samson”) filed fifteen lawsuits in federal and state courts in Oklahoma and two lawsuits in state courts in New Mexico against CRRM and other defendants between March 2009 and July 2009. In addition, in May 2010, separate groups of plaintiffs filed two lawsuits against CRRM and other defendants in state court in Oklahoma and Kansas. All of the lawsuits filed in state court were removed to federal court. All of the lawsuits (except for the New Mexico suits, which remain in federal court in New Mexico) were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware, where the Sem bankruptcy resides. In March 2011, CRRM was dismissed without prejudice from the New Mexico suits. All of the lawsuits allege that Samson or other respective plaintiffs sold crude oil to a group of companies, which generally are known as SemCrude or SemGroup (collectively, “Sem”), which later declared bankruptcy and that Sem has not paid such plaintiffs for all of the crude oil purchased from Sem. The Samson lawsuits further allege that Sem sold some of the crude oil purchased from Samson to J. Aron & Company (“J. Aron”) and that J. Aron sold some of this crude oil to CRRM. All of the lawsuits seek the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. The amount of the plaintiffs’ alleged claims is unknown since the price and amount of crude oil sold by the plaintiffs and eventually received by CRRM through Sem and J. Aron, if any, is unknown. CRRM timely paid for all crude oil purchased from J. Aron and intends to vigorously defend against these claims. On January 26, 2011, CRRM and J. Aron entered into an agreement whereby J. Aron agreed to indemnify and defend CRRM from any damage, out-of-pocket expense or loss in connection with any crude oil involved in the lawsuits which CRRM purchased through J. Aron, and J. Aron agreed to reimburse CRRM’s prior attorney fees and out-of-pocket expenses in connection with the lawsuits.

CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with its construction that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment has resulted in an increase to annual property tax expense for CRNF by an average of approximately $11.7 million per year for the year ended December 31, 2010, and approximately $10.7 million for the years ended December 31, 2009 and 2008, respectively. CRNF does not agree with the county’s classification of the nitrogen fertilizer plant and CRNF is currently disputing it before the Kansas Court of Tax Appeals (“COTA”). However, CRNF has fully accrued

   


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and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008 The first payment in respect of CRNF’s 2010 property taxes was paid in December 2010 and the second payment was paid in May 2011. These amounts are reflected as a direct operating expense in the Condensed Consolidated Statements of Operations. An evidentiary hearing before COTA occurred during the first quarter of 2011 regarding the property tax claims for the year ended December 31, 2008. CRNF believes COTA is likely to issue a ruling sometime during 2011. However, the timing of a ruling in the case is uncertain, and there can be no assurance CRNF will receive a ruling in 2011. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on the results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, CRNF expects that it will pay taxes at or below the elevated rates described above.

See note (1) to the table at the beginning of this Note 11 (“Commitments and Contingencies”) for a discussion of the TransCanada litigation.

Flood, Crude Oil Discharge and Insurance

Crude oil was discharged from the Company’s refinery on July 1, 2007, due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. In connection with the discharge, the Company received in May 2008, notices of claims from sixteen private claimants under the Oil Pollution Act in an aggregate amount of approximately $4,393,000 (plus punitive damages). In August 2008, those claimants filed suit against the Company in the United States District Court for the District of Kansas in Wichita (the “Angleton Case”). In October 2009, a companion case to the Angleton Case was filed in the United States District Court for the District of Kansas in Wichita, seeking a total of $3,200,000 (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. In August 2010, the Company settled claims with eight of the plaintiffs from the Angleton Case. The settlements did not have a material adverse effect on the consolidated financial statements. The Company believes that the resolution of the remaining claims will not have a material adverse effect on the condensed consolidated financial statements.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the “Consent Order”) with the U.S. Environmental Protection Agency (“EPA”) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of crude oil from the Company’s refinery caused an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery.. The substantial majority of all required remedial actions were completed by January 31, 2009. The Company prepared and provided its final report to the EPA in January 2011 to satisfy the final requirement of the Consent Order. In April 2011, the EPA provided the Company with a notice of completion indicating that the Company has no continuing obligations under the Consent Order, while reserving its rights to recover oversight costs and penalties.

The Company has not estimated or accrued for any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from lawsuits related to the June/July 2007 flood as management does not believe any such fines, penalties or lawsuits would be material nor can they be estimated. On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the EPA claiming approximately $1.8 million in oversight cost reimbursement. The Company has requested detailed cost data in order to evaluate the claim. The Company has reviewed and is in the process of responding to the cost data.

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and property damage claims. On July 10, 2008, the Company filed a lawsuit in the United States District Court for the District of Kansas against certain of the Company’s environmental and property insurance

   


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carriers requesting insurance coverage indemnification for the June/July 2007 flood and crude oil discharge losses. Each insurer reserved its rights under various policy exclusions and limitations and cited potential coverage defenses. Although the Court has now issued summary judgment opinions that eliminate the majority of the insurance defendants’ reservations and defenses, the Company cannot be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The Company has received $25,000,000 of insurance proceeds under its primary environmental liability insurance policy which constitutes full payment to the Company of the primary pollution liability policy limit.

The lawsuit with the insurance carriers under the environmental policies remains the only unsettled lawsuit with the insurance carriers. The property insurance lawsuit has been settled and dismissed.

Environmental, Health, and Safety (“EHS”) Matters

CRRM, Coffeyville Resources Crude Transportation, LLC (“CRCT”), and Coffeyville Resources Terminal, LLC (“CRT”), all of which are wholly-owned subsidiaries of CVR, and CRNF are subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries.

CRRM, CRNF, CRCT and CRT own and/or operate manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CRRM, CRNF, CRCT and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at these locations.

CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under the Resource Conservation and Recovery Act (“RCRA”) to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). In 2005, CRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (“VCPRP”) to address a reported release of UAN at its UAN loading rack. As of March 31, 2011 and December 31, 2010, environmental accruals of $3,273,000 and $4,090,000, respectively, were reflected in the Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, for which $929,000 and $1,538,000, respectively, are included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2031, for which the scope of remediation was arranged with the EPA, and were discounted at the appropriate risk free rates at March 31, 2011 and December 31, 2010, respectively. The accruals include estimated closure

   


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and post-closure costs of $887,000 and $921,000 for two landfills at Mach 31, 2011 and December 31, 2010, respectively. The estimated future payments for these required obligations are as follows:

     
Year Ending December 31,  Amount  
  (in thousands)  
 
 Nine months ended December 31, 2011  765  
 2012   656  
 2013   245  
 2014   245  
 2015   245  
 Thereafter   1,710  
     
 Undiscounted total   3,866  
 Less amounts representing interest at 3.24%   593  
     
 Accrued environmental liabilities at March 31, 2011  3,273  
     

Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM is considered a small refiner under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. Capital expenditures to comply with the rule are expected to be approximately $10.0 million.

In November 2010, the EPA finalized changes to the Renewable Fuel Standards (“RFS”) which require the total volume of renewable transportation fuels sold or introduced in the U.S. to reach 13.95 billion gallons in 2011 and rise to 36 billion gallons by 2022. Due to mandates in the RFS requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the original RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. For the three months ended March 31, 2011, CRRM incurred $3.5 million of expense associated with the required mandate which was included in cost of product sold in the Condensed Consolidated Statements of Operations. CRRM will utilize a combination of blending and purchase of additional RINS in 2011 in order to achieve compliance with the renewable fuel standard for the remainder of 2011.

In March 2004, CRRM and CRT entered into a Consent Decree (the “Consent Decree”) with the EPA and the Kansas Department of Health and Environment (the “KDHE”) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.’s (“Farmland”) prior ownership and operation of the crude oil refinery and Phillipsburg terminal facilities. As a result of CRRM’s agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Under the Consent Decree, CRRM agreed to install controls to reduce emissions of sulfur dioxide, nitrogen oxides and particulate matter from its FCCU by January 1, 2011. In addition, pursuant to the Consent Decree, CRRM and CRT assumed cleanup obligations at the Coffeyville refinery and the Phillipsburg terminal facilities. The remaining costs of complying with the Consent Decree are expected to be approximately $49 million, of which approximately $47 million is expected to be capital expenditures which does not

   


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include the cleanup obligations for historic contamination at the site that are being addressed pursuant to administrative orders issued under RCRA. To date, CRRM and CRT have materially complied with the Consent Decree. On June 30, 2009, CRRM submitted a force majeure notice to the EPA and KDHE in which CRRM indicated that it may be unable to meet the Consent Decree’s January 1, 2011 deadline related to the installation of controls on the FCCU because of delays caused by the June/July 2007 flood. In February 2010, CRRM and the EPA agreed to a fifteen month extension of the January 1, 2011, deadline for the installation of controls which was approved by the Court as a material modification to the existing Consent Decree. Pursuant to this agreement, CRRM agreed to offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe.

In the meantime, CRRM has been negotiating with the EPA and KDHE to replace the current Consent Decree, including the fifteen month extension, with a global settlement under the national petroleum refining initiative. Over the course of the last decade, the EPA has embarked on a National Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The Petroleum Refining Initiative has resulted in most refineries entering into consent decrees imposing civil penalties and requiring substantial expenditures for pollution control and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into “global settlements” pertaining to all “marquee” issues. The current Consent Decree covers some, but not all, of the “marquee” issues. The Company has been negotiating with the EPA to expand the existing Consent Decree obligations to include all of the “marquee” issues under the Petroleum Refining Initiative, and the parties have reached an agreement in principle on most of the issues, including an agreement to further extend the deadline for the installation of controls on the FCCU. Under the global settlement, the Company may be required to pay a civil penalty, but the incremental capital expenditures would not be material and would be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe.

On February 24, 2010, the Company received a letter from the United States Department of Justice on behalf of the EPA seeking a $900,000 civil penalty related to alleged late and incomplete reporting of air releases in violation of the Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right to Know Act. The Company has reviewed and intends to contest the EPA’s allegation.

In 2007, the federal Occupational Safety and Health Act (“OSHA”) began process safety management (“PSM”) inspections of all refineries under its jurisdiction as part of its National Emphasis Program (the “NEP”). In addition, OSHA announced in 2009 that it was going to pursue NEP inspections for chemical operations. As such, OSHA began a PSM NEP inspection at the nitrogen fertilizer plant in late 2010 resulting in an assessed penalty of approximately $9,700 and noted no serious violations.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended March 31, 2011 and 2010, capital expenditures were approximately $1,578,000 and $7,663,000, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

CRRM, CRNF, CRCT and CRT each believe it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.

   


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(12)   Long-Term Debt 
   

Long-term debt was as follows:

         
  March 31,
 
  December 31,
 
 
  2011   2010  
  (in thousands)  
 
 9.0% Senior Secured Notes, due 2015, net of unamortized discount of $1,013 and $1,065 as of March 31, 2011 and December 31, 2010, respectively  246,487   246,435  
 10.875% Senior Secured Notes, due 2017, net of unamortized discount of $2,412 and $2,481 as of March 31, 2011 and December 31, 2010, respectively   222,588    222,519  
         
 Long-term debt  469,075   468,954  
         

Senior Secured Notes

On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed a private offering of $275,000,000 aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225,000,000 aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. The associated original issue discount of the Notes is amortized to interest expense and other financing costs over the respective term of the Notes. On December 30, 2010, CRLLC made a voluntary unscheduled principal payment of $27,500,000 on the First Lien Notes that resulted in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount. At March 31, 2011, the estimated fair value of the First and Second Lien Notes was $269,156,000 and $255,938,000, respectively. These estimates of fair value were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities. The Notes are fully and unconditionally guaranteed by each of CRLLC’s subsidiaries that also guarantee the first priority credit facility. In connection with the closing of the Partnership’s initial public offering in April 2011, the Partnership and CRNF were released from their guarantees of the Notes.

The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year.

Senior Notes Tender Offer

The completion of the initial public offering of the Partnership in April 2011 triggered a Fertilizer Business Event (as defined in the indentures governing the Notes). As a result, CRLLC and Coffeyville Finance Inc. were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes, as required in the indentures governing the Notes. Holders of the Notes have until May 16, 2011 to properly tender Notes they wish to have repurchased.

ABL Credit Facility

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (“ABL credit facility”) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility is scheduled to mature in August 2015 and

   


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replaced the $150.0 million first priority revolving credit facility which was terminated. The ABL credit facility will be used to finance ongoing working capital, capital expenditures, letter of credit issuances and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to $500.0 million (in the aggregate), subject to additional lender commitments. As of March 31, 2011, CRLLC had availability under the ABL credit facility of $208,356,000 and had letters of credit outstanding of approximately $41,644,000. There were no borrowings outstanding from the ABL credit facility as of March 31, 2011.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to prime rate plus 2.0% for Base Rate Loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

The ABL credit facility contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, creation of liens on assets, the ability to dispose of assets, make restricted payments, investments or acquisitions, enter into sale-lease back transactions or enter into affiliate transactions. The ABL credit facility also contains a fixed charge coverage ratio financial covenant that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility. As of March 31, 2011, CRLLC was in compliance with the covenants of the ABL credit facility.

In connection with the ABL credit facility, through March 31, 2011, CRLLC has incurred lender and other third party costs of approximately $4,996,000. These costs will be deferred and amortized to interest expense and other financing costs using a straight-line method over the term of the facility. Additionally, in connection with termination of the first priority credit facility, a portion of the unamortized deferred financing costs associated with this facility, totaling approximately $1,908,000, was written off in the first quarter of 2011. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, the remaining $781,000 unamortized deferred financing costs associated with the first priority credit facility will continue to be amortized over the term of the ABL credit facility.

Included in other current liabilities on the Condensed Consolidated Balance Sheets is accrued interest payable totaling $23,780,000 and $12,167,000 as of March 31, 2011 and December 31, 2010, respectively. As of March 31, 2011, of the accrued interest payable, approximately $23,372,000 is related to the Notes. As of December 31, 2010, of the accrued interest payable, approximately $11,837,000 is related to the Notes and the first priority credit facility borrowing arrangement.

In connection with the closing of the Partnership’s initial public offering in April 2011, the Partnership and CRNF were released as guarantors of the ABL credit facility.

See Note 17 (“Subsequent Events”) for discussion of the $125.0 million credit facility entered into in April 2011 by CRNF to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF.

   
  
(13)   Fair Value Measurements 
   

In accordance with ASC Topic 820 —  Fair Value Measurements and Disclosures(“ASC 820”), the Company utilizes the market approach to measure fair value for its financial assets and liabilities. The market approach uses prices and other relevant information generated by market transactions involving identical or comparable assets or liabilities.

   


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ASC 820 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:

   
 •  Level 1 — Quoted prices in active market for identical assets and liabilities 
 
 •  Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities) 
 
 •  Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value) 

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of March 31, 2011 and December 31, 2010:

                 
  March 31, 2011  
  Level 1   Level 2   Level 3   Total  
  (in thousands)  
 
 Location and Description                 
 Cash equivalents (money market account)  11,057   —   —   11,057  
 Other current assets (marketable securities)   27    —    —    27  
                 
 Total Assets  11,084   —   —   11,084  
                 
 Other current liabilities (Other derivative agreements)   —    (7,301   —    (7,301 
                 
 Total Liabilities  —   (7,301  —   (7,301 
                 
                 
  December 31, 2010  
  Level 1   Level 2   Level 3   Total  
  (in thousands)  
 
 Location and Description                 
 Cash equivalents (money market account)  70,052   —   —   70,052  
 Other current assets (marketable securities)   26    —    —    26  
                 
 Total Assets  70,078   —   —   70,078  
                 
 Other current liabilities (Other derivative agreements)   —    (4,043   —    (4,043 
                 
 Total Liabilities  —   (4,043  —   (4,043 
                 

As of March 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company’s money market account, available-for-sale marketable securities and derivative instruments. Additionally, the fair value of the Company’s Notes is disclosed in Note 12 (“Long-Term Debt”). The Company’s commodity derivative contracts giving rise to a liability under Level 2 are valued using broker quoted market prices of similar commodity contracts. The Company had no transfers of assets or liabilities between any of the above levels during the three months ended March 31, 2011.

The Company’s investments in marketable securities are classified as available-for-sale, and as a result, are reported at fair market value using quoted market prices. These marketable securities totaled approximately $27,000 as of March 31, 2011 and are included in other current assets on the Condensed Consolidated Balance Sheets. Unrealized gains or losses, net of related income taxes are reported as a component of accumulated other comprehensive income. For the three months ended March 31, 2011, the unrealized gain, net of tax, associated with these marketable securities was nominal.

   


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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   
  
(14)   Derivative Financial Instruments 
   

Gain (loss) on derivatives, net consisted of the following:

         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (in thousands)  
 
 Realized gain (loss) on other derivative agreements  (18,848  85  
 Unrealized gain (loss) on other derivative agreements   (3,258   1,435  
 Realized gain (loss) on interest rate swap agreements   —    (1,775 
 Unrealized gain (loss) on interest rate swap agreements   —    1,745  
         
 Total gain (loss) on derivatives, net  (22,106  1,490  
         

CVR is subject to price fluctuations caused by supply and demand conditions, weather, economic conditions, interest rate fluctuations and other factors. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Company from time to time enters into various commodity derivative transactions. The Company, as further described below, entered into an interest rate swap as required by its long-term debt agreements. The interest rate swap was for the purpose of managing interest rate risk.

CVR has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative instruments, such as exchange-traded crude oil futures and certain over-the-counter forward swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges for GAAP purposes. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

CVR maintains a margin account to facilitate other commodity derivative activities. A portion of this account may include funds available for withdrawal. These funds are included in cash and cash equivalents within the Condensed Consolidated Balance Sheets. The maintenance margin balance is included within other current assets within the Condensed Consolidated Balance Sheets. Dependant upon the position of the open commodity derivatives, the amounts are accounted for as an other current asset or an other current liability within the Condensed Consolidated Balance Sheets. From time to time, CVR may be required to deposit additional funds into this margin account.

Interest Rate Swap

Until June 30, 2010, CRLLC held derivative contracts known as interest rate swap agreements (the “Interest Rate Swap”) that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of $180,000,000 from March 31, 2009 until March 31, 2010 and $110,000,000 from March 31, 2010 until June 30, 2010. The Interest Rate Swap expired on June 30, 2010. Half of the Interest Rate Swap agreements were held with a related party (as described in Note 15, “Related Party Transactions”), and the other half were held with a financial institution that was also a lender under CRLLC’s first priority credit facility until April 6, 2010.

Under the Interest Rate Swap, CRLLC paid the fixed rate of 4.195% and received a floating rate based on three month LIBOR rates, with payments calculated on the notional amount. The notional amount did not represent the actual amount exchanged by the parties but instead represented the amount on which the contracts were based. The Interest Rate Swap was settled quarterly and marked to market at each reporting date with all unrealized gains and losses recognized in income. Transactions related to the Interest Rate Swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments.

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   
  
(15)   Related Party Transactions 
   

Until February 2011, the Goldman Sachs Funds and Kelso Funds owned approximately 40% of CVR. Through a registered public offering, the Goldman Sachs Funds and the Kelso Funds sold into the public market shares of CVR Energy common stock in February 2011. As a result of this sale, the Goldman Sachs Funds are no longer a stockholder of the Company and, as of the date of this Report, the Kelso Funds’ own approximately 9% of CVR’s common stock.

Interest Rate Swap

On June 30, 2005, the Company entered into three Interest Rate Swap agreements with J. Aron. These swap agreements expired on June 30, 2010. As such, there was no financial statement impact for the three months ended March 31, 2011. Net losses totaling $15,000 were recognized related to these swap agreements for the three months ended March 31, 2010 and were reflected in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. See Note 14, (“Derivative Financial Instruments”) for additional information.

Cash and Cash Equivalents

The Company holds a portion of its cash balance in a highly liquid money market account with average maturities of less than 90 days within the Goldman Sachs Funds family. As of March 31, 2011 and December 31, 2010, the balance in the account was approximately $11,057,000 and $70,052,000, respectively. For the three months ended March 31, 2011, the account earned interest income of approximately $5,000. The interest income earned on the account for the three months ended March 31, 2010 was nominal.

Financing and Other

In March 2010, CRLLC amended its outstanding first priority credit facility. In connection with the amendment, CRLLC paid a subsidiary of GS fees and expenses of $905,000 for their services as lead bookrunner.

For the three months ended March 31, 2011 and 2010, the Company recognized approximately $265,000 and $21,000, respectively, in expenses for the benefit of GS and Kelso in accordance with CVR’s Registration Rights Agreement. These amounts included registration and filing fees, printing fees, external accounting fees and external legal fees.

In connection with the Offering of the Partnership, an affiliate of GS received an underwriting fee of $5,741,000 for their role as joint book-running managers. In April 2011, CRNF entered into a credit facility as discussed further in Note 17 (“Subsequent Events”) whereby an affiliate of GS was paid fees and expenses of $2,004,000.

   
  
(16)   Business Segments 
   

The Company measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in ASC Topic 280 —  Segment Reporting. All operations of the segments are located within the United States.

Petroleum

Principal products of the Petroleum Segment are refined fuels, propane and petroleum refining by-products including pet coke. The Petroleum Segment sells the pet coke to the Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant in accordance with a pet coke supply agreement. For the Petroleum Segment, a per-ton transfer price is used to record intercompany sales on the

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   

part of the Petroleum Segment and a corresponding intercompany cost of product sold (exclusive of depreciation and amortization) is recorded for the Nitrogen Fertilizer Segment. The price the Nitrogen Fertilizer Segment pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in Petroleum net sales were $1,372,000 and $413,000 for the three months ended March 31, 2011 and 2010, respectively.

The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “Nitrogen Fertilizer” for the three months ended March 31, 2011 and 2010 of $719,000 and $568,000, respectively.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was $750,000 and $438,000 for the three months ended March 31, 2011 and 2010, respectively.

Pursuant to the feedstock agreement, the Company’s segments have the right to transfer excess hydrogen to one another. Sales of hydrogen to the Petroleum Segment have been reflected as net sales for the Nitrogen Fertilizer Segment. Receipts of hydrogen from the Petroleum Segment have been reflected in cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The Nitrogen Fertilizer Segment recorded cost of product sold (exclusive of depreciation and amortization) from intercompany hydrogen purchases of $719,000 and $568,000 for the three months ended March 31, 2011 and 2010, respectively. For the three months ended March 31, 2011 and 2010, there were no net sales of hydrogen from the Nitrogen Fertilizer Segment to the Petroleum Segment.

   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   

Other Segment

The Other Segment reflects intercompany eliminations, cash and cash equivalents, all debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments.

         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (in thousands)  
 
 Net sales         
 Petroleum  1,111,260   856,688  
 Nitrogen Fertilizer   57,377    38,285  
 Intersegment eliminations   (1,372   (461 
         
 Total  1,167,265   894,512  
         
 Cost of product sold (exclusive of depreciation and amortization)         
 Petroleum  930,283   798,951  
 Nitrogen Fertilizer   7,491    4,977  
 Intersegment eliminations   (952   (1,038 
         
 Total  936,822   802,890  
         
 Direct operating expenses (exclusive of depreciation and amortization)         
 Petroleum  45,302   38,389  
 Nitrogen Fertilizer   23,024    22,173  
 Other   —    —  
         
 Total  68,326   60,562  
         
 Insurance recovery — business interruption         
 Petroleum  —   —  
 Nitrogen Fertilizer   (2,870   —  
 Other   —    —  
         
 Total  (2,870  —  
         
 Depreciation and amortization         
 Petroleum  16,916   16,134  
 Nitrogen Fertilizer   4,637    4,665  
 Other   458    461  
         
 Total  22,011   21,260  
         
 Net costs associated with flood         
 Petroleum  108   —  
 Nitrogen Fertilizer   —    —  
 Other   —    —  
         
 Total  108   —  
         
 Operating income (loss)         
 Petroleum  105,690   (7,095 
 Nitrogen Fertilizer   16,766    2,968  
 Other   (12,850   (7,467 
         
 Total  109,606   (11,594 
         
 Capital expenditures         
 Petroleum  4,588   9,109  
 Nitrogen Fertilizer   2,041    1,216  
 Other   708    1,091  
         
 Total  7,337   11,416  
         
   


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CVR Energy, Inc. and Subsidiaries

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

   
         
  As of March 31,
 
  As of December 31,
 
 
  2011   2010  
  (in thousands)  
 
 Total assets         
 Petroleum  1,226,030   1,049,361  
 Nitrogen Fertilizer   479,475    452,165  
 Other   186,457    238,658  
         
 Total  1,891,962   1,740,184  
         
 Goodwill         
 Petroleum  —   —  
 Nitrogen Fertilizer   40,969    40,969  
 Other   —    —  
         
 Total  40,969   40,969  
         
   
  
(17)   Subsequent Events 
   

CRNF Credit Facility

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125,000,000 and a revolving credit facility of $25,000,000 with an uncommitted incremental facility of up to $50,000,000. There is no scheduled amortization of the credit facility with it being due and payable in full at its April 2016 maturity. The Partnership, upon the closing of the credit facility, made a special distribution of approximately $87,192,000 to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Offering. The credit facility will be used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF.

Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for borrowings under the credit facility will be the Eurodollar rate plus a margin of 3.75% or the prime rate plus 2.75% for base rate loans. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership.

The credit facility requires CRNF to maintain a minimum interest coverage ratio and a maximum leverage ratio and contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, creation of liens on assets, the ability to dispose of assets make restricted payments, investments or acquisitions, enter into sale-lease back transactions or enter into affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of its common units provided it is in compliance with the Partnership’s leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility.

   


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

The following discussion and analysis should be read in conjunction with the consolidated financial statements and related notes and with the statistical information and financial data appearing in this Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, as well as our Annual Report on Form 10-K for the year ended December 31, 2010. Results of operations for the three months ended March 31, 2011 are not necessarily indicative of results to be attained for any other period.

Forward-Looking Statements

This Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains “forward-looking statements” as defined by the Securities and Exchange Commission (the “SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

   
 •  statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future; 
 
 •  statements relating to future financial performance, future capital sources and other matters; and 
 
 •  any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions. 

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth in the summary risks noted below and under “Risk Factors” attached hereto as Exhibit 99.1:

   
 •  volatile margins in the refining industry; 
 
 •  exposure to the risks associated with volatile crude oil prices; 
 
 •  the availability of adequate cash and other sources of liquidity for our capital needs; 
 
 •  our ability to forecast our future financial condition or results of operations and our future revenues and expenses; 
 
 •  disruption of our ability to obtain an adequate supply of crude oil; 
 
 •  interruption of the pipelines supplying feedstock and in the distribution of our products; 
 
 •  competition in the petroleum and nitrogen fertilizer businesses; 
 
 •  capital expenditures and potential liabilities arising from environmental laws and regulations; 
 
 •  changes in our credit profile; 
 
 •  the cyclical nature of the nitrogen fertilizer business; 
 
 •  the seasonal nature of our business; 
 
 •  the supply and price levels of essential raw materials; 
 
 •  the risk of a material decline in production at our refinery and nitrogen fertilizer plant; 
 
 •  potential operating hazards from accidents, fire, severe weather, floods or other natural disasters; 
   


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 •  the risk associated with governmental policies affecting the agricultural industry; 
 
 •  the volatile nature of ammonia, potential liability for accidents involving ammonia that cause interruption to our businesses, severe damage to property and/or injury to the environment and human health and potential increased costs relating to the transport of ammonia; 
 
 •  the dependence of the nitrogen fertilizer operations on a few third-party suppliers, including providers of transportation services and equipment; 
 
 •  new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities; 
 
 •  our dependence on significant customers; 
 
 •  the potential loss of the nitrogen fertilizer business’ transportation cost advantage over its competitors; 
 
 •  our potential inability to successfully implement our business strategies, including the completion of significant capital programs; 
 
 •  our ability to continue to license the technology used in our operations; 
 
 •  existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and the end-use and application of fertilizers; 
 
 •  refinery and nitrogen fertilizer facility operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage; 
 
 •  our significant indebtedness, including restrictions in our debt agreements; and 
 
 •  instability and volatility in the capital and credit markets. 

All forward-looking statements contained in this Form 10-Q speak only as of the date of this document. We undertake no obligation to update or revise publicly any forward-looking statements to reflect events or circumstances that occur after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.

Company Overview

CVR Energy, Inc. and, unless the context requires otherwise, its subsidiaries (“CVR”, the “Company”, “we”, “us” or “our”) is an independent refiner and marketer of high value transportation fuels. In addition, until the completion of the initial public offering of CVR Partners (the “Partnership”), a limited partnership which produces nitrogen fertilizers, ammonia and UAN, as discussed in further detail below, we owned all of the interests (other than the managing general partner interest and associated incentive distribution rights) in the Partnership.

Coffeyville Acquisition LLC (“CALLC”) formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering, which was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”).

As of December 31, 2010, approximately 40% of our outstanding shares were owned by certain funds affiliated with Goldman Sachs & Co. and Kelso & Company, L.P. (“GS” and “Kelso”, respectively), through their respective ownership of CALLC II and CALLC. On February 8, 2011, CALLC and CALLC II completed a sale of our common stock into the public market pursuant to a registered public offering. As a result of this offering, GS sold into the public market its remaining ownership interests in CVR Energy. Additionally, Kelso reduced its interest in the Company and as of the date of this report beneficially owns approximately 9% of all shares outstanding.

   


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On April 13, 2011, the Partnership completed its initial public offering of its common units representing limited partner interests (the “Offering”). The Partnership sold 22,080,000 common units (such amount includes commitments issued pursuant to the exercise of the underwriters over-allotment option) at a price of $16.00 per common unit, resulting in gross proceeds (including the gross proceeds from the exercise of the underwriters’ over-allotment option) of $353.3 million prior to underwriting discount and other offering costs. The Partnership’s units are listed on the New York Stock Exchange and are traded under the symbol “UAN.” In connection with the Offering the Partnership paid approximately $24.7 in underwriting fees and incurred approximately $4.0 million of other offering costs. Approximately $5.7 million was paid to an affiliate of GS acting as joint book-running managers. Until completion of the February 2011 secondary offering (described above), an affiliate of GS was a stockholder and a related party of the Company. As a result of the Offering, CVR indirectly owns 69.8% of the Partnership’s outstanding common units and 100% of the Partnership’s general partner with its non-economic general partner interest.

We operate under two business segments: petroleum and nitrogen fertilizer. Throughout the remainder of this document, our business segments are referred to as our “petroleum business” and our “nitrogen fertilizer business,” respectively.

Petroleum business.  Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 35,000 bpd serving Kansas, Oklahoma, western Missouri and southwestern Nebraska, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and at throughput terminals on Magellan and NuStar Energy, LP’s (“NuStar”) refined products distribution systems and (3) a 145,000 bpd pipeline system that transports crude oil to our refinery with 1.2 million barrels of associated company-owned storage tanks and an additional 2.7 million barrels of leased storage capacity located at Cushing, Oklahoma. The crude oil gathering system is supported by approximately 300 miles of Company owned and leased pipeline.

Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. and NuStar.

Crude oil is supplied to our refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead and Keystone pipelines (as discussed more fully in Note 11 to the financial statements) from Canada and have access to foreign and deepwater domestic crude oil via the Seaway Pipeline system from the U.S. Gulf Coast to Cushing. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics and from time to time a variety of South American, North Sea, Middle East and West African imported grades. The access to a variety of crude oils coupled with the complexity of our refinery allows us to purchase crude oil at a discount to WTI. Our consumed crude cost discount to WTI for the first quarter of 2011 was $(5.65) per barrel compared to $(3.02) per barrel in the first quarter of 2010.

Nitrogen fertilizer business.  The nitrogen fertilizer business consists of our interest in the Partnership, which, after its initial public offering, is controlled by us. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility that is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. The nitrogen fertilizer business upgrades a majority of the ammonia it produces to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate

   


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which has historically commanded a premium price over ammonia. In 2010, the nitrogen fertilizer business produced 392,745 tons of ammonia, of which approximately 60% was upgraded into 578,272 tons of UAN.

The primary raw material feedstock utilized in our nitrogen fertilizer production process is pet coke, which is produced during the crude oil refining process. In contrast, substantially all of the nitrogen fertilizer businesses’ competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been significantly less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. By using pet coke as the primary raw material feedstock instead of natural gas, the nitrogen fertilizer business has historically been the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from CVR pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by CVR’s crude oil refinery.

Major Influences on Results of Operations

Petroleum Business

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. 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 factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out (“FIFO”) accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

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 reduction in 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 fuel standards, proposed climate change laws and regulations, and increased mileage standards for vehicles.

In order to assess our operating performance, we compare our net sales, less cost of product sold, or our refining margin, against an industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil is converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 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 the benchmark production of gasoline and distillate.

   


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Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the West Canadian Select (“WCS”) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refinery is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra Low Sulfur Diesel basis. If both gasoline and Ultra Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption for the three months ended March 31, 2011, a $1.00 change of natural gas pricing would have increased or decreased our natural gas costs for the quarter by $1.0 million.

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 significantly reduces the impact of commodity price volatility on our petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent our inventory position deviates from the target level, we consider risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Our hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of our titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on our financial results unless the market value of our target inventory is increased above cost.

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 the needed maintenance, feedstock logistics and other factors. The refinery generally undergoes a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The next turnaround for our refinery is being conducted in two separate phases. The first phase will commence and conclude in the fourth quarter of 2011. The second phase of the turnaround will commence and conclude in the first quarter of 2012.

Our refinery experienced an equipment malfunction and small fire in connection with its FCCU on December 28, 2010, which led to reduced crude throughput and repair cost of approximately $1.9 million, net

   


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of the insurance receivable recorded for the three months ended March 31, 2011. We used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4.0 million in total. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. We estimate that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident.

Nitrogen Fertilizer Business

In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. As a result, volatile swings in natural gas prices have a minimal impact on its results of operations. Instead, our adjacent refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a long-term pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.

Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

Natural gas is the most significant raw material required in our competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility. This pricing and volatility has a direct impact on our competitors’ cost of producing nitrogen fertilizer.

In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs.

We and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to our out-of-region competitors in serving the U.S. farm belt agricultural market. In 2010, approximately 45% of the corn planted in the United States was grown within a $35/UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors’ revenues is derived from the lower margin industrial market. Our location on Union Pacific’s main line increases our transportation cost advantage by lowering the costs of bringing our products to customers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we do not incur any intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $25 per ton over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

   


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The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2010, the nitrogen fertilizer business upgraded approximately 60% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

The direct operating expense structure of the nitrogen fertilizer business also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs have averaged approximately 86% of direct operating expenses over the 24 months ended December 31, 2010.

Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2010, at a cost of approximately $3.5 million. The next facility turnaround is currently scheduled for the fourth quarter of 2012.

Agreements Between CVR Energy and the Partnership

In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership in October 2007, we entered into a number of agreements with the Partnership that govern the business relations between the parties. These include the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; a services agreement, in which our management operates the nitrogen fertilizer business; a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; an easement agreement; an environmental agreement; and a lease agreement pursuant to which we lease office space and laboratory space to the Partnership. Certain of these agreements were amended and/or restated in connection with the Offering.

The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from our adjacent crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.

Vitol Agreement

On March 30, 2011, CRRM and Vitol Inc. (“Vitol”) entered into a Crude Oil Supply Agreement (the “Vitol Agreement”). This agreement replaced the previous supply agreement between CRRM and  Vitol dated December 2, 2008, as amended, which was terminated by  Vitol and CRRM on March 30, 2011.

The Vitol Agreement provides that CRRM will continue to obtain all of the crude oil for CRRM’s refinery through  Vitol, other than the crude oil gathered by us from Kansas, Missouri, North Dakota and Oklahoma, Wyoming and all adjacent states. CRRM and Vitol will continue to work together to identify crude

   


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oil and pricing terms that meet CRRM’s crude oil requirements. CRRM and/or Vitol will negotiate the costs of each barrel of crude oil that is purchased from third-party crude oil suppliers.  Vitol purchases all such crude oil, executes all third-party sourcing transactions and provides transportation and other logistical services for the subject crude oil.  Vitol then sells such crude oil and delivers the same to CRRM. Title and risk of loss for all crude oil purchased by CRRM through the  Vitol Agreement passes to CRRM upon delivery to the Company’s Broome Station, located near Caney, Kansas. CRRM generally pays  Vitol a fixed origination fee per barrel over the negotiated cost of each barrel purchased. The  Vitol Agreement commenced March 30, 2011 and extends for an initial term ending December 31, 2013, but also allows for automatic renewal for successive one-year terms.

Factors Affecting Comparability of Our Financial Results

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

Refinancing and Prior Indebtedness

On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (“ABL credit facility”). The ABL credit facility replaced the first priority credit facility which was terminated. As a result of the termination of the first priority credit facility, we wrote-off a portion of our previously deferred financing costs of approximately $1.9 million. This write-off is reflected on the Condensed Consolidated Statements of Operations as a loss on extinguishment of debt for the three months ended March 31, 2011. In connection with the ABL credit facility, CRLLC incurred approximately $5.0 million of fees that were deferred and are to be amortized over the term of the credit facility on a straight-line basis.

In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing our tranche D term loans’ outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. In April 2010, we paid off the remaining $453.0 million tranche D term loans. This payoff was made possible by the issuance of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million.

On March 12, 2010, CRLLC entered into a fourth amendment to its first priority credit facility. The amendment, among other things, provided CRLLC the opportunity to issue junior lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay the tranche D term loans. The amendment also provided CRLLC the ability to issue up to $350.0 million of first lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay all of the remaining tranche D term loans.

In connection with the fourth amendment, CRLLC incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, CRLLC incurred third party costs of approximately $1.5 million primarily consisting of administrative and legal costs. Of the third party costs incurred we expensed $1.1 million in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs.

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the credit facility matures in April 2016. The Partnership, upon the closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation

   


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of the Offering. The credit facility will be used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF.

Share-Based Compensation

Through a wholly-owned subsidiary, we have two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. We account for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC 718, Compensation — Stock Compensation,the expense associated with these awards is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of our common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.

Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to other than employees for acquiring or in conjunction with selling goods or services. In accordance with this accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. Certain override units were fully vested during the second quarter of 2010. Subsequent to the second quarter of 2010, there was no additional expense incurred with respect to these awards. For the three months ended March 31, 2011 and 2010, we increased compensation expense by $16.9 million and $7.1 million, respectively, as a result of the phantom and override unit share-based compensation awards. We expect to incur additional incremental share-based compensation expense with respect to unvested override units and phantom awards to the extent our common stock price increases.

Through the Company’s Long-Term Incentive Plan, shares of non-vested common stock may be awarded to the Company’s employees, officers, consultants, advisors and directors. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock and the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the three months ended March 31, 2011 and 2010, we incurred compensation expense of $2.2 million and $0.2 million, respectively, related to non-vested share-based compensation awards.

Fertilizer Plant Property Taxes

The nitrogen fertilizer plant received a ten year tax abatement from Montgomery County, Kansas in connection with its construction that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed the nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment has resulted in an increase to annual property tax liability for the plant by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, and approximately $11.7 million for the year ended December 31, 2010. We do not agree with the county’s classification of the nitrogen fertilizer plant and are currently disputing it before the Kansas Court of Tax Appeals (“COTA”). However, we have fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008. The first payment in respect of CRNF’s 2010 property taxes was paid in December 2010 and the second payment was paid in May 2011. These amounts are reflected as a direct operating expense in the nitrogen fertilizer business’ financial results. An evidentiary hearing before COTA occurred during the first quarter of 2011 regarding our property tax claims for the year ended December 31, 2008. We believe COTA is likely to

   


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issue a ruling sometime during 2011. However, the timing of a ruling in the case is uncertain, and there can be no assurance we will receive a ruling in 2011. If we are successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, a portion of the accrued and paid expenses would be refunded to the nitrogen fertilizer business, which could have a material positive effect on its results of operations. If we are not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, we expect that the nitrogen fertilizer business will pay taxes at or below the elevated rates described above.

Noncontrolling Interest

In connection with the April 2011 initial public offering of the Partnership, the noncontrolling interests representing the incentive distribution rights (“IDRs”) of the managing general partner were purchased by the Partnership and the IDRs were subsequently extinguished. The payment for the IDRs was paid to owners of CALLC III, which included GS, Kelso and members of CVR senior management. As a result of the Offering, the Company recorded a noncontrolling interest for the common units sold into the public market which represented an approximately 30.2% interest in the net book value of the Partnership at the time of the Offering. Effective with the Offering, CVR Energy’s noncontrolling interest reflected on the consolidated balance sheet will be impacted by approximately 30.2% of the net income of the Partnership and related distributions for each future reporting period. The revenue and expenses from the Partnership will continue to be consolidated with CVR Energy’s statement of operations based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy; and therefore has the ability to control the activities of the Partnership. However, the percentage of ownership held by the public unitholders will be reflected as net income attributable to noncontrolling interest in our consolidated statement of operations and will reduce consolidated net income to derive net income attributable to CVR Energy, Inc.

Publicly Traded Partnership Expenses

We expect that our general and administrative expenses will increase due to the costs of the Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements, including annual and quarterly reports to unit holders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses will approximate $3.5 million per year, excluding the costs associated with the costs of the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing. Our future consolidated financial statements will reflect the impact of these expenses, which will affect the comparability of its post-offering results with its financial statements from periods prior to the completion of the initial public offering.

September 2010 UAN Vessel Rupture

On September 30, 2010, our nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. The nitrogen fertilizer facility had previously scheduled a major turnaround to begin on October 5, 2010. To minimize disruption and impact to the production schedule, the turnaround was accelerated. The turnaround was completed on October 29, 2010 with the gasification and ammonia units in operation. The fertilizer facility restarted production of UAN on November 16, 2010 and as of December 31, 2010 repairs to the facility as a result of the rupture were substantially complete. Besides adversely impacting UAN sales in the fourth quarter of 2010, the outage caused us to shift delivery of lower priced tons from the fourth quarter of 2010 to the first and second quarters of 2011.

Total gross costs recorded as of March 31, 2011 due to the incident were approximately $10.9 million for repairs and maintenance and other associated costs. We recorded an insurance receivable of $4.5 million under the property damage coverage of which approximately $4.3 million of insurance proceeds were received as of December 31, 2010 and the remaining $0.2 million was received in January 2011. Of the costs incurred, approximately $4.5 million were capitalized. We also recognized income of approximately $2.9 million from our business interruption insurance policy in the first quarter of 2011. We received approximately $2.3 million related to the business interruption claim and received the remaining $0.6 million in April 2011.

   


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Distributions to Unitholders

Following the initial public offering, the Partnership intends to make cash distributions of all available cash it generates each quarter beginning with the quarter ending June 30, 2011, covering April 13, 2011, the closing of its initial public offering through June 30, 2011. Available cash for each quarter will be determined by the Partnership’s board of directors of its general partner following the end of such quarter. We expect that available cash for each quarter will generally equal the Partnership’s cash flow from operations for the quarter, less cash needed for maintenance, capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the Partnership’s general partner deems necessary or appropriate. However, the board of directors of the general partner may modify the cash distribution policy at any time and the partnership agreement does not require the Partnership to make distributions at all.

Results of Operations

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three months ended March 31, 2011 and 2010. The summary financial data for our two operating segments does not include certain selling, general and administrative expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” except for the balance sheet data as of December 31, 2010, is unaudited.

         
  Three Months Ended
 
 
  March 31,  
Consolidated Statement of Operations Data  2011   2010  
  (unaudited)
 
 
  (in millions, except share data)  
 
 Net sales  1,167.3   894.5  
 Cost of product sold(1)   936.8    802.9  
 Direct operating expenses(1)   68.3    60.6  
 Insurance recovery — business interruption   (2.9   —  
 Selling, general and administrative expenses(1)   33.4    21.3  
 Net costs associated with flood   0.1    —  
 Depreciation and amortization(2)   22.0    21.3  
         
 Operating income (loss)  109.6   (11.6 
 Other income, net   0.5    0.4  
 Interest expense and other financing costs   (13.2   (9.9 
 Gain (loss) on derivatives, net   (22.1   1.5  
 Loss on extinguishment of debt   (1.9   (0.5 
         
 Income (loss) before income tax expense (benefit)  72.9   (20.1 
 Income tax expense (benefit)   27.1    (7.7 
         
 Net income (loss)(3)  45.8   (12.4 
 Basic earnings (loss) per share  0.53   (0.14 
 Diluted earnings (loss) per share  0.52   (0.14 
 Weighted-average common shares outstanding:         
 Basic   86,413,781    86,329,237  
 Diluted   87,783,857    86,329,237  
   


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  As of March 31,
 
 As of December 31,
 
  2011  2010 
  (unaudited)   
  (in millions) 
 
Balance Sheet Data         
 Cash and cash equivalents  165.9   200.0  
 Working capital   402.2    333.6  
 Total assets   1,892.0    1,740.2  
 Total debt, including current portion   470.6    477.0  
 Total CVR stockholders’ equity   743.2    689.6  
         
  Three Months Ended
 
  March 31, 
  2011  2010 
  (unaudited)
 
  (in millions) 
 
Cash Flow Data         
 Net cash flow provided by (used in):         
 Operating activities  (16.0  43.4  
 Investing activities   (7.1   (11.4 
 Financing activities   (11.1   (31.4 
Other Financial Data         
 Capital expenditures for property, plant and equipment  7.3   11.4  
 Depreciation and amortization   22.0    21.3  
   
(1)  Amounts are shown exclusive of depreciation and amortization. 
 
(2)  Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general and administrative expenses: 
         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)
 
 
  (in millions)  
 
 Depreciation and amortization excluded from cost of product sold  0.6   0.8  
 Depreciation and amortization excluded from direct operating expenses   20.9    20.0  
 Depreciation and amortization excluded from selling, general and administrative expenses   0.5    0.5  
         
 Total depreciation and amortization  22.0   21.3  
         
   
(3)  The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance: 
         
  Three Months Ended
 
  March 31, 
  2011  2010 
  (unaudited)
 
  (in millions) 
 
 Loss on extinguishment of debt(a)  1.9   0.5  
 Letter of credit expense and interest rate swap not included in interest expense(b)   0.8    2.3  
 Share-based compensation expense(c)   19.1    7.3  
 Major scheduled turnaround expense(d)   3.1    —  
   

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 (a)  On February 22, 2011, CRLLC entered into a $250.0 million ABL credit facility, as described in further detail below. The ABL credit facility replaced the first priority credit facility which was terminated. As a result of the termination of the first priority credit facility we wrote-off a portion of our previously deferred financing costs of approximately $1.9 million. In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. 
   
 (b)  Consists of fees which are expensed to selling, general and administrative expenses in connection with letters of credit outstanding. 
   
 (c)  Represents the impact of share-based compensation awards. 
   
 (d)  Represents expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery. 

Petroleum Business Results of Operations

The following tables below provide an overview of the petroleum business’ results of operations, relevant market indicators and its key operating statistics:

         
  Three Months
 
 
  Ended March 31,  
  2011   2010  
  (unaudited)
 
 
  (in millions)  
 
Petroleum Business Financial Results         
 Net sales  1,111.3   856.7  
 Cost of product sold(1)   930.3    799.0  
 Direct operating expenses(1)(2)   45.3    38.4  
 Net costs associated with flood   0.1    —  
 Depreciation and amortization   16.9    16.1  
         
 Gross profit(3)  118.7   3.2  
 Plus direct operating expenses(1)   45.3    38.4  
 Plus net costs associated with flood   0.1    —  
 Plus depreciation and amortization   16.9    16.1  
         
 Refining margin(4)   181.0    57.7  
 Operating income (loss)  105.7   (7.1 
 Adjusted Petroleum EBITDA(5)  91.7   (4.4 
         
  Three Months
 
  Ended March 31, 
  2011  2010 
  (unaudited)
 
  (in millions) 
 
Key Operating Statistics         
 Per crude oil throughput barrel:         
 Refining margin(4)  20.38   6.10  
 Gross profit(3)  13.36   0.34  
 Direct operating expenses(1)(2)  5.10   4.06  
 Direct operating expenses per barrel sold(1)(6)  4.88   3.63  
 Barrels sold (barrels per day)(6)   103,200    117,556  
   


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  Three Months Ended March 31,  
  2011   2010  
     %      %  
 
Refining Throughput and Production Data (bpd)                 
 Throughput:                 
 Sweet   79,924    75.7    84,867    75.0  
 Light/medium sour   599    0.6    7,527    6.6  
 Heavy sour   18,161    17.2    12,746    11.3  
                 
 Total crude oil throughput   98,684    93.5    105,140    92.9  
 All other feedstocks and blendstocks   6,873    6.5    7,980    7.1  
                 
 Total throughput   105,557    100.0    113,120    100.0  
 Production:                 
 Gasoline   49,610    46.9    59,036    51.6  
 Distillate   42,876    40.6    45,234    39.5  
 Other (excluding internally produced fuel)   13,200    12.5    10,184    8.9  
                 
 Total refining production (excluding internally produced fuel)   105,686    100.0    114,454    100.0  
                 
 Product price (dollars per gallon):                 
 Gasoline  2.65       2.04      
 Distillate  2.90       2.05      
         
  Three Months Ended
 
  March 31, 
  2011  2010 
 
Market Indicators (dollars per barrel)         
 West Texas Intermediate (WTI) NYMEX  94.60   78.88  
 Crude Oil Differentials:         
 WTI less WTS (light/medium sour)   4.10    1.89  
 WTI less WCS (heavy sour)   21.95    10.47  
 NYMEX Crack Spreads:         
 Gasoline   18.03    9.72  
 Heating Oil   23.94    7.24  
 NYMEX 2-1-1 Crack Spread   20.99    8.48  
 PADD II Group 3 Basis:         
 Gasoline   (2.05   (2.73 
 Ultra Low Sulfur Diesel   1.15    (0.36 
 PADD II Group 3 Product Crack:         
 Gasoline   15.98    6.99  
 Ultra Low Sulfur Diesel   25.10    6.88  
 PADD II Group 3 2-1-1   20.54    6.93  
   
(1)  Amounts are shown exclusive of depreciation and amortization. 
 
(2)  Direct operating expense is presented on a per crude oil throughput basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period. 
   

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(3)  In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period. 
 
(4)  Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) are taken directly from our Condensed Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and allow for greater transparency in the review of our overall financial, operational and economic performance. 
 
(5)  Adjusted Petroleum EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the petroleum segment for the three months ended March 31, 2011 and 2010: 
         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)  
  (in millions)  
 
Petroleum:         
 Petroleum operating income  105.7   (7.1 
 FIFO impacts (favorable), unfavorable(a)   (21.9   (15.7 
 Share-based compensation   6.6    2.1  
 Major scheduled turnaround expenses(b)   3.1    —  
 Realized gain (loss) on derivatives, net   (18.8   0.1  
 Depreciation and amortization   16.9    16.1  
 Other income (expense)   0.1    0.1  
         
 Adjusted Petroleum EBITDA  91.7   (4.4 
   
(a)  FIFO is the petroleum business’ basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period. 
 
(b)  Represents expense associated with a major scheduled turnaround at our refinery. 
   


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(6)  Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refinery. We utilize the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of barrels sold for the period to derive the metric. 

Nitrogen Fertilizer Business Results of Operations

The tables below provide an overview of the nitrogen fertilizer business’ results of operations, relevant market indicators and key operating statistics:

         
  Three Months Ended
 
  March 31, 
Nitrogen Fertilizer Business Financial Results  2011  2010 
  (unaudited) 
  (in millions) 
 
 Net sales  57.4   38.3  
 Cost of product sold(1)   7.5    5.0  
 Direct operating expenses(1)   23.0    22.2  
 Insurance recovery — business interruption   (2.9   —  
 Net costs associated with flood   —    —  
 Depreciation and amortization   4.6    4.7  
 Operating income (loss)  16.8   3.0  
 Adjusted Nitrogen Fertilizer EBITDA(2)  25.9   8.8  
         
  Three Months Ended
 
 
  March 31,  
Key Operating Statistics  2011   2010  
 
 Production (thousand tons):         
 Ammonia (gross produced)(3)   105.3    105.1  
 Ammonia (net available for sale)(3)   35.2    38.2  
 UAN   170.6    163.8  
 Pet coke consumed (thousand tons)   124.1    117.7  
 Pet coke (cost per ton)  15   14  
 Sales (thousand tons)(4):         
 Ammonia   27.3    31.2  
 UAN   179.3    155.8  
         
 Total sales   206.6   187.0  
 Product pricing (plant gate) (dollars per ton)(4):         
 Ammonia  564   282  
 UAN  207   167  
 On-stream factor(5):         
 Gasification   100.0   96.0 
 Ammonia   96.7   94.2 
 UAN   93.2   90.6 
 Reconciliation to net sales (dollars in millions):         
 Freight in revenue  4.8   3.5  
 Hydrogen revenue   —    —  
 Sales net plant gate   52.6    34.8  
         
 Total net sales  57.4   38.3  
   


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  Three Months Ended
 
  March 31, 
Market Indicators  2011  2010 
 
 Natural gas NYMEX (dollars per MMBtu)  4.20   4.99  
 Ammonia — Southern Plains (dollars per ton)  605   330  
 UAN — Mid Cornbelt (dollars per ton)  349   245  
   
(1)  Amounts are shown exclusive of depreciation and amortization. 
 
(2)  Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for share-based compensation, major scheduled turnaround expenses, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the nitrogen fertilizer segment for the three months ended March 31, 2011 and 2010: 
         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)  
 
Nitrogen Fertilizer:         
 Nitrogen fertilizer operating income  16.8   3.0  
 Share-based compensation   4.6    1.1  
 Major scheduled turnaround expenses   —    —  
 Depreciation and amortization   4.6    4.7  
 Other income (expense)   (0.1   —  
         
 Adjusted Nitrogen Fertilizer EBITDA  25.9   8.8  
   
(3)  The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN. 
 
(4)  Plant gate sales per ton represent net sales less freight and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. 
 
(5)  On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. 

Three Months Ended March 31, 2011 Compared to the Three Months Ended March 31, 2010

Consolidated Results of Operations

Net Sales.  Consolidated net sales were $1,167.3 million for the three months ended March 31, 2011 compared to $894.5 million for the three months ended March 31, 2010. The increase of $272.8 million for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was due to an increase in petroleum net sales of approximately $254.6 million that resulted primarily from higher product prices. The reduction in petroleum sales volumes was the result of reduced crude oil throughput in January 2011, due to the equipment malfunction and small fire in connection with the FCCU that occurred on December 28, 2010. The average sales price for gasoline was $2.65 per gallon and distillate was $2.90 per gallon for the three months ended March 31, 2011. Gasoline and distillate prices per gallon increased

   

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approximately 29.6% and 41.4%, respectively, for the three months ended March 31, 2011 compared to the three months ended March 31, 2010. The increase in petroleum sales were coupled with an increase in nitrogen fertilizer net sales of $19.1 million for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The increase in nitrogen net sales was primarily due to higher average plant gate prices coupled with higher overall sales volume.

Cost of Product Sold (Exclusive of Depreciation and Amortization).  Consolidated cost of product sold (exclusive of depreciation and amortization) was $936.8 million for the three months ended March 31, 2011 as compared to $802.9 million for the three months ended March 31, 2010. The increase of $133.9 million for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 primarily resulted from an increase in crude oil prices. On a quarter-over-quarter basis, our consumed crude oil costs increased approximately $77.4 million. The increase of crude oil costs is primarily the result of increased prices offset by a decrease in crude oil throughput on a quarter over quarter basis. Consumed crude oil cost per barrel increased approximately 18% from an average price of $75.91 per barrel for the three months ended March 31, 2010 to an average price of $89.60 per barrel for the three months ended March 31, 2011. Increases in feedstocks other than crude oil resulted in an additional cost of product sold of approximately $52.8 million. Effective January 1, 2011, our refinery was subject to the provisions of the Renewable Fuel Standards, which mandates the use of renewable fuels. To meet this mandate, the refinery must either blend renewable fuels into gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. As a result of this mandate, the petroleum business incurred an additional $3.5 million of expense for the three months ended March 31, 2011 which is reflected in our cost of product sold (exclusive of depreciation and amortization). Additionally, the increase in cost of product sold (exclusive of depreciation and amortization) by the petroleum business was coupled with a slight increase of $2.5 million associated with the nitrogen fertilizer’s cost of product sold (exclusive of depreciation and amortization).

Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Consolidated direct operating expenses (exclusive of depreciation and amortization) were $68.3 million for the three months ended March 31, 2011 as compared to $60.6 million for the three months ended March 31, 2010. This increase of $7.7 million for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was due to an increase in petroleum direct operating expenses of $6.9 million coupled with an increase in nitrogen fertilizer direct operating expenses of approximately $0.8 million. The increase was primarily attributable to increases in repairs and maintenance ($3.7 million), turnaround ($3.0 million), other direct operating expenses ($0.7 million) and property taxes ($0.5 million). The increase in repairs and maintenance was primarily the result of repairs needed for the FCC unit and cooling tower. These expenses for the three months ended March 31, 2011 totaled approximately $1.9 million net of the insurance receivable recorded. Additionally, the petroleum business incurred turnaround costs related to work in advance of the major scheduled turnaround scheduled to commence in the fourth quarter of 2011 and to be completed in the first quarter of 2012. A portion of the turnaround work completed was done during downtime associated with the FCC unit. These direct operating expense increases were partially offset by decreases in expenses associated with energy and utilities ($2.1 million), refractory brick amortization ($0.4 million) and catalyst ($0.2 million). The decrease in energy and utilities was primarily the result of lower consumption and reduced prices of natural gas used by the petroleum business.

Insurance Recovery — Business Interruption.  During the three months ended March 31, 2011, we recorded business interruption recoveries of $2.9 million related to the September 30, 2010 UAN vessel rupture. As of March 31, 2011, $2.3 million of the proceeds was received and the remaining $0.6 million was received in April 2011.

Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).  Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $33.4 million for the three months ended March 31, 2011 as compared to $21.3 million for the three months ended March 31, 2010. This variance was primarily the result of an increase in expenses associated with share-based compensation ($11.1 million), payroll ($0.8 million), bank charges ($0.3 million), and asset write-offs ($0.3 million). The increase in our share-based compensation expense was the result of an increase in our stock price coupled with additional stock based compensation awards granted in the fourth quarter of 2010.

   


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These increases were partially offset by a decrease in outside services ($0.7 million) and insurance ($0.3 million).

Operating Income (loss).  Consolidated operating income was $109.6 million for the three months ended March 31, 2011 as compared to an operating loss of $11.6 million for the three months ended March 31, 2010. For the three months ended March 31, 2011 as compared to the three months ended March 31, 2010, petroleum operating income increased $112.8 million coupled with an increase in nitrogen fertilizer operating income of $13.8 million. The increase in operating income for both the petroleum and nitrogen fertilizer business was the result of higher product margins. The refining margin per barrel of crude oil throughput increased from $6.10 for the three months ended March 31, 2010 compared to $20.38 per barrel for the three months ended March 31, 2011. The increase due to favorable product margins was partially offset by increases in direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization).

Interest Expense.  Consolidated interest expense for the three months ended March 31, 2011 was $13.2 million as compared to interest expense of $9.9 million for the three months ended March 31, 2010. This $3.3 million increase for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 resulted from the issuance of the Notes on April 6, 2010 in an aggregate principal amount of $500.0 million. The proceeds from the Notes were utilized primarily to pay off our existing tranche D term debt. The $275.0 million in First Lien Notes accrue interest at 9.0% and the $225.0 million in Second Lien Notes accrue interest at 10.875%. In December 2010, we made a $27.5 million payment on the First Lien Notes, thus reducing the principal balance outstanding. The weighted average interest rate of the Notes for the three months ended March 31, 2011 was approximately 9.89%. Interest expense associated with the Notes totaled approximately $11.7 million for the three months ended March 31, 2011. This compares to interest expense associated with our first priority credit facility term loan that totaled approximately $10.1 million for the three months ended March 31, 2010. This interest expense was partially offset by capitalized interest of approximately $0.1 million for the three months ended March 31, 2011 and $0.9 million for the three months ended March 31, 2010. Also impacting interest expense for the three months ended March 31, 2011 is the increased amortization of deferred financing costs, and amortization of the original issue discount associated with the Notes. Amortization of deferred financing costs and original issue discount for the three months ended March 31, 2011 totaled $1.0 million compared to the amortization of deferred financing costs of $0.5 million for the three months ended March 31, 2010.

Gain (loss) on Derivatives, net.  For the three months ended March 31, 2011, we recorded a $22.1 million loss on derivatives, net compared to a $1.5 million gain on derivatives, net for the three months ended March 31, 2010. The loss on derivatives, net for the three months ended March 31, 2011 as compared to the gain on derivatives, net for the three months ended March 31, 2010 was primarily attributable to our other derivative agreements whereby through an over-the-counter market we hedge a portion of our crude oil and finished goods inventory positions. These other derivative agreements provided a net realized and unrealized loss of approximately $22.1 million for the three months ended March 31, 2011 compared to a net realized and unrealized gain of approximately $1.5 million for the three months ended March 31, 2010. The quarter-over-quarter impacts of the interest rate swap that expired June 30, 2010 were nominal. Our other derivative agreements were primarily entered into for the purpose of mitigating our risk due to the purchase of Canadian crude oil purchased outside our intermediation agreement. This Canadian crude oil was purchased at a discount to WTI that will be received and processed primarily in the second quarter of 2011 whereby the discount received will be recognized through cost of product sold (exclusive of depreciation and amortization). As a result of the new agreement with  Vitol effective March 30, 2011, such crude oil purchases will no longer be conducted outside the framework of the  Vitol Agreement.

Income Tax Expense (benefit).  Income tax expense for the three months ended March 31, 2011 was $27.1 million, or 37.2% of income before income tax expense, as compared to income tax benefit of $7.7 million, or 38.4% of loss before income tax benefit, for the three months ended March 31, 2010.

Net Income (loss).  For the three months ended March 31, 2011, net income totaled $45.8 million as compared to a net loss of $12.4 million for the three months ended March 31, 2010. The increase of

   


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$58.2 million for the first quarter of 2011 compared to the first quarter of 2010 was primarily due to an increase in refining margins, nitrogen fertilizer margins and business interruption insurance recoveries. These impacts were partially offset by an increase in direct operating expenses (exclusive of depreciation and amortization), selling, general and administrative expenses (exclusive of depreciation and amortization), interest expense and a loss on derivatives, net in the first quarter of 2011 compared to a gain on derivatives, net for the first quarter of 2010.

Petroleum Business Results of Operations for the Three Months Ended March 31, 2011

Net Sales.  Petroleum net sales were $1,111.3 million for the three months ended March 31, 2011 compared to $856.7 million for the three months ended March 31, 2010. The increase of $254.6 million during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was the result of higher product prices partially offset by lower overall sales volumes. The reduction in petroleum sales volumes was the result of reduced crude oil throughput in January 2011, due to the equipment malfunction and small fire in connection with the FCCU that occurred on December 28, 2010. Our average sales price per gallon for the three months ended March 31, 2011 for gasoline of $2.65 and distillate of $2.90 increased by approximately 29.6% and 41.4%, respectively, as compared to the three months ended March 31, 2010.

                                           
  Three Months Ended March 31, 2011  Three Months Ended March 31, 2010   Total Variance   Price
 
 Volume
 
  Volume(1)  $ per barrel  Sales $(2)  Volume(1)  $ per barrel  Sales $(2)   Volume(1)  Sales $(2)   Variance  Variance 
                    (in millions) 
 Gasoline   5.1   111.10   571.9    5.6   85.74   482.5     (0.5  89.4    142.8   (53.4 
 Distillate   4.0   121.68   483.1    4.1   86.07   351.4     (0.1  131.7    145.4   (13.7 
   
(1)  Barrels in millions 
 
(2)  Sales dollars in millions 

Cost of Product Sold (Exclusive of Depreciation and Amortization).  Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $930.3 million for the three months ended March 31, 2011 compared to $799.0 million for the three months ended March 31, 2010. The increase of $131.3 million during the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was primarily the result of a significant increase in crude oil prices. Our average cost per barrel of crude oil consumed for the three months ended March 31, 2011 was $89.60 compared to $75.91 for the comparable period of 2010, an increase of approximately 18.0%. Sales volume of refined fuels decreased by approximately 4.9% for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010. The impact of FIFO accounting also impacted cost of product sold during the comparable periods. Under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO inventory impact when crude oil prices increase and an unfavorable FIFO inventory impact when crude oil prices decrease. For the three months ended March 31, 2011, we had a favorable FIFO inventory impact of $21.9 million compared to a favorable FIFO inventory impact of $15.7 million for the comparable period of 2010.

Refining margin per barrel of crude oil throughput increased from $6.10 for the three months ended March 31, 2010 to $20.38 for the three months ended March 31, 2011. Refining margin adjusted for FIFO impact was $17.91 per crude oil throughput barrel for the three months ended March 31, 2011, as compared to $4.44 per crude oil throughput barrel for the three months ended March 31, 2010. Gross profit per barrel increased to $13.36 for the three months ended March 31, 2011 as compared to gross profit per barrel of $0.34 in the equivalent period in 2010. The increase of our refining margin per barrel is due to an increase in the average sales prices of our produced gasoline and distillates, partially offset by an increase in our cost of consumed crude oil. Our average sales price of gasoline increased approximately 29.6% and our average sales price for distillates increased approximately 41.4% for the three months ended March 31, 2011 over the comparable period of 2010. Consumed crude oil costs rose due to a 19.9% increase in WTI for the three months ended March 31, 2011 over the three months ended March 31, 2010.

   


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Effective January 1, 2011, our refinery was subject to the provisions of the Renewable Fuel Standards, which mandates the use of renewable fuels. To meet this mandate we must either blend renewable fuels into gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. As a result of this mandate we incurred an additional $3.5 million of expense for the three months ended March 31, 2011 which is reflected in our cost of product sold (exclusive of depreciation and amortization).

Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, property taxes, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $45.3 million for the three months ended March 31, 2011 compared to direct operating expenses of $38.4 million for the three months ended March 31, 2010. The increase of $6.9 million for the three months ended March 31, 2011 compared to the three months ended March 31, 2010 was the result of increases in expenses primarily associated with repairs and maintenance ($2.5 million), turnaround ($3.0 million), labor ($2.0 million), production chemicals ($0.5 million), operating supplies ($0.5 million) and rents ($0.4 million). The increase in repairs and maintenance was primarily the result of repairs needed for the FCC unit and cooling tower. Repair costs for the FCC unit and cooling tower totaled approximately $1.9 million for the three months ended March 31, 2011. These costs are net of the insurance receivable recorded through March 31, 2011. Increases in direct operating expenses were partially offset by decreases in expenses primarily associated with utilities and energy costs ($1.8 million) and other direct operating expenses ($0.2 million). On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the three months ended March 31, 2011 increased to $5.10 per barrel as compared to $4.06 per barrel for the three months ended March 31, 2010.

Operating Income (loss).  Petroleum operating income was $105.7 million for the three months ended March 31, 2011 as compared to operating loss of $(7.1) million for the three months ended March 31, 2010. This increase of $112.8 million from the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was primarily the result of an increase in the refining margin ($123.3 million). The increase in refining margin was partially offset by an increase in direct operating expenses ($6.9 million), an increase in selling, general and administrative expenses ($2.7 million), an increase in flood related costs ($0.1 million) and an increase in depreciation and amortization ($0.8 million). The increase in selling, general and administrative cost is primarily attributable to an increase in share-based compensation expense.

Nitrogen Fertilizer Business Results of Operations for the Three Months Ended March 31, 2011

Net Sales.  Nitrogen fertilizer net sales were $57.4 million for the three months ended March 31, 2011 compared to $38.3 million for the three months ended March 31, 2010. For the three months ended March 31, 2011, ammonia and UAN made up $15.9 million and $41.5 million of our net sales, respectively. This compared to ammonia and UAN net sales of $9.5 million and $28.8 million of our net sales for the three months ended March 31, 2010. The increase of $19.1 million was the result of both higher average plant gate prices for both ammonia and UAN and a 15% increase in UAN sales unit volumes offset by lower ammonia product sales volume. The following table demonstrates the impact of sales volumes and pricing for ammonia and UAN for the quarters ending March 31, 2011 and March 31, 2010:

                                           
  Three Months Ended March 31, 2011  Three Months Ended March 31, 2010   Total Variance   Price
 
 Volume
 
  Volume(1)  $ per ton(2)  Sales $(3)  Volume(1)  $ per ton(2)  Sales $(3)   Volume(1)  Sales $(3)   Variance  Variance 
                    (in millions) 
 Ammonia   27,322   581   15.9    31,216   305   9.5     (3,894  6.4    8.6   (2.2 
 UAN   179,314   231   41.5    155,758   185   28.8     23,556   12.7    7.3   5.4  
   
(1)  Sales volume in tons 
 
(2)  Includes freight charges 
 
(3)  Sales dollars in millions 
   


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The decrease in ammonia sales volume for the first quarter of 2011 compared to the first quarter of 2010 was primarily attributable to low inventory levels coming into the quarter compared to the same period last year. UAN sales volume increased due to strong demand backed by increased production levels in the first three months of 2011 over the first quarter of 2010. On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification, ammonia and UAN units continue to demonstrate their reliability as all increased over the first quarter of 2010 with the units reporting 100.0%, 96.7% and 93.2%, respectively, on-stream for the three months ended March 31, 2011.

Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both FOB our plant gate (sold plant) and FOB the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or three months to three months. The plant gate price provides a measure that is consistently comparable period to period. Average plant gate prices for the three months ended March 31, 2011 were higher for both ammonia and UAN over the comparable period of 2010, increasing 100% and 24% respectively. The price increases reflect strong farm belt market conditions. While UAN pricing in the first quarter of 2011 was higher than the comparable period in 2010, it nevertheless was adversely impacted by the outage of a high-pressure UAN vessel that occurred in September 2010. This caused us to shift delivery of lower priced tons from the fourth quarter of 2010 to the first and second quarters of 2011.

The demand for nitrogen fertilizer is affected by the aggregate crop planting decisions and nitrogen fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of nitrogen fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted. See “— Major Influences on Results of Operations — Nitrogen Fertilizer Business.”

Cost of Product Sold (Exclusive of Depreciation and Amortization).  Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold (excluding depreciation and amortization) for the three months ended March 31, 2011 was $7.5 million compared to $5.0 million for the three months ended March 31, 2010. Besides increased costs associated with higher UAN sales volumes, a $1.0 million increase in freight expense was the principal contributor along with increases in pet coke costs ($0.2 million) and hydrogen costs ($0.2 million).

Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Direct operating expenses include costs associated with the actual operations of our plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses (exclusive of depreciation and amortization) for the three months ended March 31, 2011 were $23.0 million as compared to $22.2 million for the three months ended March 31, 2010. The $0.8 million increase was primarily the result of increases in expenses for repairs and maintenance ($1.2 million), labor ($0.4 million) and property taxes ($0.5 million). These increases were partially offset by decreases in expenses associated with refractory brick amortization ($0.4 million) utilities ($0.3 million), outside services ($0.3 million) and production chemicals and catalysts ($0.3 million).

Insurance Recovery — Business Interruption.  During the three months ended March 31, 2011, we recorded business interruption recoveries of $2.9 million related to the September 30, 2010 UAN vessel rupture. As of March 31, 2011, $2.3 million of the proceeds were received and the remaining $0.6 million was received in April 2011.

Operating Income.  Nitrogen fertilizer operating income was $16.8 million for the three months ended March 31, 2011 as compared to operating income of $3.0 million for the three months ended March 31, 2010. This increase of $13.8 million was primarily the result of the increase in nitrogen fertilizer margin ($16.6 million), coupled with business interruption recoveries recorded of $2.9 million. These favorable increases were partially offset by an increase in selling, general and administrative expenses (exclusive of depreciation and amortization) ($4.8 million) and direct operating expenses (exclusive of depreciation and amortization) ($0.8 million).

   


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Liquidity and Capital Resources

Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash and cash equivalent balances, our working capital, our ABL credit facility and CRNF’s credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined petroleum and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.

We believe that our cash flows from operations and existing cash and cash equivalents and improvements in our working capital, together with borrowings under our existing revolving facilities as necessary, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.

Cash Balance and Other Liquidity

As of March 31, 2011, we had cash and cash equivalents of $165.9 million. As of March 31, 2011, we had no amounts outstanding under our ABL credit facility and aggregate availability of $208.4 million under our ABL credit facility. Our availability under the ABL credit facility is reduced by outstanding letters of credit. As of March 31, 2011, we had $41.6 million in letters of credit outstanding as provided by our ABL credit facility. As of May 6, 2011, we had $218.4 million available under the ABL credit facility and CRNF had $25.0 million of availability under the credit facility. As of May 6, 2011, the Partnership had cash and cash equivalents of approximately $227.2 million and we had cash and cash equivalents (exclusive of the Partnership) of approximately $453.9 million.

In connection with the completion of the Offering, the Partnership intends to make cash distributions within 45 days after the end of each quarter, beginning with the quarter ending June 30, 2011. The distributions will be made to all common unitholders. CRLLC currently holds approximately 69.8% of all common units outstanding. The amount of the distribution will be determined pursuant to the general partner’s calculation of available cash for the applicable quarter. The general partner, as a non-economic interest holder, is not entitled to receive cash distributions. As a result of the general partner’s distribution policy, funds held by the Partnership will not be available for CRLLC’s use, and CRLLC as a unitholder will receive its applicable percentage of the distribution of funds within 45 days following each quarter. The Partnership does not have a legal obligation to pay distributions and there is no guarantee that it will pay any distributions on the units in any quarter.

Senior Secured Notes

On April 6, 2010, CRLLC and its newly formed wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed the private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due April 1, 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due April 1, 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, we made a voluntary unscheduled principal payment of $27.5 million on our First Lien Notes. As of March 31, 2011, the Notes had an aggregate principal balance of $472.5 million and a net carrying value of $469.1 million.

The First Lien Notes were issued pursuant to an indenture (the “First Lien Notes Indenture”), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the “First Lien Notes Trustee”). The Second Lien Notes were issued pursuant to an indenture (the “Second Lien Notes Indenture” and together with the First Lien Notes Indenture, the “Indentures”), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the “Second Lien Notes Trustee” and in reference to the Indentures, the “Trustee”). The Notes are

   


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fully and unconditionally guaranteed by each of the Company’s subsidiaries that also guarantee the ABL credit facility (the “Guarantors” and, together with the Issuers, the “Credit Parties”).

The First Lien Notes bear interest at a rate of 9.0% per annum and mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes bear interest at a rate of 10.875% per annum and mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year to holders of record at the close of business on March 15 and September 15, as the case may be, immediately preceding each such interest payment date.

The Issuers have the right to redeem the First Lien Notes at the redemption prices set forth below:

   
 •  On or after April 1, 2012, some or all of the First Lien Notes may be redeemed at a redemption price of (i) 106.750% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2012; (ii) 104.500% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; and (iii) 100% of the principal amount, if redeemed on or after April 1, 2014, in each case, plus any accrued and unpaid interest; 
 
 •  Prior to April 1, 2012, up to 35% of the First Lien Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 109.000% of the principal amount thereof, plus any accrued and unpaid interest; 
 
 •  Prior to April 1, 2012, some or all of the First Lien Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest; and 
 
 •  Prior to April 1, 2012, but not more than once in any twelve-month period, up to 10% of the First Lien Notes may be redeemed at a price equal to 103.000% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption. 

The Issuers have the right to redeem the Second Lien Notes at the redemption prices set forth below:

   
 •  On or after April 1, 2013, some or all of the Second Lien Notes may be redeemed at a redemption price of (i) 108.156% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; (ii) 105.438% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2014; (iii) 102.719% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2015; and (iv) 100% of the principal amount if redeemed on or after April 1, 2016, in each case, plus any accrued and unpaid interest; 
 
 •  Prior to April 1, 2013, up to 35% of the Second Lien Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 110.875% of the principal amount thereof, plus any accrued and unpaid interest; and 
 
 •  Prior to April 1, 2013, some or all of the Second Lien Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest. 

In the event of a “change of control” as defined in the Indentures, the Issuers are required to offer to buy back all of the Notes at 101% of their principal amount. A change of control is generally defined as (1) the direct or indirect sale or transfer (other than by a merger) of “all or substantially all of the assets of the Company” to any person other than permitted holders, which are generally GS, Kelso and certain members of management, (2) liquidation or dissolution of CRLLC, (3) any person, other than a permitted holder, directly or indirectly acquiring 50% of the voting stock of CRLLC or (4) the first day when a majority of the directors of CRLLC or CVR Energy are not Continuing Directors (as defined in the Indentures). Continuing Directors are generally our existing directors, directors approved by the then-Continuing Directors or directors nominated or elected by GS or Kelso.

The definition of “change of control” specifically excludes a transaction where CVR Energy becomes a subsidiary of another company, so long as (1) CVR Energy’s shareholders own a majority of the surviving parent or (2) no one person owns a majority of the common stock of the surviving parent following the merger.

   


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The Indentures also allowed the Company to sell, spin-off or complete an initial public offering of the Partnership, as long as the Company offers to buy back a percentage of the Notes as described in the Indentures. In April 2011, the Partnership completed an initial public offering of common units. This offering triggered a Fertilizer Business Event (as defined in the Indentures). As a result, CRLLC and Coffeyville Finance Inc. were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes, as required in the Indentures. Holders of the Notes have until May 16, 2011 to properly tender Notes they wish to have repurchased.

The Indentures impose covenants that restrict the ability of the Credit Parties to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the Notes are rated investment grade by both S&P and Moody’s. However, such covenants would be reinstituted if the Notes subsequently lost their investment grade rating. In addition, the Indentures contain customary events of default, the occurrence of which would result in, or permit the Trustee or holders of at least 25% of the First Lien Notes or Second Lien Notes to cause the acceleration of the applicable Notes, in addition to the pursuit of other available remedies. We were in compliance with the covenants as of March 31, 2011.

The obligations of the Credit Parties under the Notes and the guarantees are secured by liens on substantially all of the Credit Parties’ assets. The liens granted in connection with the First Lien Notes are first-priority liens and rank pari passu with the liens granted to the lenders under the ABL credit facility and certain hedge counterparties. The liens granted in connection with the Second Lien Notes are second-priority liens and rank junior to the aforementioned first-priority liens. In connection with the closing of the Offering, the Partnership and CRNF were released from their guarantees of the Notes.

ABL Credit Facility

CRLLC entered into a $250.0 million ABL credit facility on February 22, 2011, that provides for borrowings, letter of credit issuances and a feature that permits an increase of borrowings up to $500.0 million (in the aggregate) subject to additional lender commitments. The ABL credit facility is scheduled to mature in August 2015 and will be used to finance ongoing working capital, capital expenditures, letter of credit issuances and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total commitment.

Borrowings under the facility bear interest based on a pricing grid determined by the previous quarter’s excess availability. The pricing for borrowings under the ABL credit facility can range from LIBOR plus a margin of 2.75% to LIBOR plus 3.0% or the prime rate plus 1.75% to the prime rate plus 2.0% for base rate loans. Availability under the ABL credit facility is determined by a borrowing base formula supported primarily by cash and cash equivalents, certain accounts receivable and inventory.

Under its terms, the lenders under the ABL credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and rank pari passu with liens granted in connection with the First Lien Notes and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement). In connection with the Offering, the Partnership and CRNF were released from their guarantees of the ABL credit facility.

The ABL credit facility also contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, creation of liens on assets, the ability to dispose assets, make restricted payments, investments or acquisitions, enter into sale-lease back transactions or enter into affiliate transactions. The facility also contains a fixed charge coverage ratio financial covenant that

   


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is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility.

CRNF Credit Facility

On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility (the “credit facility”) with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the credit facility matures in April 2016. The Partnership, upon the closing of the credit facility, made a special distribution of approximately $87.2 million to CRLLC, in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Offering. The Credit Facility will be used to finance on-going working capital, capital expenditures, letter of credit issuances and general needs of CRNF.

Borrowings under the facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for borrowings under the facility will be the Eurodollar rate plus a margin of 3.75% or the prime rate plus 2.75% for base rate loans. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership.

The credit facility requires the Partnership to maintain (i) a minimum interest coverage ratio (ratio of Consolidated Adjusted EBITDA to interest) as of any fiscal quarter of 3.0 to 1.0 and (ii) a maximum leverage ratio (ratio of debt to Consolidated Adjusted EBITDA) of (a) as of any fiscal quarter ending after the closing date and prior to December 31, 2011, 3.50 to 1.0, and (b) as of any fiscal quarter ending on or after December 31, 2011, 3.0 to 1.0 in all cases calculated on a training four quarter basis. It also contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, creation of liens on assets, the ability to dispose assets make restricted payments, investments or acquisitions, enter in to sale-lease back transactions or enter into affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of its common units provided it is in compliance with its leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution and there is no default or event of default under the facility.

The credit facility also contains certain customary representations and warranties, affirmative covenants and events of default, including among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, actual or asserted failure of any guaranty or security document supporting the new credit facility to be in force and effect, and change of control. An event of default will also be triggered if CVR Energy terminates or violates any of CVR Energy’s covenants in any of the intercompany agreements between the Partnership and CVR Energy and such action has a material adverse effect on the Partnership.

Capital Spending

We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.

   


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The following table summarizes our total actual capital expenditures for the three months ended March 31, 2011 by operating segment and major category:

     
  Three Months
 
 
  Ended
 
 
  March 31, 2011  
 
Petroleum Business:     
 Maintenance  3.8  
 Growth   0.8  
     
 Petroleum business total capital excluding turnaround expenditures  4.6  
     
Nitrogen Fertilizer Business:     
 Maintenance   1.8  
 Growth   0.2  
     
 Nitrogen fertilizer business total capital excluding turnaround expenditures  2.0  
     
Corporate:  0.7  
     
Total capital spending  7.3  
     

We expect the petroleum business and corporate related capital expenditures for 2011 to be approximately $94 million and $3 million, respectively. This figure includes an estimated $23 million for construction of additional crude oil storage in Cushing, Oklahoma. These facilities will provide additional capacity of approximately 1,000,000 barrels of crude oil storage. Owning our own storage facilities will provide us additional operational flexibility. Additionally, the refinery turnaround is expected to commence at the beginning of the fourth quarter of 2011 and be completed in the first quarter of 2012. We expect to incur total major scheduled turnaround expenses of approximately $70 million in connection with the refinery turnaround, of which approximately $54 million of this expense is expected to be incurred in 2011.

The nitrogen fertilizer business expects capital expenditures for 2011 to be approximately $47 million. This includes an estimated $38 million for UAN expansion capital expenditures. As the Partnership consummated its initial public offering in April 2011, the Partnership is moving forward with the UAN expansion. We expect that the approximately $135 million UAN expansion, for which approximately $31 million had been spent as of March 31, 2011, will take eighteen to twenty-four months to complete and is expected to be funded by proceeds of the Partnership’s initial public offering and term loan borrowings made by the Partnership.

Our estimated capital expenditures are subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refinery or nitrogen fertilizer plant. Capital spending for the nitrogen fertilizer business has been and will be determined by the board of directors of the general partner of the Partnership.

   


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Cash Flows

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

         
  Three Months Ended
 
 
  March 31,  
  2011   2010  
  (unaudited)  
  (in millions)  
 
 Net cash provided by (used in):         
 Operating activities  (16.0  43.4  
 Investing activities   (7.1   (11.4 
 Financing activities   (11.1   (31.4 
         
 Net increase (decrease) in cash and cash equivalents  (34.2  0.6  
         

Cash Flows Provided by Operating Activities

For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.

Net cash flows used for operating activities for the three months ended March 31, 2011 was $16.0 million. The net cash flow used for operating activities over this period was partially driven by outflows due to trade working capital as well as outflows from other working capital. These outflows were partially offset by net income of $45.8 million. Trade working capital for the three months ended March 31, 2011 resulted in a cash outflow of $108.6 million, primarily attributable to an increase in inventory of $147.9 million, an increase in accounts receivable of $33.9 million and partially offset by an increase in accounts payable of $73.2 million, including amounts accrued for construction-in-progress. Other working capital activities resulted in a net cash outflow of $4.2 million, which was primarily driven by an increase in other prepaid expenses and other current assets of $17.0 million, an increase in the insurance receivable of $8.6 million, primarily attributable to the fire that occurred at the refinery’s FCC unit, and a increase in other current liabilities of approximately $4.1 million. These outflows were partially offset by increases in accrued income taxes $15.2 million, the increase of deferred revenue by $8.0 million and the receipt of insurance proceeds of approximately $2.5 million, the majority of which primarily related to the business interruption claim filed by the nitrogen fertilizer business related to the September 30, 2010 UAN vessel rupture. The increase in deferred revenue is the result of prepayments received for nitrogen fertilizer.

Net cash flows provided by operating activities for the three months ended March 31, 2010 was $43.4 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in trade working capital and other working capital which were partially offset by a net loss for the quarter. Trade working capital for the three months ended March 31, 2010 resulted in a cash inflow of $14.0 million, primarily attributable to a decrease in inventory of $19.2 million, an increase in accounts payable of $9.4 million coupled with the accrual of construction in progress of $1.5 million. This activity was partially offset by an increase in accounts receivable of $16.1 million. In addition, our deferred revenue increased by $19.8 million as a result of the receipt of nitrogen fertilizer payments.

Cash Flows Used in Investing Activities

Net cash used in investing activities for the three months ended March 31, 2011 was $7.1 million compared to $11.4 million for the three months ended March 31, 2010. The decrease in investing activities for the three months ended March 31, 2011 as compared to the three months ended March 31, 2010 was primarily the result of a decrease in capital expenditures. For the three months ended March 31, 2011 petroleum capital expenditure decreased by approximately $4.5 million compared to the three months ended March 31, 2010. For the three months ended March 31, 2011, petroleum capital expenditures totaled approximately $4.6 million compared to $9.1 million for the three months ended March 31, 2010. Significant capital expenditures for the three months ended March 31, 2010, included expenditures for the petroleum business’ ultra low sulfur

   


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gasoline unit of approximately $6.8 million compared to approximately $0.2 million for the three months ended March 31, 2011. This decrease was partially offset by an increase in nitrogen fertilizer capital expenditures. Additionally, we received approximately $0.2 million of insurance proceeds in January 2011 related to the rupture of the UAN vessel that occurred on September 30, 2010.

Cash Flows Used in Financing Activities

Net cash used in financing activities for the three months ended March 31, 2011 was $11.1 million as compared to net cash used in financing activities of $31.4 million for the three months ended March 31, 2010. During the three months ended March 31, 2011, we paid financing costs associated with the ABL credit facility and CRNF credit facility of approximately $4.7 million. During the first quarter of 2011, we also exercised our purchase option related to a corporate asset. This option resulted in a cash outflow of approximately $4.7 million and satisfied a capital lease obligation. Additionally, we paid approximately $1.6 million of costs related to the Offering. During the three months ended March 31, 2010, we paid a $1.2 million scheduled principal payment on our first priority credit facility long-term debt and also made voluntary unscheduled principal payments totaling $25.0 million in the first quarter of 2010 related to our first priority credit facility long-term debt. In the first quarter of 2010, we also paid $5.2 million of financing costs in connection with the fourth amendment to our first priority credit facility and issuance of the Notes.

For the three months ended March 31, 2011, there were no borrowings or repayments under our first priority credit facility or ABL credit facility. As of March 31, 2011, there were no short-term borrowings outstanding under the ABL credit facility. For the three months ended March 31, 2010, we borrowed and repaid $40.0 million in short-term borrowings. These borrowings were made from our first priority revolving credit facility and were for the purpose of facilitating our working capital needs.

Capital and Commercial Commitments

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of March 31, 2011 relating to the Notes, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the period following March 31, 2011 and thereafter. As of March 31, 2011, there were no amounts outstanding under the ABL credit facility. The following table assumes no borrowings are made under the ABL credit facility.

                             
  Payments Due by Period  
  Total   2011   2012   2013   2014   2015   Thereafter  
  (in millions)  
 
Contractual Obligations                             
 Long-term debt(1)  472.5   —   —   —   —   247.5   225.0  
 Operating leases(2)   19.9    4.7    6.5    4.6    2.4    1.1    0.6  
 Capital lease obligations(3)   0.3    0.1    0.1    0.1    —    —    —  
 Unconditional purchase obligations(4)(5)   816.8    67.1    86.8    86.9    87.0    81.3    407.7  
 Environmental liabilities(6)   3.9    0.8    0.7    0.2    0.2    0.2    1.8  
 Interest payments(7)   254.4    41.2    46.7    46.7    46.7    35.9    37.2  
                             
 Total  1,567.8   113.9   140.8   138.5   136.3   366.0   672.3  
Other Commercial Commitments                             
 Standby letters of credit(8)  41.6   —   —   —   —   —   —  
   
(1)  As described above, the Company issued the Notes in an aggregate principal amount of $500.0 million on April 6, 2010. The First Lien Notes and Second Lien Notes bear an interest rate of 9.0% and 10.875% per year, respectively, payable semi-annually. The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier 
   


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  redeemed or repurchased by the Issuers. In December 2010, we made a voluntary unscheduled prepayment on our First Lien Notes of $27.5 million, reducing our aggregate principal balance of the Notes to $472.5 million. On April 14, 2011, we made an offer to purchase $100 million of the Notes, which expires on May 16, 2011. See “— Liquidity and Capital Resources — Senior Secured Notes.” 
 
  The Partnership entered into a new credit facility in connection with the closing of the Offering. The new credit facility includes a $125.0 million term loan, which was fully drawn at closing, and a $25.0 million revolving credit facility, which was undrawn at close. These amounts have not been included in the table above as they were not contractual obligations as of March 31, 2011. 
 
(2)  The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods. 
 
(3)  The amount includes commitments under capital lease arrangements for personal property used for corporate purposes. 
 
(4)  The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville and (c) a product supply agreement with Linde. 
 
(5)  This amount includes approximately $543.5 million payable ratably over ten years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM would receive transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. On September 15, 2009, the Company filed a Statement of Claim in the Court of the Queen’s Bench of Alberta, Judicial District of Calgary, to dispute the validity of the petroleum transportation service agreements. The Company and TransCanada settled this claim in March 2011. CRRM began receiving crude oil under the agreements on the terms discussed above in the first quarter of 2011. 
 
(6)  Environmental liabilities represents (a) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (b) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleaning and Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. 
 
(7)  Interest payments are based on stated interest rates for the respective Notes. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year. 
 
(8)  Standby letters of credit include $0.2 million of letters of credit issued in connection with environmental liabilities, $30.6 million in letters of credit to secure transportation services for crude oil, $1.0 million issued for the purpose of providing support during the transition of letters of credit issued under the first priority credit facility to the ABL credit facility and standby letters of credit totaling $9.8 million issued in support of the purchase of feedstocks. 

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2011.

Recent Accounting Pronouncements

In July 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-20, which amends ASC Topic 310,  Receivablesto provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. This ASU will require an entity to disclose (1) the inherent credit risk in its financing receivables, (2) how the credit risk is analyzed and assessed in calculating the allowance for credit losses and (3) the changes and reasons for those changes in the allowance for credit losses. The provisions of ASU No. 2010-20 are effective for interim and annual reporting periods ending on or

   


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after December 31, 2010. The adoption of this standard did not impact our financial position or results of operations.

In January 2010 the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurementsan amendment to ASC Topic 820,  Fair Value Measurements and Disclosures. This amendment requires an entity t (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements and (iii) enhance disclosures of assets and liabilities subject to fair value measurements. The provisions of ASU No. 2010-06 are effective for us for interim and annual reporting beginning after December 15, 2009, with one new disclosure effective after December 15, 2010. We adopted this ASU as of January 1, 2010. The adoption of this standard did not impact our financial position or results of operations.

Critical Accounting Policies

Our critical accounting policies are disclosed in the “Critical Accounting Policies” section of our Annual Report on Form 10-K for the year ended December 31, 2010. No modifications have been made to our critical accounting policies.

  
Item 3. Quantitative and Qualitative Disclosures About Market Risk 

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. Information about market risks for the three months ended March 31, 2011 does not differ materially from that discussed under Part II — Item 7A of our Annual Report on Form 10-K for the year ended December 31, 2010. We are exposed to market pricing for all of the products sold in the future both at our petroleum business and the nitrogen fertilizer business, as all of the products manufactured in both businesses are commodities.

Our earnings and cash flows and estimates of future cash flows are sensitive to changes in energy prices. The prices of crude oil and refined products have fluctuated substantially in recent years. These prices depend on many factors, including the overall demand for crude oil and refined products, which in turn depends, among other factors, general economic conditions, the level of foreign and domestic production of crude oil and refined products, the availability of imports of crude oil and refined products, the marketing of alternative and competing fuels, the extent of government regulations and global market dynamics. The prices we receive for refined products are also affected by factors such as local market conditions and the level of operations of other refineries in our markets. The prices at which we can sell gasoline and other refined products are strongly influenced by the price of crude oil. Generally, an increase or decrease in the price of crude oil results in a corresponding increase or decrease in the price of gasoline and other refined products. The timing of the relative movement of the prices, however, can impact profit margins, which could significantly affect our earnings and cash flows.

  
Item 4. Controls and Procedures 

Evaluation of Disclosure Controls and Procedures

Our management, under the direction of our Chief Executive Officer and Chief Financial Officer, evaluated as of March 31, 2011 the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon and as of the date of that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, to ensure that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required and is accumulated and communicated to our management, including our Chief Executive Officer and our Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that

   


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the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.

Changes in Internal Control Over Financial Reporting

There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended March 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

  
Item 1. Legal Proceedings 

See Note 11 (“Commitments and Contingencies”) to Part I, Item I of this Form 10-Q, which is incorporated by reference into this Part II, Item 1, for a description of the Samson, J. Aron, property tax and TransCanada litigation contained in “Litigation” and for a description of the Consent Decree contained in “Environmental, Health, and Safety (“EHS”) Matters.”

  
Item 1A. Risk Factors 

See “Risk Factors” attached hereto as Exhibit 99.1 for a discussion of risks our business may face.

  
Item 6. Exhibits 
     
Number  Exhibit Title 
 
 10 .1*  Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and John J. Lipinski. 
 10 .2*  Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Stanley A. Riemann. 
 10 .3*  Second Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edward Morgan. 
 10 .4*  Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edmund S. Gross. 
 10 .5*  Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Robert W. Haugen. 
 10 .6**  ABL Credit Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, the Holding Companies (as defined therein), the Subsidiary Guarantors (as defined therein), certain other Subsidiaries of the Holding Companies or Coffeyville Resources, LLC from time to time party thereto, the lenders from time to time party thereto, Deutsche Bank Trust Company Americas, JPMorgan Chase Bank, N.A. and Wells Fargo Capital Finance, LLC, as Co-ABL Collateral Agents, and  Deutsche Bank Trust Company Americas, as Administrative Agent and Collateral Agent (filed as Exhibit 1.1 to the Company’s Current Report on Form 8-K, filed on February 28, 2011 and incorporated herein by reference). 
 10 .7**  ABL Pledge and Security Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Pipeline, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, the Holdings Companies (as defined therein), certain other Subsidiaries of the Holding Companies party thereto from time to time, and Deutsche Bank Trust Company Americas, as Collateral Agent (filed as Exhibit 1.2 to the Company’s Current Report on Form 8-K, filed on February 28, 2011 and incorporated herein by reference). 
   


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Number  Exhibit Title 
 
 10 .8**  ABL Intercreditor Agreement, dated as of February 22, 2011, among Coffeyville Resources, LLC, Coffeyville Finance Inc., Deutsche Bank Trust Company Americas, as collateral agent for the secured parties, Wells Fargo Bank, National Association, as collateral trustee for the secured parties in respect of the outstanding first lien notes, and the outstanding second lien notes and certain subordinated liens, respectively, and the Guarantors (as defined therein) (filed as Exhibit 1.3 to the Company’s Current Report on Form 8-K, filed on February 28, 2011 and incorporated herein by reference). 
 10 .9*†  Crude Oil Supply Agreement dated as of March 30, 2011, by and between Vitol Inc. and Coffeyville Resources Refining & Marketing, LLC. 
 10 .10**  CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (filed as Exhibit 10.1 to the Partnership’s Registration Statement on Form S-8 filed on April 12, 2011 and incorporated herein by reference). 
 10 .11  Form of CVR Partners, LP Long-Term Incentive Plan Director Phantom Unit Agreement (filed as Exhibit 10.13.1 to the Partnership’s Form S-1/A, File No. 333-171270 and incorporated herein by reference). 
 10 .12  Form of CVR Partners, LP Long-Term Incentive Plan Director Stock Option Agreement (filed as Exhibit 10.13.2 to the Partnership’s Form S-1/A, File No. 333-171270 and incorporated herein by reference). 
 31 .1*  Certification of the Company’s Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. 
 31 .2*  Certification of the Company’s Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. 
 32 .1*  Certification of the Company’s Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
 32 .2*  Certification of the Company’s Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 
 99 .1*  Risk Factors. 
   
*   Filed herewith. 
 
**  Previously filed. 
 
†   Certain portions of this exhibit have been omitted and separately filed with the SEC pursuant to a request for confidential treatment that is pending at the SEC. 

PLEASE NOTE:  Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this quarterly report on Form 10-Q. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Company’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Company or its business or operations on the date hereof.

   

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CVR Energy, Inc.

   
 By:   /s/  John J. Lipinski 

Chief Executive Officer

(Principal Executive Officer)

May 10, 2011

   
 By:   /s/  Edward Morgan 

Chief Financial Officer

(Principal Financial Officer)

May 10, 2011

   


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