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

Form 10-Q

(Mark One)    

ý

 

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

For the quarterly period ended June 30, 2013

OR

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)

(281) 207-3200
(Registrant's telephone number, including area code)

        Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    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 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý    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.

Large accelerated filer o   Accelerated filer ý   Non-accelerated filer o
(Do not check if smaller reporting company.)
  Smaller reporting company o

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

        There were 86,831,050 shares of the registrant's common stock outstanding at July 30, 2013.

   


CVR ENERGY, INC. AND SUBSIDIARIES

INDEX TO QUARTERLY REPORT ON FORM 10-Q
For The Quarter Ended June 30, 2013

 
   
  Page No.  
 

Part I. Financial Information

 

 


Item 1.


 


Financial Statements


 

 


6

 

 



 


Condensed Consolidated Balance Sheets—June 30, 2013 (unaudited) and December 31, 2012


 

 


6

 

 



 


Condensed Consolidated Statements of Operations—Three and Six Months Ended June 30, 2013 and 2012 (unaudited)


 

 


7

 

 



 


Condensed Consolidated Statements of Comprehensive Income (Loss)—Three and Six Months Ended June 30, 2013 and 2012 (unaudited)


 

 


8

 

 



 


Condensed Consolidated Statement of Changes in Equity—Six Months Ended June 30, 2013 (unaudited)


 

 


9

 

 



 


Condensed Consolidated Statements of Cash Flows—Six Months Ended June 30, 2013 and 2012 (unaudited)


 

 


10

 

 



 


Notes to the Condensed Consolidated Financial Statements—June 30, 2013 (unaudited)


 

 


11

 

 


Item 2.


 


Management's Discussion and Analysis of Financial Condition and Results of Operations


 

 


47

 

 


Item 3.


 


Quantitative and Qualitative Disclosures About Market Risk


 

 


91

 

 


Item 4.


 


Controls and Procedures


 

 


92

 

 


Part II. Other Information


 

 


Item 1.


 


Legal Proceedings


 

 


93

 

 


Item 1A.


 


Risk Factors


 

 


93

 

 


Item 6.


 


Exhibits


 

 


94

 

 


Signatures


 

 


95

 

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GLOSSARY OF SELECTED TERMS

        The following are definitions of certain terms used in this Quarterly Report on Form 10-Q for the quarter ended June 30, 2013 (this "Report").

        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.

        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 calendar day, which refers to the total number of barrels processed in a refinery within a year, divided by 365 days, thus reflecting all operational and logistical limitations.

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

        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.

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

        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, during the refining process.

        Group 3—A geographic subset of the PADD II region comprising refineries in Oklahoma, Kansas, Missouri, Nebraska and Iowa. Current Group 3 refineries include the Refining Partnership's Coffeyville and Wynnewood refineries; the Valero Ardmore refinery in Ardmore, OK; HollyFrontier's Tulsa refinery in Tulsa, OK and El Dorado refinery in El Dorado, KS; Phillips 66's Ponca City refinery in Ponca City, OK; and NCRA's refinery in McPherson, KS.

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        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.

        MSCF—One thousand standard cubic feet, a customary gas measurement unit.

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

        Nitrogen Fertilizer Partnership IPO—The initial public offering of 22,080,000 common units representing limited partner interests of CVR Partners, LP (the "Nitrogen Fertilizer Partnership"), which closed on April 13, 2011.

        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.

        rack sales—Sales which are made at terminals into third-party tanker trucks.

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

        Refining Partnership IPO—The initial public offering of 27,600,000 common units representing limited partner interests of CVR Refining, LP (the "Refining Partnership"), which closed on January 23, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).

        Secondary Offering—The registered public offering of 12,000,000 common units representing limited partner interests of the Nitrogen Fertilizer Partnership, which closed on May 28, 2013.

        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.

        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.

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        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 refineries and every two years for the nitrogen fertilizer plant.

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

        Underwritten Offering—The underwritten offering of 13,209,236 common units of the Refining Partnership, which closed on May 20, 2013 (which includes the underwriters' subsequently-exercised option to purchase additional common units).

        WCS—Western Canadian Select crude oil, a medium to heavy, sour crude oil, characterized by an American Petroleum Institute gravity ("API gravity") of between 20 and 22 degrees and a sulfur content of approximately 3.3 weight percent.

        WEC—Gary-Williams Energy Corporation, subsequently converted to Gary-Williams Energy Company, LLC and now known as Wynnewood Energy Company, LLC.

        WRC—Wynnewood Refining Company, LLC, the owner of the 70,000 bpd Wynnewood, Oklahoma refinery and related assets.

        WTI—West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an 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

 
  June 30,
2013
  December 31,
2012
 
 
  (unaudited)
   
 
 
  (in millions, except
share data)

 

ASSETS

             

Current assets:

             

Cash and cash equivalents

  $ 1,134.5   $ 896.0  

Accounts receivable, net of allowance for doubtful accounts of $2.7 and $2.0,  respectively

    277.0     210.6  

Inventories

    588.8     528.1  

Prepaid expenses and other current assets

    132.3     54.4  

Insurance receivable

        1.3  

Income tax receivable

        4.1  

Deferred income taxes

    13.6     57.4  

Due from parent

        9.2  
           

Total current assets

    2,146.2     1,761.1  

Property, plant, and equipment, net of accumulated depreciation

    1,809.9     1,782.9  

Intangible assets, net

    0.3     0.3  

Goodwill

    41.0     41.0  

Deferred financing costs, net

    12.6     16.6  

Insurance receivable

    4.0     4.0  

Other long-term assets

    9.4     5.0  
           

Total assets

  $ 4,023.4   $ 3,610.9  
           

LIABILITIES AND EQUITY

             

Current liabilities:

             

Note payable and capital lease obligations

  $ 1.2   $ 1.1  

Accounts payable

    380.2     440.1  

Personnel accruals

    46.2     51.2  

Accrued taxes other than income taxes

    29.4     36.7  

Income taxes payable

    9.7      

Due to parent

    118.9      

Deferred revenue

    1.5     1.0  

Other current liabilities

    97.3     95.6  
           

Total current liabilities

    684.4     625.7  

Long-term liabilities:

             

Long-term debt and capital lease obligations, net of current portion

    675.6     897.1  

Accrued environmental liabilities, net of current portion

    1.4     1.6  

Deferred income taxes

    585.2     386.9  

Other long-term liabilities

    44.4     39.5  
           

Total long-term liabilities

    1,306.6     1,325.1  

Commitments and contingencies

             

Equity:

             

CVR stockholders' equity:

             

Common stock $0.01 par value per share, 350,000,000 shares authorized, 86,929,660 issued as of June 30, 2013 and December 31, 2012

    0.9     0.9  

Additional paid-in-capital

    1,114.8     582.3  

Retained earnings

    185.3     945.4  

Treasury stock, 98,610 as of June 30, 2013 and December 31, 2012, at cost

    (2.3 )   (2.3 )

Accumulated other comprehensive income (loss), net of tax

    0.3     (1.2 )
           

Total CVR stockholders' equity

    1,299.0     1,525.1  
           

Noncontrolling interest

    733.4     135.0  
           

Total equity

    2,032.4     1,660.1  
           

Total liabilities and equity

  $ 4,023.4   $ 3,610.9  
           

   

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
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (unaudited)
(in millions, except per share data)

 

Net sales

  $ 2,220.3   $ 2,308.3   $ 4,572.7   $ 4,276.9  

Operating costs and expenses:

                         

Cost of product sold (exclusive of depreciation and amortization)

    1,785.4     1,874.2     3,599.0     3,509.4  

Direct operating expenses (exclusive of depreciation and amortization)

    108.3     94.1     216.8     209.6  

Selling, general and administrative expenses (exclusive of depreciation and amortization)

    28.9     72.0     57.4     117.3  

Depreciation and amortization

    35.0     32.2     69.2     64.3  
                   

Total operating costs and expenses

    1,957.6     2,072.5     3,942.4     3,900.6  
                   

Operating income

    262.7     235.8     630.3     376.3  

Other income (expense):

                         

Interest expense and other financing costs (Note 13)

    (12.5 )   (19.0 )   (27.9 )   (38.2 )

Interest income

    0.3     0.2     0.6     0.2  

Gain (loss) on derivatives, net

    120.5     38.8     100.5     (108.5 )

Loss on extinguishment of debt

            (26.1 )    

Other income, net

    0.2     0.6     0.3     0.9  
                   

Total other income (expense)

    108.5     20.6     47.4     (145.6 )
                   

Income before income taxes

    371.2     256.4     677.7     230.7  

Income tax expense

    99.5     91.1     193.3     81.4  
                   

Net income

    271.7     165.3     484.4     149.3  

Less: Net income attributable to noncontrolling interest

    88.3     10.6     136.0     19.8  
                   

Net income attributable to CVR Energy stockholders

  $ 183.4   $ 154.7   $ 348.4   $ 129.5  
                   

Basic earnings per share

  $ 2.11   $ 1.78   $ 4.01   $ 1.49  

Diluted earnings per share

  $ 2.11   $ 1.75   $ 4.01   $ 1.46  

Weighted-average common shares outstanding:

                         

Basic

    86.8     86.8     86.8     86.8  

Diluted

    86.8     88.4     86.8     88.5  

   

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (unaudited)
(in millions)

 

Net income

  $ 271.7   $ 165.3   $ 484.4   $ 149.3  

Other comprehensive income (loss):

                         

Unrealized gain on available-for-sale securities, net of tax of $0.9, $0, $0.9 and $0

    1.4         1.4      

Change in fair value of interest rate swap, net of tax of $0.1, $(0.2), $0.1 and $(0.3)

    0.1     (0.5 )   0.1     (0.7 )

Net loss reclassified into income on settlement of interest rate swap, net of tax of $0.1, $0.1, $0.2 and $0.1 (Note 13)

    0.2     0.2     0.3     0.3  
                   

Total other comprehensive income (loss)

    1.7     (0.3 )   1.8     (0.4 )
                   

Comprehensive income

    273.4     165.0     486.2     148.9  

Less: Comprehensive income attributable to noncontrolling interest

    88.5     10.5     136.3     19.6  
                   

Comprehensive income attributable to CVR Energy stockholders

  $ 184.9   $ 154.5   $ 349.9   $ 129.3  
                   

   

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF CHANGES IN EQUITY

 
  Common Stockholders    
   
 
 
  Shares
Issued
  $0.01 Par
Value
Common
Stock
  Additional
Paid-In
Capital
  Retained
Earnings
  Treasury
Stock
  Accumulated
Other
Comprehensive
Income (Loss)
  Total CVR
Stockholders'
Equity
  Noncontrolling
Interest
  Total
Equity
 
 
  (unaudited)
(in millions, except share data)

 

Balance at December 31, 2012

    86,929,660   $ 0.9   $ 582.3   $ 945.4   $ (2.3 ) $ (1.2 ) $ 1,525.1   $ 135.0   $ 1,660.1  

January issuance of CVR Refining's common units to the public

            229.3                 229.3     276.4     505.7  

May issuance of CVR Refining's common units to the public

            148.9                 148.9     148.7     297.6  

Sale of CVR Refining's common units to AEPC

            23.6                 23.6     22.7     46.3  

Secondary offering of CVR Partners' common units to the public

            130.1                 130.1     74.1     204.2  

Dividends paid to CVR Energy stockholders

                (1,107.1 )           (1,107.1 )       (1,107.1 )

Distributions from CVR Partners to public unitholders

                                (17.8 )   (17.8 )

Distributions from CVR Refining to public unitholders

                                (43.6 )   (43.6 )

Share-based compensation

            0.7     (1.4 )           (0.7 )   1.7     1.0  

Redemption of common units

            (0.1 )               (0.1 )   (0.1 )   (0.2 )

Net income

                348.4             348.4     136.0     484.4  

Net unrealized gain on available-for-sale securities, net of tax

                        1.4     1.4         1.4  

Net gain on interest rate swaps, net of tax

                        0.1     0.1     0.3     0.4  
                                       

Balance at June 30, 2013

    86,929,660   $ 0.9   $ 1,114.8   $ 185.3   $ (2.3 ) $ 0.3   $ 1,299.0   $ 733.4   $ 2,032.4  
                                       

   

See accompanying notes to the condensed consolidated financial statements.

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CVR ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 
  Six Months Ended
June 30,
 
 
  2013   2012  
 
  (unaudited)
(in millions)

 

Cash flows from operating activities:

             

Net income

  $ 484.4   $ 149.3  

Adjustments to reconcile net income to net cash provided by operating activities:

             

Depreciation and amortization

    69.2     64.3  

Allowance for doubtful accounts

    0.6     0.1  

Amortization of deferred financing costs

    1.5     3.9  

Amortization of original issue discount

        0.3  

Amortization of original issue premium

        (1.7 )

Deferred income taxes

    (101.2 )   (12.5 )

Loss on disposition of assets

        0.9  

Loss on extinguishment of debt

    26.1      

Share-based compensation

    10.3     21.9  

Unrealized (gain) loss on derivatives, net

    (138.3 )   81.3  

Changes in assets and liabilities:

             

Accounts receivable

    (67.1 )   (31.2 )

Inventories

    (60.7 )   121.9  

Prepaid expenses and other current assets

    (11.7 )   (9.5 )

Insurance receivable

    1.3      

Other long-term assets

    (0.2 )   (1.6 )

Accounts payable

    (41.9 )   (27.6 )

Due to parent

    128.1     28.3  

Accrued income tax

    13.8     58.6  

Deferred revenue

    0.5     (4.6 )

Other current liabilities

    47.9     (6.1 )

Accrued environmental liabilities

    (0.2 )   (0.1 )
           

Net cash provided by operating activities

    362.4     435.9  
           

Cash flows from investing activities:

             

Capital expenditures

    (114.6 )   (105.2 )

Proceeds from sale of assets

    0.1     0.4  
           

Net cash used in investing activities

    (114.5 )   (104.8 )
           

Cash flows from financing activities:

             

Payment of capital lease obligations

    (0.6 )   (0.5 )

Payments on senior secured notes

    (243.4 )    

Payment of financing costs

    (0.2 )   (2.0 )

Proceeds from CVR Refining's initial public offering in January, net of offering costs

    655.7      

Proceeds from CVR Refining's offering in May, net of offering costs

    393.7      

Proceeds from the sale of CVR Refining's common units to AEPC

    61.5      

Proceeds from CVR Partners' secondary offering, net of offering costs

    292.6      

Exercise of stock options

        0.4  

Redemption of common units

    (0.2 )   (0.1 )

Dividends to CVR Energy's stockholders

    (1,107.1 )    

Distributions to CVR Refining's noncontrolling interest holders

    (43.6 )    

Distributions to CVR Partners' noncontrolling interest holders

    (17.8 )   (24.6 )
           

Net cash used in financing activities

    (9.4 )   (26.8 )
           

Net increase in cash and cash equivalents

    238.5     304.3  

Cash and cash equivalents, beginning of period

    896.0     388.3  
           

Cash and cash equivalents, end of period

  $ 1,134.5   $ 692.6  
           

Supplemental disclosures:

             

Cash paid for income taxes, net of refunds

  $ 152.6   $ 6.9  

Cash paid for interest net of capitalized interest of $1.2 and $4.3 in 2013 and 2012, respectively

  $ 33.2   $ 36.0  

Non-cash investing and financing activities:

             

Accrual of construction in progress additions

  $ (18.1 ) $ (12.2 )

   

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

June 30, 2013

(unaudited)

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

        The "Company" or "CVR" are used in this report to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries.

        CVR is a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through its holdings in CVR Refining, LP ("CVR Refining" or the "Refining Partnership") and CVR Partners, LP ("CVR Partners" or the "Nitrogen Fertilizer Partnership"). The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the form of ammonia and UAN. The Company reports in two business segments: the petroleum segment (the operations of CVR Refining) and the nitrogen fertilizer segment (the operations of CVR Partners).

        CVR's common stock is listed on the NYSE under the symbol "CVI." On May 7, 2012, IEP Energy LLC and certain of its affiliates (collectively, "IEP") announced that they had acquired control of CVR pursuant to a tender offer for all of the Company's common stock (the "IEP Acquisition"). As of June 30, 2013, IEP owned approximately 82% of all of the outstanding shares of CVR. Prior to the IEP Acquisition, the Company was owned 100% by the public. Pursuant to the Transaction Agreement (the "Transaction Agreement") as a result of the IEP Acquisition, the settlement terms of all employee restricted share awards were modified. See further discussion in Note 3 ("Share-Based Compensation").

        On April 13, 2011, the Nitrogen Fertilizer Partnership completed its initial public offering of 22,080,000 common units (the "Nitrogen Fertilizer Partnership IPO") priced at $16.00 per unit. The common units, which are listed on the NYSE, began trading on April 8, 2011 under the symbol "UAN". In connection with the Nitrogen Fertilizer Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market which represented an approximately 30% interest in the Nitrogen Fertilizer Partnership at the time of the Nitrogen Fertilizer Partnership IPO and through May 27, 2013.

        On May 28, 2013, Coffeyville Resources, LLC ("CRLLC") completed a registered public offering (the "Secondary Offering") whereby it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million in offering costs.

        Subsequent to the closing of the Secondary Offering and as of June 30, 2013, the Nitrogen Fertilizer Partnership had 73,074,945 common units outstanding, consisting of 34,154,945 common units owned by the public, representing approximately 47% of the total Nitrogen Fertilizer Partnership units, and 38,920,000 common units owned by CRLLC, representing approximately 53% of the total Nitrogen Fertilizer Partnership units. In addition, CRLLC owns 100% of the Nitrogen Fertilizer Partnership's

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

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

general partner, CVR GP, LLC, which only holds a non-economic general partner interest. The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Nitrogen Fertilizer Partnership.

        The Nitrogen Fertilizer Partnership has adopted a policy pursuant to which the Nitrogen Fertilizer Partnership will distribute all of the available cash it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partner following the end of such quarter. The partnership agreement does not require that the Nitrogen Fertilizer Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Nitrogen Fertilizer Partnership can change the Nitrogen Fertilizer Partnership's distribution policy at any time.

        The Nitrogen Fertilizer Partnership is operated by CVR's senior management (together with other officers of the general partner) pursuant to a services agreement among CVR, the general partner and the Nitrogen Fertilizer Partnership. The Nitrogen Fertilizer Partnership's general partner, CVR GP, LLC, manages the operations and activities of the Nitrogen Fertilizer 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 are made by CRLLC as the sole member of the general partner and not by the board of directors of the general partner. The members of the board of directors of the general partner are not elected by the common unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Nitrogen Fertilizer Partnership. CVR, the Nitrogen Fertilizer 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 Nitrogen Fertilizer Partnership IPO.

        In contemplation of an initial public offering, in September 2012, CRLLC formed CVR Refining Holdings, LLC ("CVR Refining Holdings"), which in turn formed CVR Refining GP, LLC. CVR Refining Holdings and CVR Refining GP, LLC formed the Refining Partnership, which issued them a 100% limited partnership interest and a non-economic general partner interest, respectively. CVR Refining Holdings formed CVR Refining, LLC ("Refining LLC") and CRLLC contributed its petroleum and logistics subsidiaries, as well as its equity interests in Coffeyville Finance Inc. ("Coffeyville Finance") to Refining LLC in October 2012. CVR Refining Holdings contributed Refining LLC to the Refining Partnership in December 2012.

        On January 23, 2013, the Refining Partnership completed the initial public offering of its common units representing limited partner interests (the "Refining Partnership IPO"). The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00 per unit. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00 per common unit in connection with the underwriters' exercise of their option to purchase additional common units. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR." In connection with the Refining Partnership IPO, the Company recorded a noncontrolling interest for the common units sold into the public market which

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

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

represented an approximate 19% interest in the Refining Partnership at the time of the Refining Partnership IPO. Prior to the Refining Partnership IPO, CVR owned 100% of the Refining Partnership and net income earned during this period was fully attributable to the Company.

        On May 20, 2013, the Refining Partnership completed an underwritten offering (the "Underwritten Offering") by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of Icahn Enterprises LP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with a partial exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions." In connection with the Transactions, the Refining Partnership paid approximately $12.2 million in underwriting fees and approximately $0.4 million in offering costs.

        The Refining Partnership utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy. The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC.

        Subsequent to the closing of the Transactions and as of June 30, 2013, the Refining Partnership had 147,600,000 common units outstanding, consisting of 42,809,236 common units owned by the public representing approximately 29% of the total Refining Partnership units (including 6,000,000 units owned by affiliates of Icahn Enterprises representing 4% of the total Refining Partnership units) and 104,790,764 common units owned by CVR Refining Holdings, representing approximately 71% of the total Refining Partnership units. In addition, CVR Refining Holdings, an indirect wholly-owned subsidiary of CVR Energy, owns 100% of the Refining Partnership's general partner, CVR Refining GP, LLC, which holds a non-economic general partner interest. The noncontrolling interest reflected on the Condensed Consolidated Balance Sheets of CVR is impacted by the net income of, and distributions from, the Refining Partnership.

        The Refining Partnership's general partner, CVR Refining GP, LLC, manages the Refining Partnership's activities subject to the terms and conditions specified in the Refining Partnership's partnership agreement. The Refining Partnership's general partner is owned by CVR Refining Holdings. The operations of its general partner, in its capacity as general partner are managed by its board of directors. Actions by its general partner that are made in its individual capacity are made by CVR Refining Holdings as the sole member of the Refining Partnership's general partner and not by the board of directors of its general partner. The members of the board of directors of the Refining Partnership's general partner are not elected by the Refining Partnership's unitholders and are not subject to re-election on a regular basis. The officers of the general partner manage the day-to-day affairs of the business of the Refining Partnership.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

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

        The Refining Partnership has adopted a policy pursuant to which it will distribute all of the available cash it generates each quarter. The available cash for each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter. The partnership agreement does not require that the Refining Partnership make cash distributions on a quarterly basis or at all, and the board of directors of the general partner of the Refining Partnership can change the distribution policy at any time.

        The Refining Partnership entered into a services agreement on December 31, 2012, pursuant to which the Refining Partnership and its general partner obtain certain management and other services from CVR Energy. In addition, by virtue of the fact that the Refining Partnership is a controlled affiliate of CVR Energy, the Refining Partnership is bound by an omnibus agreement entered into by CVR Energy, CVR Partners and the general partner of CVR Partners, pursuant to which the Refining Partnership may not engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of the Nitrogen Fertilizer Partnership's outstanding units.

        The accompanying 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 (the "SEC"). The condensed consolidated financial statements include the accounts of CVR and its majority-owned direct and indirect subsidiaries including the Nitrogen Fertilizer Partnership, the Refining Partnership and their respective subsidiaries. The ownership interests of noncontrolling investors in CVR's 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 condensed consolidated financial statements should be read in conjunction with the December 31, 2012 audited consolidated financial statements and notes thereto included in CVR's Annual Report on Form 10-K for the year ended December 31, 2012, which was filed with the SEC on March 14, 2013.

        The Nitrogen Fertilizer Partnership and the Refining Partnership are both consolidated based upon the fact that their general partners are owned by CVR and, therefore, CVR has the ability to control their activities. The general partners of the Nitrogen Fertilizer Partnership and the Refining Partnership manage their respective operations and activities subject to the terms and conditions specified in their respective partnership agreements. The operations of each general partner in its capacity as general partner are managed by its board of directors. The limited rights of the common unitholders of the Nitrogen Fertilizer Partnership and the Refining Partnership are demonstrated by the fact that the common unitholders have no right to elect either general partner or either general partner's directors on an annual or other continuing basis. Each 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 CVR) voting together as a single class. Actions by the general partner that are made in its individual capacity are made by the CVR subsidiary that serves as

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

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

the sole member of the general partner and not by the board of directors of the general partner. The officers of the general partner manage the day-to-day affairs of the business. The majority of the officers of both general partners are also officers of CVR. Based upon the general partner's role and rights as afforded by the partnership agreements and the limited rights afforded to the limited partners, the condensed consolidated financial statements of CVR will include the assets, liabilities, cash flows, revenues and expenses of the Nitrogen Fertilizer Partnership and the Refining Partnership.

        In the opinion of the Company's management, the accompanying 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 June 30, 2013 and December 31, 2012, the results of operations and comprehensive income for the three and six month periods ended June 30, 2013 and 2012, changes in equity for the six month period ended June 30, 2013 and cash flows of the Company for the six month periods ended June 30, 2013 and 2012.

        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, 2013 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.

(2) Recent Accounting Pronouncements

        In December 2011, the FASB issued ASU No. 2011-11, "Disclosures about Offsetting Assets and Liabilities" ("ASU 2011-11"). ASU 2011-11 retains the existing offsetting requirements and enhances the disclosure requirements to allow investors to better compare financial statements prepared under GAAP with those prepared under IFRS. On January 31, 2013, the FASB issued ASU No. 2013-01, "Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities" ("ASU 2013-01"). ASU 2013-01 limits the scope of the new balance sheet offsetting disclosures to derivatives, repurchase agreements and securities lending transactions. Both standards are effective for interim and annual periods beginning January 1, 2013 and are to be applied retrospectively. The Company adopted these standards as of January 1, 2013. The adoption of these standards expanded the Company's condensed consolidated financial statement footnote disclosures.

        In February 2013, the FASB issued ASU No. 2013-02, "Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income" ("ASU 2013-02"). ASU 2013-02 requires the Company to present information about reclassification adjustments from accumulated other comprehensive income in the financial statements in a single footnote or parenthetically on the face of the financial statements based on the source and the income statement line items affected by the reclassification. The standard is effective for interim and annual periods beginning January 1, 2013 and is to be applied prospectively. The Company adopted this standard as of January 1, 2013. The adoption of this standard did not materially expand the Company's condensed consolidated financial statement footnote disclosures.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(3) Share-Based Compensation

        CVR has a Long-Term Incentive Plan ("LTIP"), which permits the grant of options, stock appreciation rights, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). As of June 30, 2013, only grants of restricted stock units under the LTIP remain outstanding. Individuals who are eligible to receive awards and grants under the LTIP include the Company's employees, officers, consultants, advisors and directors. The LTIP authorizes a share pool of 7,500,000 shares of the Company's common stock, 1,000,000 of which may be issued in respect of incentive stock options. A summary of the principal features of the LTIP is provided below.

        A summary of restricted stock units grant activity and changes during the six months ended June 30, 2013 is presented below:

 
  Shares   Weighted-Average
Grant-Date
Fair Value
 

Non-vested at January 1, 2013

    1,145,611   $ 23.24  

Granted

    2,600     54.75  

Vested

    (3,198 )   27.51  

Forfeited

    (15,089 )   22.76  
           

Non-vested at June 30, 2013

    1,129,924   $ 23.31  
           

        Through the LTIP, restricted shares have been granted to employees of the Company. Prior to the change of control as discussed in Note 1, the restricted shares, when granted, were 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.

        The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one non-transferable contingent cash payment ("CCP") upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, additional share-based compensation of approximately $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the three and six months ended June 30, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards, the classification changed from equity-classified awards to liability-classified awards.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(3) Share-Based Compensation (Continued)

        In December 2012 and subsequent periods, restricted stock units were granted to certain employees of CVR. The non-vested restricted stock units are scheduled to vest over three years, with one-third of the award vesting each year on the anniversary of the grant date, with the exception of awards granted to certain executive officers that vest over one year. Each restricted stock unit represents the right to receive, upon vesting, a cash payment equal to (a) the fair market value of one share of the Company's common stock, plus (b) the cash value of all dividends declared and paid by the Company per share of the Company's common stock from the grant date to and including the vesting date. The awards, which are liability-classified, will be remeasured at each subsequent reporting date until they vest.

        Additionally, the Company approved a discretionary award of up to 62,920 restricted stock units to Mr. Lipinski, Chief Executive Officer and President of the Company, on or before December 31, 2013. This discretionary award remains subject to the review and recommendation of the Compensation Committee and approval of the board of directors of the Company, and is conditioned on Mr. Lipinski continuing to be employed by the Company through December 31, 2013. As such, no expense related to this discretionary award was recorded during the three and six months ended June 30, 2013. To the extent awarded, the discretionary award will vest immediately, and include dividend equivalent rights for the time period commencing on December 28, 2012 through the date of the award.

        As of June 30, 2013, there was approximately $13.4 million of total unrecognized compensation cost related to restricted stock units and associated dividends to be recognized over a weighted-average period of approximately 0.5 years. Total compensation expense for the three months ended June 30, 2013 and 2012 was approximately $3.7 million and $17.3 million, respectively, related to the LTIP. Total compensation expense for the six months ended June 30, 2013 and 2012 was approximately $9.1 million and $20.8 million, respectively, related to the LTIP. As of June 30, 2013 and December 31, 2012, the Company has a liability of $28.6 million and $19.5 million, respectively, for unvested restricted stock unit awards and associated dividends, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

        In April 2011, the board of directors of CVR Partners' 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 (1) employees of the Nitrogen Fertilizer Partnership and its subsidiaries, (2) employees of its general partner, and (3) members of the board of directors of its general partner. 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. The maximum number of common units issuable under the CVR Partners LTIP is 5,000,000.

        Through the CVR Partners LTIP, phantom and common units have been awarded to employees of the Nitrogen Fertilizer Partnership and its general partner and to members of the board of directors of its general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. Prior to the amendment, the phantom units, when granted, were valued at the closing market price of the Nitrogen

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(3) Share-Based Compensation (Continued)

Fertilizer Partnership's common units on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the units. These units generally vest over a three-year period.

        The amendment triggered a modification to the awards by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to the amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award.

        A summary of common units and phantom units (collectively "units") activity and changes under the CVR Partners LTIP during the six months ended June 30, 2013 is presented below:

 
  Units   Weighted-Average
Grant-Date
Fair Value
 

Non-vested at January 1, 2013

    201,812   $ 23.70  

Granted

         

Vested

    (16,886 )   19.74  

Forfeited

         
           

Non-vested at June 30, 2013

    184,926   $ 24.06  
           

        As of June 30, 2013, there was approximately $2.1 million of total unrecognized compensation cost related to the awards under the CVR Partners LTIP to be recognized over a weighted-average period of 1.2 years. Compensation expense recorded for the three months ended June 30, 2013 and 2012 related to the awards under the CVR Partners LTIP was approximately $0.6 million and $0.5 million, respectively. Compensation expense recorded for the six months ended June 30, 2013 and 2012 related to the awards under the CVR Partners LTIP was approximately $1.2 million and $1.1 million, respectively. As of June 30, 2013 and December 31, 2012, the Company has a liability of $0.4 million and $0.2 million, respectively, for unvested phantom unit awards, which is recorded in personnel accruals on the Condensed Consolidated Balance Sheets.

        In connection with the Refining Partnership IPO, on January 16, 2013, the board of directors of the general partner of the Refining Partnership adopted the CVR Refining, LP Long-Term Incentive Plan (the "CVR Refining LTIP"). Individuals who are eligible to receive awards under the CVR Refining LTIP include employees, officers, consultants and directors of CVR Refining and its general partner and their respective subsidiaries and parents. The CVR Refining LTIP provides for the grant of options, unit appreciation rights, restricted units, phantom units, unit awards, substitute awards, other-unit based awards, cash awards, performance awards, and distribution equivalent rights, each in respect of common units. The maximum number of common units issuable under the CVR Refining LTIP is 11,070,000. As of June 30, 2013, no awards have been granted under the plan.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(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.

        Inventories consisted of the following:

 
  June 30,
2013
  December 31,
2012
 
 
  (in millions)
 

Finished goods

  $ 317.4   $ 275.2  

Raw materials and precious metals

    170.3     164.3  

In-process inventories

    56.8     42.8  

Parts and supplies

    44.3     45.8  
           

  $ 588.8   $ 528.1  
           

(5) Property, Plant, and Equipment

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

 
  June 30,
2013
  December 31,
2012
 
 
  (in millions)
 

Land and improvements

  $ 33.3   $ 31.0  

Buildings

    41.3     40.6  

Machinery and equipment

    2,261.0     2,089.5  

Automotive equipment

    16.4     15.0  

Furniture and fixtures

    14.0     13.7  

Leasehold improvements

    2.5     2.5  

Railcars

    8.0     2.5  

Construction in progress

    103.3     189.2  
           

    2,479.8     2,384.0  

Accumulated depreciation

    669.9     601.1  
           

Total net, property, plant and equipment

  $ 1,809.9   $ 1,782.9  
           

        Capitalized interest recognized as a reduction in interest expense for the three months ended June 30, 2013 and 2012 totaled approximately $0.4 million and $2.3 million, respectively. Capitalized interest recognized as a reduction in interest expense for the six months ended June 30, 2013 and 2012 totaled approximately $1.2 million and $4.3 million, respectively. Land, buildings and equipment that are under a capital lease obligation had an original carrying value of approximately $25.1 million as of

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(5) Property, Plant, and Equipment (Continued)

June 30, 2013 and December 31, 2012. 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, renewable identification numbers ("RINs") expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $1.3 million and $0.9 million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, cost of product sold excludes depreciation and amortization of approximately $2.4 million and $1.6 million, respectively.

        Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs, as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately $33.2 million and $30.7 million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, direct operating expenses exclude depreciation and amortization of approximately $65.7 million and $61.5 million, respectively.

        Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate and administrative office in Texas and the administrative offices in Kansas and Oklahoma. Selling, general and administrative expenses exclude depreciation and amortization of approximately $0.5 million and $0.6 million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, selling, general and administrative expenses exclude depreciation and amortization of approximately $1.1 million and $1.2 million, respectively.

(7) Income Taxes

        On May 19, 2012, CVR became a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of Icahn Enterprises, and subsequently entered into a tax allocation agreement with AEPC (the "Tax Allocation Agreement"). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, that it would have paid if it were to file as a consolidated group separate and apart from AEPC. As of June 30, 2013, the Company has recorded a liability of $118.9 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended June 30, 2013 the Company paid $54.0 million and $85.0 million for the first and second quarter estimated federal income tax payments, respectively, due to AEPC under the Tax Allocation Agreement.

        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 June 30, 2013, the Company had unrecognized tax benefits of approximately $42.0 million, of which $17.0 million, if recognized, would impact the Company's effective tax rate. Unrecognized tax benefits that are not expected to be settled within the next twelve

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(7) Income Taxes (Continued)

months are included in other long-term liabilities in the Condensed Consolidated Balance Sheets; unrecognized tax benefits that are expected to be settled within the next twelve months are included in income taxes payable. The Company has accrued interest of $1.1 million 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 June 30, 2013, the Company's tax filings are generally open to examination in the United States for the tax years ended December 31, 2009 through December 31, 2012 and in various individual states for the tax years ended December 31, 2008 through December 31, 2012.

        The Company's effective tax rate for the three and six months ended June 30, 2013 was 26.8% and 28.5%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.2%. The Company's effective tax rate for the three and six months ended June 30, 2013 is lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interests of CVR Refining's and CVR Partners' earnings, as well as benefits for domestic production activities and state income tax credits. The Company's effective tax rate for the three and six months ended June 30, 2012 was 35.5% and 35.3%, respectively, as compared to the Company's combined federal and state expected statutory tax rate of 39.4%. The Company's effective tax rate for the three and six months ended June 30, 2012 was lower than the statutory rate primarily due to the reduction of income subject to tax associated with the noncontrolling ownership interest of CVR Partners' earnings, as well as benefits for domestic production activities.

        Prior to the Refining Partnership IPO, CVR's deferred taxes were recorded based upon each separate component of the book versus tax basis difference of CVR's assets and liabilities, including CVR Refining's assets and liabilities. Subsequent to the Refining Partnership IPO, deferred taxes related to the net book versus tax basis difference associated with the investment in CVR Refining are recorded as a noncurrent deferred tax liability.

(8) Long-Term Debt

        Long-term debt was as follows:

 
  June 30,
2013
  December 31,
2012
 
 
  (in millions)
 

10.875% Senior Secured Notes, due 2017, net of unamortized discount of $1.8 million as of December 31, 2012

  $   $ 220.9  

6.5% Senior Notes, due 2022

    500.0     500.0  

CRNF credit facility

    125.0     125.0  

Capital lease obligations

    50.6     51.2  
           

Long-term debt

  $ 675.6   $ 897.1  
           

        On April 6, 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance (together the "Issuers") completed a private offering of $275.0 million aggregate principal amount of 9.0% First Lien

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(8) Long-Term Debt (Continued)

Senior Secured Notes due 2015 (the "2010 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 "Old Notes"). The 2010 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 15, 2011, the Issuers sold an additional $200.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 ("Additional First Lien Notes" and together with the 2010 First Lien Notes, the "First Lien Notes"). The Additional First Lien Notes were sold at an issue price of 105.0%, plus accrued interest from October 1, 2011 of $3.7 million. The associated original issue premium of $10.0 million for the Additional First Lien Notes was amortized to interest expense and other financing costs over the term of the Additional First Lien Notes.

        The First Lien Notes were scheduled to mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. See further discussion below related to the tender for and subsequent redemption of all the outstanding First Lien Notes in the fourth quarter of 2012. The Second Lien Notes were scheduled to mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

        On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. Refining LLC received approximately $492.5 million of cash proceeds, net of the underwriting fees, but before deducting other third-party fees and expenses associated with the offering. The 2022 Notes were secured by substantially the same assets that secured the then outstanding Second Lien Notes, subject to exceptions, until such time that the outstanding Second Lien Notes were satisfied and discharged in full, which occurred on January 23, 2013. The 2022 Notes are fully and unconditionally guaranteed by CVR Refining and each of Refining LLC's existing domestic subsidiaries on a joint and several basis. CVR Refining has no independent assets or operations and Refining LLC is a 100% owned finance subsidiary of CVR Refining. Prior to the satisfaction and discharge of the Second Lien Notes, which occurred on January 23, 2013, the 2022 Notes were also guaranteed by CRLLC. CVR Energy, the Nitrogen Fertilizer Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC ("CRNF"), a wholly owned subsidiary of the Nitrogen Fertilizer Partnership, are not guarantors.

        A portion of the net proceeds from the offering of the 2022 Notes approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012 and to pay

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(8) Long-Term Debt (Continued)

related fees and expenses. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. CRLLC used the remaining proceeds from the offering to redeem the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

        Previously deferred financing charges and unamortized original issuance premium related to the First Lien Notes totaled approximately $8.1 million and $6.3 million, respectively. As a result of the repayment of the First Lien Notes, a loss on extinguishment of debt of $33.4 million was recorded in the fourth quarter of 2012, which included the total premiums paid of $31.6 million and write-off of previously deferred financing charges of $8.1 million, partially offset by the write-off of the unamortized original issuance premium of $6.3 million.

        The debt issuance costs of the 2022 Notes totaled approximately $8.7 million and are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method. On May 29, 2013, Refining LLC filed a registration statement on Form S-4 to satisfy its obligations contained in the registration right agreement entered into in connection with the issuance of the 2022 Notes. The Refining Partnership has incurred approximately $0.3 million of debt registration costs related to this registration, which are being amortized over the term of the 2022 Notes as interest expense using the effective-interest amortization method.

        The 2022 Notes mature on November 1, 2022, unless earlier redeemed or repurchased by the issuers. Interest is payable on the 2022 Notes semi-annually on May 1 and November 1 of each year, commencing on May 1, 2013.

        The 2022 Notes contain customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make certain payments on contractually subordinated debt, the ability to merge, consolidate with or into another entity and the ability to enter into certain affiliate transactions. The 2022 Notes provide that the Refining Partnership can make distributions to holders of its common units provided, among other things, it has a minimum fixed charge coverage ratio and there is no default or event of default under the 2022 Notes. As of June 30, 2013, the Refining Partnership was in compliance with the covenants contained in the 2022 Notes.

        At June 30, 2013, the estimated fair value of the 2022 Notes was approximately $490.0 million. These estimates of fair value are Level 2 as they were determined by quotations obtained from a broker-dealer who makes a market in these and similar securities.

        On December 20, 2012, CRLLC, the Refining Partnership, Refining LLC and each of the operating subsidiaries of Refining LLC (collectively, the "Credit Parties") entered into an amended and restated ABL credit agreement (the "Amended and Restated ABL Credit Facility") with a group of lenders and Wells Fargo Bank, National Association ("Wells Fargo"), as administrative agent and collateral agent. The Amended and Restated ABL Credit Facility, which replaced the prior ABL credit facility, is scheduled to mature on December 20, 2017. Under the amended and restated facility, the

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(8) Long-Term Debt (Continued)

Refining Partnership assumed the Company's position as borrower and the Company's obligations under the facility upon the closing of the Refining Partnership's IPO on January 23, 2013.

        The Amended and Restated ABL Credit Facility is a senior secured asset based revolving credit facility in an aggregate principal amount of up to $400.0 million with an incremental facility, which permits an increase in borrowings of up to $200.0 million subject to receipt of additional lender commitments and certain other conditions. The proceeds of the loans may be used for capital expenditures and working capital and general corporate purposes of the Credit Parties and their subsidiaries. The Amended and Restated ABL Credit Facility provides for loans and letters of credit in an amount up to the aggregate availability under the facility, subject to meeting certain borrowing base conditions, with sub-limits of 10% of the total facility commitment for swingline loans and 90% of the total facility commitment for letters of credit.

        Borrowings under the Amended and Restated ABL Credit Facility bear interest at either a base rate or LIBOR plus an applicable margin. The applicable margin is (i) (a) 1.75% for LIBOR borrowings and (b) 0.75% for prime rate borrowings, in each case if quarterly average excess availability exceeds 50% of the lesser of the borrowing base and the total commitments and (ii) (a) 2.00% for LIBOR borrowings and (b) 1.00% for prime rate borrowings, in each case if quarterly average excess availability is less than or equal to 50% of the lesser of the borrowing base and the total commitments. The Amended and Restated ABL Credit Facility also requires the payment of customary fees, including an unused line fee of (i) 0.40% if the daily average amount of loans and letters of credit outstanding is less than 50% of the lesser of the borrowing base and the total commitments and (ii) 0.30% if the daily average amount of loans and letters of credit outstanding is equal to or greater than 50% of the lesser of the borrowing base and the total commitments. The Refining Partnership will also be required to pay customary letter of credit fees equal to, for standby letters of credit, the applicable margin on LIBOR loans on the maximum amount available to be drawn under and, for commercial letters of credit, the applicable margin on LIBOR loans less 0.50% on the maximum amount available to be drawn under, and customary facing fees equal to 0.125% of the face amount of, each letter of credit.

        The Amended and Restated ABL Credit Facility also contains customary covenants for a financing of this type that limit the ability of the Credit Parties and their respective subsidiaries to, among other things, incur liens, engage in a consolidation, merger, purchase or sale of assets, pay dividends, incur indebtedness, make advances, investment and loans, enter into affiliate transactions, issue equity interests, or create subsidiaries and unrestricted subsidiaries. The amended and restated facility also contains a fixed charge coverage ratio financial covenant, as defined therein. The Credit Parties were in compliance with the covenants of the Amended and Restated ABL Credit Facility as of June 30, 2013.

        Lender and other third-party costs associated with the Amended and Restated ABL Credit Facility of $2.1 million were deferred and are being amortized to interest expense and other financing costs using a straight-line method over the term of the amended facility. In accordance with guidance provided by the FASB regarding the modification of revolving debt arrangements, a portion of the unamortized deferred financing costs associated with the prior ABL credit facility of approximately $2.8 million will continue to be amortized over the term of the Amended and Restated ABL Credit Facility.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(8) Long-Term Debt (Continued)

        As of June 30, 2013, the Refining Partnership and its subsidiaries had availability under the Amended and Restated ABL Credit Facility of $372.9 million and had letters of credit outstanding of approximately $27.1 million. There were no borrowings outstanding under the Amended and Restated ABL Credit Facility as of June 30, 2013.

        On April 13, 2011, CRNF, as borrower, and the Nitrogen Fertilizer Partnership, as guarantor, entered into a 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. No amounts were outstanding under the revolving credit facility at June 30, 2013. There is no scheduled amortization of the credit facility, which matures in April 2016. The carrying value of the Nitrogen Fertilizer Partnership's debt approximates fair value.

        Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for Eurodollar rate loans under the credit facility is the Eurodollar rate plus a margin of 3.50% or, for base rate loans, the prime rate plus 2.50%. 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 Nitrogen Fertilizer Partnership.

        The credit facility requires the Nitrogen Fertilizer Partnership to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, the creation of liens on assets, the ability to dispose of assets, the ability to make restricted payments, investments and acquisitions, or enter into sale-leaseback transactions and affiliate transactions. The credit facility provides that the Nitrogen Fertilizer Partnership can make distributions to holders of its common units provided, among other things, it is in compliance with the leverage ratio and interest coverage ratio on a pro forma basis after giving effect to any distribution and there is no default or event of default under the credit facility. As of June 30, 2013, CRNF was in compliance with the covenants contained in the credit facility and there were no borrowings outstanding under the credit facility.

        As a result of the acquisition of the Wynnewood refinery, the Refining Partnership acquired certain lease assets and assumed related capital lease obligations related to Magellan Pipeline Terminals, L.P. and Excel Pipeline LLC. The underlying assets and related depreciation were included in property, plant and equipment. The capital lease relates to a sales-lease back agreement with Sunoco Pipeline, L.P. for its membership interest in the Excel Pipeline. The lease has 196 months remaining through September 2029. The financing agreement relates to the Magellan Pipeline terminals, bulk terminal and loading facility. The lease has 195 months remaining and will expire in September 2029.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(9) Dividends

        On January 24, 2013, the board of directors of the Company adopted a quarterly cash dividend policy. Subject to declaration by its board of directors, CVR Energy's initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which the Company began paying in the second quarter of 2013. Additionally, the Company declared and paid two special cash dividends during the six months ended June 30, 2013.

        The following is a summary of the quarterly and special dividends paid to stockholders during the six months ended June 30, 2013:

 
  February 19,
2013
  May 17,
2013
  June 10,
2013
  Total Dividends
Paid in 2013
 
 
  ($ in millions, expect per share amounts)
 

Dividend type

    Special     Quarterly     Special        

Amount paid IEP

  $ 391.6   $ 53.4   $ 462.8   $ 907.8  

Amounts paid to public stockholders

    86.0     11.7     101.6     199.3  
                   

Total amount paid

  $ 477.6   $ 65.1   $ 564.4   $ 1,107.1  
                   

Per common share

  $   5.50   $ 0.75   $   6.50   $ 12.75  
                   

Shares outstanding

    86.8     86.8     86.8        
                     

(10) Earnings Per Share

        Basic and diluted earnings per share are computed by dividing net income attributable to CVR stockholders by the weighted-average number of shares of common stock outstanding. The components of the basic and diluted earnings per share calculation are as follows:

 
  For the Three Months
Ended June 30,
  For the Six Months
Ended June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions, except per share data)
 

Net income attributable to CVR Energy stockholders

  $ 183.4   $ 154.7   $ 348.4   $ 129.5  

Weighted-average number of shares of common stock outstanding

    86.8     86.8     86.8     86.8  

Effect of dilutive securities:

                         

Non-vested common stock

        1.6         1.7  

Stock options

                 
                   

Weighted-average number of shares of common stock outstanding assuming dilution

    86.8     88.4     86.8     88.5  
                   

Basic earnings per share

  $ 2.11   $ 1.78   $ 4.01   $ 1.49  

Diluted earnings per share

  $ 2.11   $ 1.75   $ 4.01   $ 1.46  

        All outstanding stock options totaling 22,900 were exercised in May 2012. There were no dilutive awards outstanding during the three and six months ended June 30, 2013 as all unvested awards under the LTIP were liability-classified awards. See Note 3 ("Share-Based Compensation").

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies

        The minimum required payments for CVR's lease agreements and unconditional purchase obligations are as follows:

 
  Operating
Leases
  Unconditional
Purchase
Obligations(1)
 
 
  (in millions)
 

Six months ending December 31, 2013

  $ 4.8   $ 99.2  

Year Ending December 31,

             

2014

    9.1     112.9  

2015

    7.7     101.2  

2016

    6.7     94.0  

2017

    4.0     92.8  

Thereafter

    8.0     951.4  
           

  $ 40.3   $ 1,451.5  
           

(1)
This amount includes approximately $979.8 million payable ratably over eighteen 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 twenty years on TransCanada's Keystone pipeline system. CRRM began receiving crude oil under the agreements in the first quarter of 2011.

        CVR leases various equipment, including rail cars, and real properties under long-term operating leases which expire at various dates. For the three months ended June 30, 2013 and 2012, lease expense totaled approximately $2.2 million and $1.4 million, respectively. For the six months ended June 30, 2013 and 2012, lease expense totaled approximately $4.5 million and $2.7 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR's option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. Additionally, in the normal course of business, the Company has long-term commitments to purchase oxygen, nitrogen, electricity, storage capacity and pipeline transportation services.

        On August 31, 2012, CRRM, and Vitol Inc. ("Vitol"), entered into an Amended and Restated Crude Oil Supply Agreement (the "Vitol Agreement"). The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended. Under the Vitol Agreement, Vitol supplies the petroleum business with crude oil and intermediation logistics, which helps to reduce the Refining Partnership's inventory position and mitigate crude oil pricing risk.

        The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to the expiration of the Initial Term or any Renewal Term.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

        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 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.

        In May 2010, separate groups of plaintiffs (the "Anstine and Arrow cases") filed two lawsuits against CRRM and other defendants in state court in Oklahoma and Kansas. Both lawsuits were removed to federal court and were then transferred to the Bankruptcy Court for the United States District Court for the District of Delaware. The Anstine and Arrow cases alleged the 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 did not pay such plaintiffs for all of the crude oil purchased by Sem. Both lawsuits sought the same remedy, the imposition of a trust, an accounting and the return of crude oil or the proceeds therefrom. In February 2013, CRRM agreed to a settlement in the Anstine and Arrow cases, which was finalized with the plaintiffs in June 2013, and CRRM has been dismissed with prejudice. The settlement did not have a material adverse effect on the condensed consolidated financial statements.

        On June 21, 2012, Goldman, Sachs & Co. ("GS") filed suit against CVR in state court in New York, alleging that CVR failed to pay GS approximately $18.5 million in fees allegedly due to GS by CVR pursuant to an engagement letter dated March 21, 2012, which according to the allegations set forth in the complaint, provided that GS was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock, made by IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of June 30, 2013.

        On August 10, 2012, Deutsche Bank ("DB") filed suit against CVR in state court in New York, alleging that CVR failed to pay DB approximately $18.5 million in fees allegedly due to DB by CVR pursuant to an engagement letter dated March 23, 2012, which according to the allegations set forth in the complaint, provided that DB was engaged by CVR to assist CVR and the CVR board of directors in connection with a tender offer for CVR's stock made by IEP and certain of its affiliates. CVR believes it has meritorious defenses and intends to vigorously defend against the suit. This amount has been fully accrued as of June 30, 2013.

        On December 17, 2012, Gary Community Investment Company, F/K/A The Gary-Williams Company and GWEC Holding Company, Inc. (referred to herein collectively as "Gary-Williams") filed a lawsuit in the Supreme Court of New York, New York County (Gary Community Investment Co. v. CVR Energy, Inc., No. 654401/12) against CVR and CRLLC (referred to collectively for purposes of this paragraph as "CVR"). The action arises out of claims relating to CVR's purchase of the

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

Wynnewood, Oklahoma refinery pursuant to the Purchase and Sale Agreement entered into by the parties on November 2, 2011 (the "Purchase Agreement"). Specifically, CVR provided notice to Gary-Williams that it sought indemnification for various breaches of the Purchase Agreement and subsequently made a claim notice for payment of the entire escrow property pursuant to the Escrow Agreement by and among Gary-Williams, CRLLC, and the escrow agent, dated as of December 15, 2011. Gary-Williams, in its lawsuit, alleges that CVR breached the Purchase Agreement and the Escrow Agreement, and is seeking a declaratory judgment that CVR's claims are without any legal basis, damages in an unspecified amount, and release of the full amount of the escrow property to Gary-Williams.

        CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended December 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2008 through 2012.

        On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012, which will lower CRNF's property taxes by about $10.5 million per year for tax years 2013 through 2016 based on current mill levy rates. In addition, the settlement provides that Montgomery County will support CRNF's application before COTA for a ten year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment.

        Crude oil was discharged from the Company's Coffeyville 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 May 2008, in connection with the discharge, the Company received notices of claims from sixteen private claimants under the Oil Pollution Act ("OPA") in an aggregate amount of approximately $4.4 million (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 and June 2010, companion cases to the Angleton Case were filed in the United States District Court for the District of Kansas in Wichita, seeking a total of approximately $3.2 million (plus punitive damages) for three additional plaintiffs as a result of the July 1, 2007 crude oil discharge. The Company has settled all of the claims with the plaintiffs from the Angleton Case and has settled all of the claims except for one of the plaintiffs from the companion cases. The settlements did not have a material adverse effect on the condensed consolidated financial statements. The Company believes that the resolution of the remaining claim will not have a material adverse effect on the condensed consolidated financial statements.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

        On October 25, 2010, the Company received a letter from the United States Coast Guard on behalf of the U.S. Environmental Protection Agency (the "EPA") seeking approximately $1.8 million in oversight cost reimbursement. The Company responded by asserting defenses to the Coast Guard's claim for oversight costs. On September 23, 2011, the United States Department of Justice ("DOJ"), acting on behalf of the EPA and the United States Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking recovery from CRRM related to alleged non-compliance with the Clean Air Act's Risk Management Program ("RMP"), the Clean Water Act ("CWA") and the OPA. CRRM has reached an agreement with the DOJ resolving its claims under the CWA and the OPA. The agreement is memorialized in a Consent Decree that was filed with and approved by the Court on February 12, 2013 and March 25, 2013, respectively (the "2013 Consent Decree"). On April 19, 2013, CRRM paid a civil penalty plus accrued interest in the amount of $0.6 million for the CWA violations and reimbursed the Coast Guard for oversight costs under OPA in the amount of $1.7 million. The 2013 Consent Decree also requires CRRM to make small capital upgrades to the Coffeyville refinery crude oil tank farm, develop flood procedures and provide employee training. The parties also reached an agreement to settle DOJ's RMP claims. The agreement was filed with and approved by the Court on May 21, 2013 and July 2, 2013, respectively, and provided for a civil penalty of $0.3 million. On July 29, 2013, CRRM paid the civil penalty related to the RMP settlement agreement.

        The Company is seeking insurance coverage for this release and for the ultimate costs for remediation and third-party 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 insurance 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 $25.0 million 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 related to these events.

        The petroleum and nitrogen fertilizer businesses 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, Coffeyville Resources Crude Transportation, LLC ("CRCT"), Wynnewood Refining Company, LLC ("WRC") and Coffeyville Resources Terminal, LLC ("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, WRC and CRT have exposure to potential EHS liabilities related to past and present EHS conditions at

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

these locations. Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), the Resource Conservation and Recovery Act ("RCRA"), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. Similarly, the OPA generally subjects owners and operators of facilities to strict, joint and several liability for all containment and clean-up costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States.

        CRRM and CRT have agreed to perform corrective actions at the Coffeyville, Kansas refinery and the now-closed Phillipsburg, Kansas terminal facility, pursuant to Administrative Orders on Consent issued under RCRA to address historical contamination by the prior owners (RCRA Docket No. VII-94-H-0020 and Docket No. VII-95-H-011, respectively). As of June 30, 2013 and December 31, 2012, environmental accruals of approximately $1.9 million and $2.3 million, respectively, were reflected in the Condensed Consolidated Balance Sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders, for which approximately $0.5 million and $0.7 million, 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 June 30, 2013 and December 31, 2012, respectively. The accruals include estimated closure and post-closure costs of approximately $0.8 million for two landfills at both June 30, 2013 and December 31, 2012. The estimated future payments for these required obligations are as follows:

 
  Amount  
 
  (in millions)
 

Six months ending December 31, 2013

  $ 0.4  

Year Ending December 31,

       

2014

    0.3  

2015

    0.2  

2016

    0.1  

2017

    0.1  

Thereafter

    1.1  
       

Undiscounted total

    2.2  

Less amounts representing interest at 2.24%

    0.3  
       

Accrued environmental liabilities at June 30, 2013

  $ 1.9  
       

        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.

        CRRM, CRNF, CRCT, WRC and CRT are subject to extensive and frequently changing federal, state and local, environmental and health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water, the

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. The ultimate impact of complying with evolving laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws, such as the federal Clean Air Act, have not yet been finalized, are under governmental or judicial review or are being revised. These laws and regulations could result in increased capital, operating and compliance costs.

        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 and WRC are considered to be small refiners under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. However, the change in control resulting from the IEP Acquisition in 2012 triggered the loss of small refiner status. Accordingly, the MSAT II projects have been accelerated by three months. Capital expenditures to comply with the rule are expected to be approximately $59.0 million for CRRM and $98.0 million for WRC.

        The petroleum business is subject to the Renewable Fuel Standard ("RFS") which requires refiners to blend "renewable fuels" in with their transportation fuels or purchase renewable energy credits, known as RINs, in lieu of blending. The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to 9.6%. Beginning in 2011, the Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending, and in 2013, the Wynnewood refinery was required to comply. From time to time, the petroleum business may purchase RINs on the open market or waiver credits for cellulosic biofuels from the EPA in order to comply with RFS. While the petroleum business cannot predict the future prices of RINs or waiver credits, the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year. The cost of RINs for the three and six month periods ended June 30, 2012 was approximately $6.0 million and $9.3 million, respectively, and the cost of RINs for the three and six month periods ended June 30, 2013 was approximately $65.5 million and $97.6 million, respectively. As of June 30, 2013 and December 31, 2012, the petroleum business' biofuel blending obligation was approximately $82.6 million and $1.1 million, respectively, which was recorded in other current liabilities on the Condensed Consolidated Balance Sheets. The petroleum business expects that the cost of RINs will continue to be substantially higher in 2013 as compared to 2012. The ultimate cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at the its refineries, all of which can vary significantly from quarter to quarter.

        In 2013, the EPA proposed "Tier 3" gasoline sulfur standards. Based on the proposed standards, CRRM anticipates it will incur less than $20.0 million of capital expenditures to install controls in order to meet the anticipated new standards. The project is expected to be completed during the Coffeyville refinery's next scheduled turnaround in 2016. It is not anticipated that the Wynnewood refinery will require additional controls or capital expenditures to meet the anticipated new standard.

        In March 2004, CRRM and CRT entered into a Consent Decree (the "2004 Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to resolve air

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

compliance concerns raised by the EPA and KDHE related to Farmland Industries Inc.'s prior ownership and operation of the Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. Under the 2004 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 2004 Consent Decree, CRRM and CRT assumed clean-up obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities.

        In March 2012, CRRM entered into a "Second Consent Decree" with the EPA, which replaces the 2004 Consent Decree, as amended (other than certain financial assurance provisions associated with corrective action at the refinery and terminal under RCRA). The Second Consent Decree gives CRRM more time to install the FCCU controls from the 2004 Consent Decree and expands the scope of the settlement so that it is now considered a "global settlement" under the EPA's "National Petroleum Refining Initiative." Under the National Petroleum Refining Initiative, the EPA identified industry-wide non-compliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries (representing more than 90% of the US refining capacity) entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. Under the Second Consent Decree, the Company was required to pay a civil penalty of approximately $0.7 million and complete the installation of FCCU controls required under the 2004 Consent Decree, add controls to certain heaters and boilers and enhance certain work practices relating to wastewater and fugitive emissions. The remaining costs of complying with the Second Consent Decree are expected to be approximately $40.0 million. CRRM also agreed to complete a voluntary environmental project that will reduce air emissions and conserve water at an estimated cost of approximately $1.2 million. Additional incremental capital expenditures associated with the Second Consent Decree will not be material and will be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The Second Consent Decree was entered by the U.S. District Court for the District of Kansas on April 19, 2012.

        WRC's refinery has not entered into a global settlement with the EPA and the Oklahoma Department of Environmental Quality (the "ODEQ") under the National Petroleum Refining Initiative, although it had discussions with the EPA and the ODEQ about doing so. Instead, WRC entered into a Consent Order with the ODEQ in August 2011 (the "Wynnewood Consent Order"). The Wynnewood Consent Order addresses some, but not all, of the traditional marquee issues under the National Petroleum Refining Initiative and addresses certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC paid a civil penalty of $950,000, and agreed to install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. A substantial portion of the costs of complying with the Wynnewood Consent Order were expended during the last turnaround. The remaining costs are expected to be approximately $3.0 million. In consideration for entering into the Wynnewood Consent Order, WRC received a release from liability from ODEQ for matters described in the ODEQ order.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

        From time to time, the EPA has conducted inspections and issued information requests to CRNF with respect to the Company's compliance with the RMP and the release reporting requirements under CERCLA and the EPCRA. These previous investigations have resulted in the issuance of preliminary findings regarding CRNF's compliance status. In the fourth quarter of 2010, following CRNF's reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances), the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against the Company and the Company has not accrued for any liability associated with the investigations or releases.

        WRC has entered into a series of Clean Water Act consent orders with ODEQ. The latest Consent Order (the "CWA Consent Order"), which supersedes other consent orders, became effective in September 2011. The CWA Consent Order addresses alleged noncompliance by WRC with its Oklahoma Pollutant Discharge Elimination System permit limits. The CWA Consent Order requires WRC to take corrective action steps, including undertaking studies to determine whether the Wynnewood refinery's wastewater treatment plant capacity is sufficient. The Wynnewood refinery may need to install additional controls or make operational changes to satisfy the requirements of the CWA Consent Order. The cost of additional controls, if any, cannot be predicted at this time. However, based on our experience with wastewater treatment and controls, the Company does not anticipate that the costs of any required additional controls or operational changes would be material.

        Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the three months ended June 30, 2013 and 2012, capital expenditures were approximately $15.8 million and $8.1 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations. For the six months ended June 30, 2013 and 2012, capital expenditures were approximately $38.0 million and $11.0 million, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

        CRRM, CRNF, CRCT, WRC 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.

        On September 28, 2012, the Wynnewood refinery experienced an explosion in a boiler unit during startup after a short outage as part of the turnaround process. Two employees were fatally injured. Damage at the refinery was limited to the boiler. Additionally, there was no environmental impact. The refinery was in the final stages of shutdown for turnaround maintenance at the time of the incident. The petroleum business completed an internal investigation of the incident and continues to cooperate with OSHA and Oklahoma Department of Labor investigations. OSHA also conducted a general inspection of the facility during the boiler incident investigation. In March 2013, OSHA completed its investigation and communicated its citations to WRC. OSHA also placed WRC in its Severe Violators Enforcement Program ("SVEP"). WRC has filed its notice of contest against the citations, and will

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

vigorously defend against the citations and OSHA's placement of WRC in the SVEP. WRC is in the process of reviewing the citations and no settlement has been reached. Any penalties associated with OSHA's citations are not expected to have a material adverse effect on the condensed consolidated financial statements.

        Mr. Icahn, through certain affiliates, owns approximately 82% of the Company's capital stock. Applicable pension and tax laws make each member of a "controlled group" of entities, generally defined as entities in which there is at least an 80% common ownership interest, jointly and severally liable for certain pension plan obligations of any member of the controlled group. These pension obligations include ongoing contributions to fund the plan, as well as liability for any unfunded liabilities that may exist at the time the plan is terminated. In addition, the failure to pay these pension obligations when due may result in the creation of liens in favor of the pension plan or the Pension Benefit Guaranty Corporation ("PBGC") against the assets of each member of the controlled group.

        As a result of the more than 80% ownership interest in CVR Energy by Mr. Icahn's affiliates, the Company is subject to the pension liabilities of all entities in which Mr. Icahn has a direct or indirect ownership interest of at least 80%. One such entity, ACF Industries LLC, is the sponsor of several pension plans. All the minimum funding requirements of the Code and the Employee Retirement Income Security Act of 1974, as amended by the Pension Protection Act of 2006, for these plans have been met as of June 30, 2013. If the ACF plans were voluntarily terminated, they would be underfunded by approximately $125.4 million as of June 30, 2013. Subsequent to June 30, 2013, as a result of Mr. Icahn's affiliates obtaining approximately 80.7% of the outstanding common stock of Federal-Mogul Corporation, ("Federal-Mogul") the Company is also subject to the pension liabilities of Federal-Mogul. If the plans of Federal-Mogul and ACF were voluntarily terminated, as of June 30, 2013, they would collectively be underfunded by approximately $764.4 million. These results are based on the most recent information provided by Mr. Icahn's affiliates based on information from the plans' actuaries. These liabilities could increase or decrease, depending on a number of factors, including future changes in benefits, investment returns, and the assumptions used to calculate the liability. As members of the controlled group, CVR Energy would be liable for any failure of ACF, and subsequent to June 30, 2013, Federal-Mogul to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of their respective pension plans. In addition, other entities now or in the future within the controlled group that includes CVR Energy may have pension plan obligations that are, or may become, underfunded, and the Company would be liable for any failure of such entities to make ongoing pension contributions or to pay the unfunded liabilities upon a termination of such plans. The current underfunded status of the ACF and Federal-Mogul pension plans requires such entities to notify the PBGC of certain "reportable events," such as if CVR Energy were to cease to be a member of the controlled group, or if CVR Energy makes certain extraordinary dividends or stock redemptions. The obligation to report could cause the Company to seek to delay or reconsider the occurrence of such reportable events. Based on the contingent nature of potential exposure related to these affiliate pension obligations, no liability has been recorded in the condensed consolidated financial statements.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(11) Commitments and Contingencies (Continued)

        Starfire Holding Corporation ("Starfire") which is 99.4% owned by Mr. Icahn, has undertaken to indemnify CVR Energy from losses resulting from any imposition of certain pension funding or termination liabilities that may be imposed the Company or its assets as a result of being a member of the Icahn controlled group. However, Starfire is not required to maintain a net worth equal to the amounts by which ACF and Federal-Mogul are underfunded, and there can be no guarantee Starfire will be able to fund its indemnification obligations to the Company.

(12) 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, liabilities or a group of assets or liabilities, such as a business.

        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:

        The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of June 30, 2013 and December 31, 2012:

 
  June 30, 2013  
 
  Level 1   Level 2   Level 3   Total  
 
  (in millions)
 

Location and Description

                         

Cash equivalents

  $ 124.0   $   $   $ 124.0  

Other current assets (marketable securities)

    20.9             20.9  

Other current assets (other derivative agreements)

        66.6         66.6  

Other long-term assets (other derivative agreements)

        5.0         5.0  
                   

Total Assets

  $ 144.9   $ 71.6   $   $ 216.5  
                   

Other current liabilities (other derivative agreements)

        (0.1 )       (0.1 )

Other current liabilities (interest rate swap)

        (0.9 )       (0.9 )

Other current liabilities (biofuel blending obligation)

        (43.1 )       (43.1 )

Other long-term liabilities (other derivative agreements)

                 

Other long-term liabilities (interest rate swap)

        (1.2 )       (1.2 )
                   

Total Liabilities

  $   $ (45.3 ) $   $ (45.3 )
                   

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June 30, 2013

(unaudited)

(12) Fair Value Measurements (Continued)


 
  December 31, 2012  
 
  Level 1   Level 2   Level 3   Total  
 
  (in millions)
 

Location and Description

                         

Cash equivalents

  $ 134.0   $   $   $ 134.0  

Other current assets (other derivative agreements)

                 

Other long-term assets (other derivative agreements)

        0.9         0.9  
                   

Total Assets

  $ 134.0   $ 0.9   $   $ 134.9  
                   

Other current liabilities (other derivative agreements)

        (67.7 )       (67.7 )

Other current liabilities (interest rate swap)

        (0.9 )       (0.9 )

Other current liabilities (biofuel blending obligation)

        (1.1 )       (1.1 )

Other long-term liabilities (other derivative agreements)

                 

Other long-term liabilities (interest rate swap)

        (1.9 )       (1.9 )
                   

Total Liabilities

  $   $ (71.6 ) $   $ (71.6 )
                   

        As of June 30, 2013 and December 31, 2012, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Company's cash equivalents, available-for-sale marketable securities, derivative instruments and the uncommitted biofuel blending obligation. Additionally, the fair value of the Company's debt issuances is disclosed in Note 8 ("Long-Term Debt"). The Refining Partnership's commodity derivative contracts and the uncommitted biofuel blending obligation which use fair value measurements are valued using broker quoted market prices of similar instruments which are considered Level 2 inputs. The Nitrogen Fertilizer Partnership has an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs. The fair value of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs. 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. As of June 30, 2013, the aggregate cost basis for the Company's available-for-sale securities is approximately $18.6 million. The Company had no transfers of assets or liabilities between any of the above levels during the six months ended June 30, 2013.

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(13) Derivative Financial Instruments

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

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Realized gain (loss) on settlement of derivative agreements, net

  $ 14.7   $ (8.1 ) $ (37.8 ) $ (27.2 )

Change in unrealized gain (loss) on derivative agreements, net

    105.8     46.9     138.3     (81.3 )
                   

Total gain (loss) on derivatives, net

  $ 120.5   $ 38.8   $ 100.5   $ (108.5 )
                   

        The Refining Partnership and Nitrogen Fertilizer Partnership are subject to price fluctuations caused by supply 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 Refining Partnership from time to time enters into various commodity derivative transactions.

        The Refining Partnership has adopted accounting standards which impose extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. The Refining Partnership 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.

        The Refining Partnership 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. Dependent 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, the Refining Partnership may be required to deposit additional funds into this margin account. The fair value of the open commodity positions as of June 30, 2013 was a net loss of $0.1 million included in other current liabilities. For the three months ended June 30, 2013 and 2012, the Refining Partnership recognized a net loss of $0.2 million and a net gain of $4.1 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized net losses of $2.4 million and $3.9 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

        The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. The physical volumes are not exchanged and these contracts are net

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NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(13) Derivative Financial Instruments (Continued)

settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. Quoted prices for similar assets or liabilities in active markets (Level 2) are considered to determine the fair values for the purpose of marking to market the hedging instruments at each period end. At June 30, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 20.0 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of its future gasoline and distillate production. The fair value of the outstanding contracts at June 30, 2013 was a net unrealized gain of $71.6 million, of which $66.6 million is included in current assets and $5.0 million is included in non-current assets. For the three months ended June 30, 2013 and 2012, the Refining Partnership recognized net gains of $120.7 million and $34.7 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized a net gain of $102.9 million and a net loss of $104.6 million, respectively, which are recorded in gain (loss) on derivatives, net in the Condensed Consolidated Statements of Operations.

        On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of the nitrogen fertilizer business' $125.0 million floating rate term debt which matures in April 2016. See Note 8 ("Long-Term Debt"). The aggregate notional amount covered under these agreements, which commenced on August 12, 2011 and expires on February 12, 2016, totals $62.5 million (split evenly between the two agreement dates). Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF will receive a floating rate based on three month LIBOR and pay a fixed rate of 1.975%. Both swap agreements are settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as calculated under the CRNF credit agreement. At June 30, 2013, the effective rate was approximately 4.58%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) ("AOCI"), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense on the Condensed Consolidated Statements of Operations.

        The realized loss on the interest rate swap re-classed from AOCI into interest expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.3 million and $0.2 million for the three months ended June 30, 2013 and 2012, respectively. For the three months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized an increase in the fair value of the interest rate swap agreements of $0.2 million and a decrease in the fair value of the interest rate swap agreements of $0.7 million, respectively, which was unrealized in accumulated other comprehensive income. The realized loss on the interest rate swap re-classed from AOCI into interest

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(13) Derivative Financial Instruments (Continued)

expense and other financing costs on the Condensed Consolidated Statements of Operations was $0.5 million for each of the six months ended June 30, 2013 and 2012. For the six months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Partnership recognized an increase in fair value of the interest rate swap agreements of $0.2 million and a decrease in fair value of the interest rate swap agreements of $1.0 million, respectively, which was unrealized in accumulated other comprehensive income.

        The Refining Partnership's exchange-traded crude oil futures and certain over-the-counter forward swap agreements are potentially exposed to concentrations of credit risk as a result of economic conditions and periods of uncertainty and illiquidity in the credit and capital markets. The Refining Partnership manages credit risk on its exchange-traded crude oil futures by completing trades with an exchange clearinghouse, which subjects the trades to mandatory margin requirements until the contract settles. The Refining Partnership also monitors the creditworthiness of its commodity swap counterparties and assesses the risk of nonperformance on a quarterly basis. Counterparty credit risk identified as a result of this assessment is recognized as a valuation adjustment to the fair value of the commodity swaps recorded in the Condensed Consolidated Balance Sheets. As of June 30, 2013, the counterparty credit risk adjustment was not material to the condensed consolidated financial statements. Additionally, the Refining Partnership does not require any collateral to support commodity swaps into which it enters; however, it does have master netting arrangements that allow for the setoff of amounts receivable from and payable to the same party, which mitigates the risk associated with nonperformance.

        The commodity swaps and other commodity derivatives agreements discussed above include multiple derivative positions with a number of counterparties for which the Refining Partnership has entered into agreements governing the nature of the derivative transactions. Each of the counterparty agreements provides for the right to setoff each individual derivative position to arrive at the net receivable due from the counterparty or payable owed by the Refining Partnership. As a result of the right to setoff, the Refining Partnership's recognized assets and liabilities associated with the outstanding derivative positions have been presented net in the Condensed Consolidated Balance Sheets. The interest rate swap agreements held by the Nitrogen Fertilizer Partnership also provide for the right to setoff. However, as the interest rate swaps are in a liability position, there are no amounts offset in the Condensed Consolidated Balance Sheets as of June 30, 2013 and December 31, 2012. In accordance with guidance issued by the FASB related to "Disclosures about Offsetting Assets and Liabilities," the tables below outline the gross amounts of the recognized assets and liabilities and the gross amounts offset in the Condensed Consolidated Balance Sheets for the various types of open derivative positions at the Refining Partnership.

        The offsetting assets and liabilities for the Refining Partnership's derivatives as of June 30, 2013 are recorded as current assets and non-current assets in prepaid expenses and other current assets and

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(13) Derivative Financial Instruments (Continued)

other long-term assets, respectively in the Condensed Consolidated Balance Sheets and as current liabilities in other current liabilities in the Condensed Consolidated Balance Sheets as follows:

 
  As of June 30, 2013  
Description
  Gross
Current
Assets
  Gross
Amounts
Offset
  Net
Current
Assets
Presented
  Cash
Collateral
Not Offset
  Net
Amount
 
 
  (in millions)
 

Commodity Swaps

  $ 68.3   $ (1.7 ) $ 66.6   $   $ 66.6  
                       

Total

  $ 68.3   $ (1.7 ) $ 66.6   $   $ 66.6  
                       

 

 
  As of June 30, 2013  
Description
  Gross
Non-
Current
Assets
  Gross
Amounts
Offset
  Net
Non-
Current
Assets
Presented
  Cash
Collateral
Not Offset
  Net
Amount
 
 
  (in millions)
 

Commodity Swaps

  $ 5.0   $   $ 5.0   $   $ 5.0  
                       

Total

  $ 5.0   $   $ 5.0   $   $ 5.0  
                       

 

 
  As of June 30, 2013  
Description
  Gross
Current
Liabilities
  Gross
Amounts
Offset
  Net
Current
Liabilities
Presented
  Cash
Collateral
Not Offset
  Net
Amount
 
 
  (in millions)
 

Other Derivative Activity

  $ 0.1   $   $ 0.1   $ (0.1 ) $  
                       

Total

  $ 0.1   $   $ 0.1   $ (0.1 ) $  
                       

        The offsetting assets and liabilities for the Refining Partnership's derivatives as of December 31, 2012 are recorded as non-current assets in other long-term assets in the Condensed Consolidated Balance Sheets and as current liabilities in other current liabilities in the Condensed Consolidated Balance Sheets as follows:

 
  As of December 31, 2012  
Description
  Gross
Non-
Current
Assets
  Gross
Amounts
Offset
  Net
Non-
Current
Assets
Presented
  Cash
Collateral
Not Offset
  Net
Amount
 
 
  (in millions)
 

Commodity Swaps

  $ 0.9   $   $ 0.9   $   $ 0.9  
                       

Total

  $ 0.9   $   $ 0.9   $   $ 0.9  
                       

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(13) Derivative Financial Instruments (Continued)

 
  As of December 31, 2012  
Description
  Gross
Current
Liabilities
  Gross
Amounts
Offset
  Net
Current
Liabilities
Presented
  Cash
Collateral
Not Offset
  Net
Amount
 
 
  (in millions)
 

Commodity Swaps

  $ 74.2   $ (6.5 ) $ 67.7   $   $ 67.7  
                       

Total

  $ 74.2   $ (6.5 ) $ 67.7   $   $ 67.7  
                       

(14) Related Party Transactions

        In May 2012, IEP announced that it had acquired control of CVR pursuant to a tender offer to purchase all of the issued and outstanding shares of the Company's common stock. As of June 30, 2013, IEP owned approximately 82% of all common shares outstanding.

        Since March 2009, the Company, through the Nitrogen Fertilizer Partnership, has leased 199 railcars from American Railcar Leasing LLC ("ARL"), a company controlled by Mr. Carl Icahn, the Company's majority stockholder. The agreement was scheduled to expire on March 31, 2014. For the three months ended June 30, 2013 and 2012, $0.1 million and $0.3 million, respectively, of rent expense was recorded related to this agreement and is included in cost of product sold (exclusive of depreciation and amortization) in the Condensed Consolidated Statements of Operations. For the six months ended June 30, 2013 and 2012, rent expense of $0.4 million and $0.5 million, respectively, was recorded related to this agreement. The Nitrogen Fertilizer Partnership negotiated an agreement with ARL to purchase the railcars under the lease for approximately $5.0 million. On June 13, 2013, the Nitrogen Fertilizer Partnership completed the purchase of the railcars.

        On May 19, 2012, CVR became a member of the consolidated federal tax group of AEPC, a wholly-owned subsidiary of Icahn Enterprises, and subsequently entered into a tax allocation agreement with AEPC (the "Tax Allocation Agreement"). The Tax Allocation Agreement provides that AEPC will pay all consolidated federal income taxes on behalf of the consolidated tax group. CVR is required to make payments to AEPC in an amount equal to the tax liability, if any, that it would have paid if it were to file as a consolidated group separate and apart from AEPC.

        As of June 30, 2013, the Company has recorded approximately $118.9 million for federal income taxes due to AEPC under the Tax Allocation Agreement. During the three months ended June 30, 2013 the Company paid $54.0 million and $85.0 million for the first and second quarter estimated federal income tax payments, respectively, due to AEPC under the Tax Allocation Agreement.

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(14) Related Party Transactions (Continued)

        Insight Portfolio Group LLC ("Insight Portfolio Group") is an entity formed by Mr. Icahn in order to maximize the potential buying power of a group of entities with which Mr. Icahn has a relationship in negotiating with a wide range of suppliers of goods, services and tangible and intangible property at negotiated rates. In January 2013 CVR Energy acquired a minority equity interest in Insight Portfolio Group and agreed to pay a portion of Insight Portfolio Group's operating expenses in 2013. The Company paid Insight Portfolio Group approximately $0.1 million during each of the three and six months ended June 30, 2013, respectively. The Company may purchase a variety of goods and services as members of the buying group at prices and terms that management believes would be more favorable than those which would be achieved on a stand-alone basis.

(15) 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.

        Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products, including pet coke. The Petroleum Segment's Coffeyville refinery sells pet coke to the Nitrogen Fertilizer Partnership for use in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For the Petroleum Segment, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the pet coke supply agreement that became effective October 24, 2007, is based on the lesser of a pet coke price derived from the price received by the Nitrogen Fertilizer Segment for UAN (subject to a UAN based price ceiling and floor) and a pet coke price index for pet coke. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were approximately $2.6 million and $2.4 million for the three months ended June 30, 2013 and 2012, respectively. Intercompany sales included in petroleum net sales were approximately $5.3 million and $4.8 million for the six months ended June 30, 2013 and 2012, respectively.

        The Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the net hydrogen purchases (sales) described below under "Nitrogen Fertilizer" of approximately and $4.0 million and $(0.1) million for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012, the Petroleum Segment recorded intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen purchases (sales) of approximately $4.0 million and $5.6 million, respectively. The Petroleum Segment recorded intercompany revenue for hydrogen sales of approximately $0.1 million and $0 for the three months ended June 30, 2013 and 2012, respectively. For the six months ended June 30, 2013 and 2012,

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(15) Business Segments (Continued)

the Petroleum Segment recorded intercompany revenue of approximately $0.3 million and $0, respectively.

        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 approximately $2.5 million and $2.3 million for the three months ended June 30, 2013 and 2012 respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the pet coke transfer described above was approximately $5.1 million and $5.2 million for the six months ended June 30, 2013 and 2012, respectively.

        Pursuant to the feedstock agreement, the Company's segments have the right to transfer excess hydrogen between the Coffeyville refinery and nitrogen fertilizer plant. 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. For the three months ended June 30, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $4.0 million and $0, respectively. For the six months ended June 30, 2013 and 2012, the net sales generated from intercompany hydrogen sales were $4.0 million and $5.7 million, respectively. For each of the three months ended June 30, 2013 and 2012, the nitrogen fertilizer segment also recognized approximately $0.1 million of cost of product sold related to the transfer of excess hydrogen. For the six months ended June 30, 2013 and 2012, the Nitrogen Fertilizer Segment also recognized approximately $0.3 million and $0.1 million, respectively, of cost of product sold related to the transfer of excess hydrogen. As these intercompany sales and cost of product sold are eliminated, there is no financial statement impact on the condensed consolidated financial statements.

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

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(15) Business Segments (Continued)

        The following table summarizes certain operating results and capital expenditures information by segment:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Net sales

                         

Petroleum

  $ 2,138.1   $ 2,229.5   $ 4,412.1   $ 4,128.0  

Nitrogen Fertilizer

    88.8     81.4     170.2     159.7  

Intersegment elimination

    (6.6 )   (2.6 )   (9.6 )   (10.8 )
                   

Total

  $ 2,220.3   $ 2,308.3   $ 4,572.7   $ 4,276.9  
                   

Cost of product sold (exclusive of depreciation and amortization)

                         

Petroleum

  $ 1,776.6   $ 1,866.1   $ 3,582.3   $ 3,496.8  

Nitrogen Fertilizer

    15.6     10.7     26.2     23.3  

Intersegment elimination

    (6.8 )   (2.6 )   (9.5 )   (10.7 )
                   

Total

  $ 1,785.4   $ 1,874.2   $ 3,599.0   $ 3,509.4  
                   

Direct operating expenses (exclusive of depreciation and amortization)

                         

Petroleum

  $ 83.8   $ 71.6   $ 169.9   $ 164.3  

Nitrogen Fertilizer

    24.4     22.4     47.0     45.3  

Other

    0.1     0.1     (0.1 )    
                   

Total

  $ 108.3   $ 94.1   $ 216.8   $ 209.6  
                   

Depreciation and amortization

                         

Petroleum

  $ 28.4   $ 26.6   $ 56.4   $ 52.9  

Nitrogen Fertilizer

    6.2     5.2     12.0     10.6  

Other

    0.4     0.4     0.8     0.8  
                   

Total

  $ 35.0   $ 32.2   $ 69.2   $ 64.3  
                   

Operating income

                         

Petroleum

  $ 229.1   $ 248.9   $ 564.7   $ 383.8  

Nitrogen Fertilizer

    37.1     36.1     73.9     67.5  

Other

    (3.5 )   (49.2 )   (8.3 )   (75.0 )
                   

Total

  $ 262.7   $ 235.8   $ 630.3   $ 376.3  
                   

Capital expenditures

                         

Petroleum

  $ 35.5   $ 27.0   $ 80.1   $ 62.4  

Nitrogen fertilizer

    13.8     16.9     31.9     39.2  

Other

    1.6     1.7     2.6     3.6  
                   

Total

  $ 50.9   $ 45.6   $ 114.6   $ 105.2  
                   

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CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (Continued)

June 30, 2013

(unaudited)

(15) Business Segments (Continued)


 
  As of June 30,
2013
  As of December 31,
2012
 
 
  (in millions)
 

Total assets

             

Petroleum

  $ 2,800.2   $ 2,258.5  

Nitrogen Fertilizer

    619.2     623.0  

Other

    604.0     729.4  
           

Total

  $ 4,023.4   $ 3,610.9  
           

Goodwill

             

Petroleum

  $   $  

Nitrogen Fertilizer

    41.0     41.0  

Other

         
           

Total

  $ 41.0   $ 41.0  
           

(16) Subsequent Events

        On July 31, 2013, the board of directors of the Company declared a cash dividend for the second quarter of 2013 to the Company's stockholders of $0.75 per share, or $65.1 million in aggregate. The dividend will be paid on August 19, 2013 to stockholders of record at the close of business on August 12, 2013. IEP will receive $53.4 million in respect of its 82% ownership interest in the Company's shares.

        On July 26, 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the second quarter of 2013 to the Nitrogen Fertilizer Partnership's unitholders of $0.583 per common unit, or $42.6 million in aggregate. The cash distribution will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013. The Company will receive $22.7 million in respect of its Nitrogen Fertilizer Partnership common units.

        On July 26, 2013, the board of directors of the Refining Partnership's general partner declared a cash distribution for the second quarter of 2013 to the Refining Partnership's unitholders of $1.35 per common unit, or $199.3 million in aggregate. The cash distribution will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013. The Company will receive $141.5 million in respect of its Refining Partnership common units.

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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 unaudited condensed consolidated financial statements and related notes and with the statistical information and financial data appearing in this Report, as well as our Annual Report on Form 10-K for the year ended December 31, 2012 filed with the Securities and Exchange Commission ("SEC") on March 14, 2013. Results of operations for the three and six months ended June 30, 2013 are not necessarily indicative of results to be attained for any other period.


Forward-Looking Statements

        This Report, including this Management's Discussion and Analysis of Financial Condition and Results of Operations, contains "forward-looking statements" as defined by the SEC. Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

        Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report, 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:

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        All forward-looking statements contained in this Report 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 Report, or to reflect the occurrence of unanticipated events, except as may be required by law.


Company Overview

        We are a diversified holding company primarily engaged in the petroleum refining and nitrogen fertilizer manufacturing industries through our holdings in the Refining Partnership and the Nitrogen Fertilizer Partnership. The Refining Partnership is an independent petroleum refiner and marketer of high value transportation fuels. The Nitrogen Fertilizer Partnership produces nitrogen fertilizers in the

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form of ammonia and UAN. We own the general partner and a majority of the common units representing limited partner interests in each of the Refining Partnership and the Nitrogen Fertilizer Partnership.

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

        Petroleum business.    The petroleum business consists of our interest in the Refining Partnership. At June 30, 2013, we owned the general partner and approximately 71% of the common units of the Refining Partnership. The petroleum business consists of a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and a 70,000 bpd medium complexity crude oil unit refinery in Wynnewood, Oklahoma capable of processing 20,000 bpd of light sour crude oil (within its 70,000 bpd capacity). In addition, its supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 50,000 bpd serving Kansas, Nebraska, Oklahoma, Missouri and Texas, (2) a rack marketing business supplying refined petroleum product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and Wynnewood, Oklahoma and at throughput terminals on Magellan and NuStar's refined petroleum products distribution systems, (3) a 145,000 bpd pipeline system (supported by approximately 350 miles of Company owned and leased pipeline) that transports crude oil to the Coffeyville refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels, (4) crude oil storage tanks with a capacity of 0.5 million barrels in Wynnewood, Oklahoma, (5) 1.0 million barrels of company owned crude oil storage capacity in Cushing, Oklahoma, (6) an additional 3.3 million barrels of leased crude oil storage capacity located in Cushing and (7) approximately 4.5 million barrels of combined refinery related storage capacity.

        The Coffeyville refinery is situated approximately 100 miles northeast of Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States and the Wynnewood refinery is approximately 130 miles southwest of Cushing. Cushing is supplied by numerous pipelines from U.S. domestic locations and Canada. The early June 2012 reversal of the Seaway pipeline that now flows from Cushing, Oklahoma to the U.S. Gulf Coast has eliminated the ability to source foreign waterborne crude oil, as well as deep water U.S. Gulf of Mexico produced sweet and sour crude oil grades. In addition to rack sales (sales which are made at terminals into third-party tanker trucks), Coffeyville makes bulk sales (sales through third-party pipelines) into the mid-continent markets and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise, and NuStar.

        Crude oil is supplied to the Coffeyville refinery through the gathering system and by a pipeline owned by Plains that runs from Cushing to its Broome Station tank farm. The petroleum business maintains capacity on the Spearhead and Keystone pipelines from Canada to Cushing. It also maintains leased and owned storage in Cushing to facilitate optimal crude oil purchasing and blending. The Coffeyville refinery blend consists of a combination of crude oil grades, including domestic grades and various Canadian medium and heavy sours and sweet synthetics. Crude oil is supplied to the Wynnewood refinery through two third-party pipelines operated by Sunoco Pipeline and Excel Pipeline and historically has mainly been sourced from Texas and Oklahoma. The Wynnewood refinery is capable of processing a variety of crudes, including WTS, WTI, sweet and sour Canadian and other U.S. domestically produced crude oils. The petroleum business expects to spend approximately $60.0 million on a hydrocracker project that will increase the conversion capability and the ULSD yield of the Wynnewood refinery. The access to a variety of crude oils coupled with the complexity of the refineries allows the petroleum business to purchase crude oil at a discount to WTI. The consumed crude oil cost discount to WTI for the second quarter of 2013 was $(2.90) per barrel compared to $(2.06) per barrel in the second quarter of 2012.

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        Nitrogen fertilizer business.    The nitrogen fertilizer business consists of our interest in the Nitrogen Fertilizer Partnership. At June 30, 2013, we owned the general partner and approximately 53% of the common units of the Nitrogen Fertilizer Partnership. 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 3,000 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day of hydrogen. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. For the three and six months ended June 30, 2013, the nitrogen fertilizer business produced 91,318 and 202,670 tons of ammonia, respectively, of which approximately 100% and 86% was upgraded into 225,166 and 421,323 tons of UAN, respectively.

        The Nitrogen Fertilizer Partnership will continue to expand the nitrogen fertilizer business' existing asset base to execute its growth strategy. The Nitrogen Fertilizer Partnership's growth strategy includes expanding production of UAN and acquiring additional infrastructure and production assets. The Nitrogen Fertilizer Partnership recently completed a significant two-year plant expansion designed to increase its UAN production capacity by 400,000 tons, or approximately 50%, per year. The UAN expansion was completed in February 2013 and was at full rates prior to the end of the first quarter. The Nitrogen Fertilizer Partnership now upgrades substantially all of the ammonia it produces into higher margin UAN fertilizer.

        The primary raw material feedstock utilized in the 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 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. The nitrogen fertilizer business currently purchases most of its pet coke from the Refining Partnership pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During 2012, the Nitrogen Fertilizer Partnership entered into a pet coke supply agreement with HollyFrontier Corporation. The initial term ends in December 2013 and is subject to renewal. On average, during the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by the Refining Partnership's crude oil refinery in Coffeyville.


Transaction Agreement

        On April 18, 2012, CVR Energy entered into a Transaction Agreement (the "Transaction Agreement") with IEP Energy LLC and certain of its affiliates (collectively "IEP"). Pursuant to the Transaction Agreement, IEP offered (the "Offer") to purchase all of the issued and outstanding shares of CVR Energy's common stock for a price of $30.00 per share in cash, without interest, less any applicable withholding taxes, plus one non-transferable contingent cash payment ("CCP") right for each share, which represents the contractual right to receive an additional cash payment per share if a definitive agreement for the sale of CVR Energy is executed on or before August 18, 2013 and such transaction closes.

        In May 2012, IEP acquired a majority of the common stock of CVR Energy through the Offer. As of June 30, 2013, IEP owned approximately 82% of CVR Energy's outstanding common stock.


Refining Partnership Initial Public Offering

        On January 23, 2013, the Refining Partnership completed the Refining Partnership IPO. The Refining Partnership sold 24,000,000 common units to the public at a price of $25.00 per common unit, resulting in gross proceeds of $600.0 million. Additionally, on January 30, 2013, the Refining Partnership sold an additional 3,600,000 common units to the public at a price of $25.00 per common

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unit in connection with the exercise of the underwriters' option to purchase additional common units, resulting in gross proceeds of $90.0 million. The common units, which are listed on the NYSE, began trading on January 17, 2013 under the symbol "CVRR."

        Prior to the Refining Partnership IPO, CVR owned 100% of the Refining Partnership and net income earned during this period was fully attributable to the Company. Following the Refining Partnership IPO and through May 19, 2013, CVR Energy indirectly owned approximately 81% of the Refining Partnership's outstanding common units and 100% of the Refining Partnership's general partner, which holds a non-economic general partner interest.


Refining Partnership Underwritten Offering

        On May 20, 2013, the Refining Partnership completed the Underwritten Offering by selling 12,000,000 common units to the public at a price of $30.75 per unit. American Entertainment Properties Corporation ("AEPC"), an affiliate of Icahn Enterprises LP, also purchased an additional 2,000,000 common units at the public offering price in a privately negotiated transaction with a subsidiary of CVR Energy, which was completed on May 29, 2013. In connection with the Underwritten Offering, on June 10, 2013, the Refining Partnership sold an additional 1,209,236 common units to the public at a price of $30.75 per unit in connection with the exercise by the underwriters of their option to purchase additional common units. The transactions described in this paragraph are collectively referred to as the "Transactions."

        Following the closing of the Transactions and as of June 30, 2013, public security holders held 42,809,236 units representing approximately 29% of all outstanding Refining Partnership common units (including 6,000,000 units held by affiliates of Icahn Enterprises, representing approximately 4% of all outstanding Refining Partnership common units) and CVR Refining Holdings held 104,790,764 units representing approximately 71% of all outstanding Refining Partnership common units in addition to owning 100% of CVR Refining GP, LLC, the general partner.

        The Refining Partnership utilized proceeds of approximately $394.0 million from the Underwritten Offering (including the underwriters' option) to redeem 13,209,236 common units from CVR Refining Holdings. The net proceeds to a subsidiary of CVR Energy from the sale of 2,000,000 common units to AEPC were approximately $61.5 million. The Refining Partnership did not receive any of the proceeds from the sale of common units by CVR Energy to AEPC. In connection with the Underwritten Offering, the Refining Partnership incurred approximately $0.4 million of offering expenses.


Nitrogen Fertilizer Partnership Secondary Offering

        On May 28, 2013, Coffeyville Resources, LLC ("CRLLC"), a wholly-owned subsidiary of CVR Energy, completed the Secondary Offering in which it sold 12,000,000 Nitrogen Fertilizer Partnership common units to the public at a price of $25.15 per unit. Additionally, the underwriters were granted an option to purchase 1,800,000 common units at the public offering price, which expired unexercised at the end of the option period. The net proceeds to CRLLC from the Secondary Offering were approximately $292.6 million, after deducting approximately $9.2 million in underwriting discounts and commissions. The Nitrogen Fertilizer Partnership did not receive any of the proceeds from the sale of common units by CRLLC. In connection with the Secondary Offering, the Nitrogen Fertilizer Partnership incurred approximately $0.5 million of offering expenses.

        Following the closing of the Secondary Offering and as of June 30, 2013, public security holders held 34,154,945 units representing approximately 47% of all outstanding Nitrogen Fertilizer Partnership common units and CRLLC held 38,920,000 units representing approximately 53% of all outstanding Nitrogen Fertilizer Partnership common units in addition to owning 100% of CVR GP, LLC, the general partner.

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Major Influences on Results of Operations

        The earnings and cash flows of the petroleum business are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks that are processed and blended into refined products. The cost to acquire crude oil and other feedstocks and the price for which refined products are ultimately sold depend on factors beyond its 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 the petroleum business applies first-in, first-out ("FIFO") accounting to value its inventory, crude oil price movements may impact net income in the short term because of changes in the value of its 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.

        The prices of crude oil and other feedstocks 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. Widespread expansion or upgrades of competitors' facilities, price volatility, international political and economic developments and other factors 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 fuels standards, proposed climate change laws and regulations, and increased mileage standards for vehicles. The petroleum business is also subject to the EPA's Renewable Fuel Standard ("RFS"), which requires it to blend "renewable fuels" in with its transportation fuels or purchase renewable energy credits, known as renewable identification numbers ("RINs"), in lieu of blending.

        The EPA is required to determine and publish the applicable annual renewable fuel percentage standards for each compliance year by November 30 for the forthcoming year. The percentage standards represent the ratio of renewable fuel volume to gasoline and diesel volume. The EPA has not yet finalized the 2013 renewable fuel percentage standard, but has proposed to raise it to approximately 9.6%. In 2013, the Wynnewood refinery became subject to the RFS for the first time, and the cost of RINs became extremely volatile and significantly higher than the cost during the comparable 2012 period. The cost of RINs for the year ended December 31, 2012 was approximately $21.0 million. The cost of RINs for the three and six months ended June 30, 2012 was approximately $6.0 million and $9.3 million, respectively, and the cost of RINs for the three and six months ended June 30, 2013 was approximately $65.5 million and $97.6 million, respectively. The petroleum business expects that the cost of RINs will continue to be substantially higher in 2013 as compared to 2012. The ultimate cost of RINs for the petroleum business in 2013 is difficult to estimate. In particular, the cost of RINs is dependent upon a variety of factors, which include the price at which RINs can be purchased, transportation fuel production levels, the mix of the petroleum business' petroleum products, as well as the fuel blending performed at its refineries, all of which can vary significantly from quarter to quarter. Based upon recent market prices of RINs and current estimates related to the other variable factors, the petroleum business estimates that the total cost of RINs will be approximately $200.0 million to $240.0 million for the year ending December 31, 2013.

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        When the 2013 volume mandate is finalized by the EPA, if sufficient RINs are unavailable for purchase at times when the petroleum business seeks to purchase RINs, or if the petroleum business has to pay a significantly higher price for RINs or if the petroleum business is subject to penalties as a result of delays in its ability to timely deliver RINs to the EPA, its business, financial condition and results of operations could be materially adversely affected. Many petroleum refiners blend renewable fuel into their transportation fuels and do not have to pass on the costs of compliance through the purchase of RINs to their customers. Therefore, it may be significantly harder for the petroleum business to pass on the costs of compliance with RFS to its customers.

        Because the cost of purchasing RINs has been extremely volatile and has significantly increased over the last year, the Wynnewood refinery will be petitioning the EPA as a "small refinery" for hardship relief from the RFS2 requirements in 2013 and 2014.

        In order to assess the operating performance of the petroleum business, we compare net sales, less cost of product sold (exclusive of depreciation and amortization), or the refining margin, against an industry refining margin benchmark. The industry refining margin benchmark 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.

        Although the 2-1-1 crack spread is a benchmark for the refinery margin, because the refineries have certain feedstock costs and logistical advantages as compared to a benchmark refinery and their product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. The Coffeyville 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. The Wynnewood refinery has the capability to process blends of a variety of crude oil ranging from medium sour to light sweet crude oil, although isobutene, gasoline components, and normal butane are also typically used. We measure the cost advantage of the crude oil slate by calculating the spread between the price of the delivered crude oil and the price of WTI. The spread is referred to as the consumed crude oil differential. The refinery margin can be impacted significantly by the consumed crude oil differential. The consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the WCS differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between the consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil the petroleum business purchases 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.

        The petroleum business produces a high volume of high value products, such as gasoline and distillates. The petroleum business benefits from the fact that its marketing region consumes more refined products than it produces, resulting in prices that reflect the logistics cost for U.S. Gulf Coast refineries to ship into its 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 its refineries is that prices the petroleum business realizes are different than those used in determining the 2-1-1 crack spread. The difference between its 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 its marketing area exceed those used in the 2-1-1 crack spread.

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        The direct operating expense structure is also important to the petroleum business' profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. The predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. The petroleum business is therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the six months ended June 30, 2013, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $4.4 million.

        Because crude oil and other feedstocks and refined products are commodities, the petroleum business has no control over the changing market. Therefore, the lower target inventory it is able to maintain significantly reduces the impact of commodity price volatility on its petroleum product inventory position relative to other refiners. This target inventory position is generally not hedged. To the extent its inventory position deviates from the target level, the petroleum business considers risk mitigation activities usually through the purchase or sale of futures contracts on the NYMEX. Its hedging activities carry customary time, location and product grade basis risks generally associated with hedging activities. Because most of its titled inventory is valued under the FIFO costing method, price fluctuations on our target level of titled inventory have a major effect on its financial results.

        Safe and reliable operations at the refineries are key to the petroleum business' financial performance and results of operations. Unplanned downtime at the refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The petroleum business seeks 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 refineries generally require a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The Coffeyville refinery completed the first phase of a two phase turnaround during the fourth quarter of 2011. The second phase was completed during the first quarter of 2012 and the first phase of its next turnaround is scheduled to begin in late 2015, with the second phase scheduled to begin in early 2016. The Wynnewood Refinery completed a turnaround in December 2012. Its next turnaround is scheduled to begin in late 2016.

        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, the adjacent Coffeyville 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.

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        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 last ten years, natural gas prices have significantly decreased. This decrease has significantly lowered 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 nitrogen 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 2012, approximately 54% of the corn planted in the United States was grown within a $45 per 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 are derived from the lower margin industrial market. 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 currently incur significant intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $15 per UAN ton for transportation of UAN 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.

        The value of nitrogen fertilizer products is also an important consideration in understanding our results. For the three and six months ended June 30, 2013, the nitrogen fertilizer business upgraded approximately 100% and 86%, respectively, of its ammonia production into UAN, a product that presently generates a greater value than ammonia. As a result of the completion of the UAN expansion project, the nitrogen fertilizer business now upgrades substantially all of its ammonia into UAN. UAN production is a major contributor to the nitrogen fertilizer business' profitability.

        The nitrogen fertilizer business' largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. In the three and six months ended June 30, 2013, the nitrogen fertilizer business spent approximately $3.4 million and $7.4 million, respectively, for pet coke, which equaled an average cost per ton of $29 and $30, respectively. In the three and six months ended June 30, 2012, the nitrogen fertilizer business spent approximately $4.1 million and $9.1 million, respectively, for pet coke, which equaled an average cost per ton of $31 and $36, respectively.

        The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from the adjacent Coffeyville crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder through a third-party contact with HollyFrontier Corporation. 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.

        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

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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 $3.0 million to $5.0 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2012, at a cost of approximately $4.8 million. The next turnaround is currently scheduled for the fourth quarter of 2014.

        In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Nitrogen Fertilizer Partnership in October 2007, we entered into a number of agreements with the Nitrogen Fertilizer Partnership that govern the business relations among the nitrogen fertilizer business on the one hand and the refining business on the other hand. In connection with the Nitrogen Fertilizer Partnership IPO, certain of the intercompany agreements were amended and restated, and the nitrogen fertilizer business and the refining business entered into several new agreements. In connection with the Refining Partnership IPO, some of our subsidiaries party to these agreements became subsidiaries of the Refining Partnership.

        These intercompany agreements include (i) the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; (ii) a services agreement, pursuant to which our management operates the nitrogen fertilizer business; (iii) a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; (iv) a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; (v) an easement agreement; (vi) an environmental agreement; and (vii) a lease agreement pursuant to which the petroleum business leases office space and laboratory space to the Nitrogen Fertilizer Partnership. These agreements were not the result of arm's-length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.

        In connection with the Refining Partnership IPO, we entered into a number of agreements with the Refining Partnership, including (i) a $150.0 million intercompany credit facility between CRLLC and the Refining Partnership and (ii) a services agreement, pursuant to which our management operates the petroleum business.

        On August 31, 2012, CRRM and Vitol entered into the Vitol Agreement. The Vitol Agreement amends and restates the Crude Oil Supply Agreement between CRRM and Vitol dated March 30, 2011, as amended. Under the agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us to reduce our inventory position and mitigate crude oil pricing risk. The Vitol Agreement has an initial term commencing on August 31, 2012 and extending through December 31, 2014 (the "Initial Term"). Following the Initial Term, the Vitol Agreement will automatically renew for successive one-year terms (each such term, a "Renewal Term") unless either party provides the other with notice of nonrenewal at least 180 days prior to the expiration of the Initial Term or any Renewal Term.

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Factors Affecting Comparability

        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.

        In February 2012, IEP commenced a tender offer to acquire all of the outstanding shares of common stock of our Company. On April 18, 2012, we entered into a transaction agreement and on May 7, 2012, IEP announced that control of the Company had been acquired. CVR incurred related costs of approximately $29.4 million and $44.2 million for the three and six months ended June 30, 2012 that did not occur in 2013. We are currently challenging a majority of the expenses charged and, if we are successful, such expenses would be reversed and have a favorable impact to our results of operations.

        Notes.    In April 2010, CRLLC and its then wholly-owned subsidiary, Coffeyville Finance, Inc. ("Coffeyville Finance"), issued $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 "Old Notes").

        In December 2010, CRLLC voluntarily redeemed $27.5 million of the First Lien Notes. On December 15, 2011, CRLLC and Coffeyville Finance issued an additional $200.0 million of the First Lien Notes to partially fund the acquisition of the Wynnewood refinery. In connection with the acquisition of the Wynnewood refinery, in November 2011, we received a commitment for a one year bridge loan, which remained undrawn and was terminated as a result of the issuance of the $200.0 million of First Lien Notes.

        On October 23, 2012, Refining LLC and Coffeyville Finance completed a private offering of $500.0 million aggregate principal amount of 6.5% Second Lien Senior Secured Notes due 2022 (the "2022 Notes"). The 2022 Notes were issued at par. A portion of the net proceeds from the offering approximating $348.1 million were used to purchase approximately $323.0 million of the First Lien Notes pursuant to a tender offer and to settle accrued interest of approximately $1.8 million through October 23, 2012. Tendered notes were purchased at a premium of approximately $23.2 million in aggregate amount. A portion of the remaining net proceeds from the 2022 Notes offering were used to fund the redemption of the remaining $124.1 million of outstanding First Lien Notes and to settle accrued interest of approximately $1.6 million through November 23, 2012. Redeemed notes were purchased at a premium of approximately $8.4 million in aggregate amount.

        On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The amounts were used to (i) repay the face amount of all $222.8 million aggregate principal amount of Second Lien Notes then outstanding, (ii) pay the redemption premium of approximately $20.6 million and (iii) settle accrued interest with respect thereto in an amount of approximately $9.5 million. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

        Through the Company's Long-Term Incentive Plan ("LTIP"), equity compensation awards may be awarded to the Company's employees, officers, consultants, advisors and directors including, but not limited to, shares of non-vested common stock. Prior to the acquisition by IEP Energy LLC and the

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related change of control, restricted shares, when granted, were valued at the closing market price of CVR Energy's common stock at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The change of control and related Transaction Agreement in May 2012 triggered a modification to outstanding awards under the LTIP. Pursuant to the Transaction Agreement, all restricted shares scheduled to vest in 2012 were converted to restricted stock units whereby the recipient received cash settlement of the offer price of $30.00 per share in cash plus one CCP upon vesting. Restricted shares scheduled to vest in 2013, 2014 and 2015 were converted to restricted stock units whereby the awards will be settled in cash upon vesting in an amount equal to the lesser of the offer price or the fair market value as determined at the most recent valuation date of December 31 of each year. As a result of the modification, additional share-based compensation of $12.4 million was incurred to revalue the unvested shares to the fair value upon the date of modification for the three and six months ended June 30, 2012. For awards vesting subsequent to 2012, the awards will be remeasured at each subsequent reporting date until they vest. In addition, the classification changed from an equity-classified award to a liability-classified award due to the cash settlement of the awards. For the three months ended June 30, 2013 and 2012, we incurred compensation expense of $3.7 million and $17.3 million, respectively, related to non-vested share-based compensation awards related to the LTIP. For the six months ended June 30, 2013 and 2012, we incurred compensation expense of $9.1 million and $20.8 million, respectively, related to non-vested share-based compensation awards related to the LTIP.

        Through the CVR Partners, LP Long-Term Incentive Plan ("CVR Partners LTIP"), shares of non-vested common units and phantom units may be awarded to (1) employees of the Nitrogen Fertilizer Partnership, (2) employees of the general partner and (3) members of the board of directors of the general partner. In December 2012, the board of directors of the general partner of the Nitrogen Fertilizer Partnership approved an amendment to modify the terms of certain phantom unit awards previously granted to employees of the Nitrogen Fertilizer Partnership and its subsidiaries. The amendment triggered a modification to the awards by providing that the phantom units would be settled in cash rather than common units of the Nitrogen Fertilizer Partnership. For awards vesting subsequent to amendment, the awards will be remeasured at each subsequent reporting date until they vest. As a result of the modification of the awards to employees of the Nitrogen Fertilizer Partnership, the classification changed from an equity-classified award to a liability-classified award. For the three months ended June 30, 2013 and 2012, we incurred compensation expense of $0.6 million and $0.5 million, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP. For the six months ended June 30, 2013 and 2012, we incurred compensation expense of $1.2 million and $1.1 million, respectively, related to non-vested share-based compensation awards related to the CVR Partners LTIP.

        Prior to the Refining Partnership IPO on January 23, 2013, the noncontrolling interest reflected in our condensed consolidated financial statements represented the approximately 30% interest in the Nitrogen Fertilizer Partnership held by common unitholders, which was adjusted each reporting period for the noncontrolling ownership percentage of the Nitrogen Fertilizer Partnership's net income and related distributions. As a result of the Refining Partnership IPO, CVR Energy recorded an additional noncontrolling interest for the Refining Partnership common units sold into the public market, which represented an approximately 19% interest of the Refining Partnership. Effective with the Refining Partnership's IPO, the noncontrolling interest reflected on the Condensed Consolidated Balance Sheets was impacted additionally, by the noncontrolling ownership percentage of the net income of the Refining Partnership and related distributions for each future reporting period. As a result of the Refining Partnership's closing of the Underwritten Offering to sell an additional 13,209,326 common units to the public (including 1,209,236 units purchased through the underwriters' option) and the sale of 2,000,000 common units to AEPC, the noncontrolling interest reflected in our condensed

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consolidated financial statements subsequent to the completion of the Transactions and as of June 30, 2013 is approximately 29%. Additionally, as a result of the Secondary Offering to sell 12,000,000 Nitrogen Fertilizer Partnership common units, the noncontrolling interest reflected in our condensed consolidated financial statements subsequent to the completion of the Secondary Offering on May 28, 2013 and as of June 30, 2013 is approximately 47%.

        The revenue and expenses from the Refining Partnership and Nitrogen Fertilizer Partnership are consolidated with CVR Energy's Condensed Consolidated Statements of Operations because each of the general partners is owned by CVR Refining Holdings and CRLLC, respectively, wholly-owned subsidiaries of CVR Energy. Therefore, CVR Energy has the ability to control the activities of the Refining Partnership and Nitrogen Fertilizer Partnership. However, the percentage of ownership held by the public unitholders for the Refining Partnership and the Nitrogen Fertilizer Partnership is reflected as net income attributable to noncontrolling interest in our Condensed Consolidated Statements of Operations and reduces consolidated net income to derive net income attributable to CVR Energy.

        We expect our general and administrative expenses will increase in 2013 in part due to the costs of the Refining Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to unitholders), 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, which also include increased personnel costs, will approximate $5.0 million per year, excluding the costs associated with the initial implementation of the Refining Partnership's Sarbanes-Oxley Section 404 internal controls review and testing. These increased costs will be paid by the Refining Partnership. Our historical condensed consolidated financial statements for periods ended prior to January 23, 2013 do not reflect the impact of these expenses, which affects the comparability of the post-Refining Partnership IPO results with our financial statements from periods prior to the completion of the Refining Partnership IPO.

        The Coffeyville refinery completed the second phase of a two-phase turnaround project during the first quarter of 2012. The first phase was completed during the fourth quarter of 2011. The Coffeyville refinery incurred costs of approximately $21.0 million for the six months ended June 30, 2012 associated with the 2011/2012 turnaround.

        As a result of the acquisition of the Wynnewood refinery in December 2011, we incurred transaction fees and integration expenses for the three and six months ended June 30, 2012 of $4.6 million and $8.3 million, respectively. We did not incur such expenses for the three and six months ended June 30, 2013 as the Wynnewood refinery's operations were fully integrated.

        CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reclassified and reassessed CRNF's nitrogen fertilizer plant for property tax purposes. The reclassification and reassessment resulted in an increase in CRNF's annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and 2009, $11.7 million for the year ended December 31, 2010, $11.4 million for the year ended December 31, 2011, and $11.3 million for the year ended

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December 31, 2012. CRNF protested the classification and resulting valuation for each of those years to the Kansas Court of Tax Appeals ("COTA"), followed by an appeal to the Kansas Court of Appeals. However, CRNF fully accrued and paid the property taxes the county claimed were owed for the years ended December 31, 2008 through 2012.

        On February 25, 2013, Montgomery County and CRNF agreed to a settlement for tax years 2009 through 2012, which will lower CRNF's property taxes by about $10.5 million per year for tax years 2013 through 2016 based on current mill levy rates. In addition, the settlement provides that Montgomery County will support CRNF's application before COTA for a ten year tax exemption for the UAN expansion. Finally, the settlement provides that CRNF will continue its appeal of the 2008 reclassification and reassessment.

        The current policy of the board of directors of the Nitrogen Fertilizer Partnership's general partner is to distribute all of the available cash the Nitrogen Fertilizer Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Nitrogen Fertilizer Partnership's general partner following the end of such quarter. Beginning with the first quarter of 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner has adopted an amended policy to calculate available cash starting with Adjusted Nitrogen Fertilizer EBITDA reduced for cash needed for net interest expense (excluding capitalized interest) and debt service and other contractual obligations, maintenance capital expenditures and, to the extent applicable, major scheduled turnaround expense incurred and reserves for future operating or capital needs that the board of directors of the Nitrogen Fertilizer Partnership's general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, at the discretion of the board of directors of the Nitrogen Fertilizer Partnership's general partner. Actual distributions are set by the board of directors of the Nitrogen Fertilizer Partnership's general partner. The board of directors of the Nitrogen Fertilizer Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Nitrogen Fertilizer Partnership to make distributions at all.

        The following is a summary of cash distributions paid to the Nitrogen Fertilizer Partnership unitholders during 2013 for the respective quarters to which the distributions relate:

 
  December 31,
2012
  March 31,
2013
  Total Cash
Distributions
Paid in 2013
 
 
  ($ in millions, expect per common
unit amounts)

 

Amount paid CRLLC

  $ 9.8   $ 31.1   $ 40.8  

Amounts paid to public unitholders

    4.2     13.5     17.8  
               

Total amount paid

  $ 14.0   $ 44.6   $ 58.6  
               

Per common unit

  $ 0.192   $ 0.610   $ 0.802  
               

Common units outstanding

    73.1     73.1        
                 

        On July 26, 2013, the board of directors of the Nitrogen Fertilizer Partnership's general partner declared a cash distribution for the second quarter of 2013 to the Nitrogen Fertilizer Partnership's unitholders of $0.583 per common unit or $42.6 million in aggregate. The cash distribution will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013. We will receive $22.7 million in respect of our common units.

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        The current policy of the board of directors of the Refining Partnership's general partner is to distribute all of the available cash the Refining Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Refining Partnership's general partner following the end of such quarter and will generally equal Adjusted Petroleum EBITDA reduced for cash needed for debt service, reserves for environmental and maintenance capital expenditures, reserves for future major scheduled turnaround expenses and, to the extent applicable, reserves for future operating or capital needs that the board of directors of the Refining Partnership's general partner deems necessary or appropriate, if any. Available cash for distributions may be increased by previously established cash reserves, if any, at the discretion of the board of directors of the Refining Partnership's general partner. Actual distributions are set by the board of directors of the Refining Partnership's general partner. The board of directors of the Refining Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Refining Partnership to make distributions at all.

        On May 17, 2013, the Refining Partnership paid out a cash distribution to the Refining Partnership's unitholders of record at the close of business on May 10, 2013 for the first quarter of 2013 in the amount of $1.58 per unit, or $233.2 million in aggregate. We received $189.6 million in respect of our common units. This distribution was adjusted to exclude the period from January 1, 2013 through January 22, 2013 (the period preceding the closing of the Refining Partnership IPO).

        On July 26, 2013, the board of directors of the Refining Partnership's general partner declared a cash distribution for the second quarter of 2013 to the Refining Partnership's unitholders of $1.35 per common unit or $199.3 million in aggregate. The cash distribution will be paid on August 14, 2013 to unitholders of record at the close of business on August 7, 2013. We will receive $141.5 million in respect of our common units.

        On January 24, 2013, our board of directors adopted a quarterly cash dividend policy. Subject to declaration by our board of directors, our initial quarterly dividend is expected to be $0.75 per share, or $3.00 per share on an annualized basis, which we began paying in the second quarter of 2013. Additionally, we declared and paid two special cash dividends during the six months ended June 30, 2013.

        The following is a summary of the quarterly and special dividends paid to stockholders during the six months ended June 30, 2013:

 
  February 19,
2013
  May 17,
2013
  June 10,
2013
  Total Dividends
Paid in 2013
 
 
  ($ in millions, expect per share amounts)
 

Dividend type

    Special     Quarterly     Special        

Amount paid IEP

  $ 391.6   $ 53.4   $ 462.8   $ 907.8  

Amounts paid to public stockholders

    86.0     11.7     101.6     199.3  
                   

Total amount paid

  $ 477.6   $ 65.1   $ 564.4   $ 1,107.1  
                   

Per common share

  $   5.50   $ 0.75   $   6.50   $ 12.75  
                   

Shares outstanding

    86.8     86.8     86.8        
                     

        On July 31, 2013, our board of directors declared a dividend for the second quarter of 2013 of $0.75 per share, or $65.1 million in aggregate. The dividend will be paid on August 19, 2013 to stockholders of record at the close of business on August 12, 2013.

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        The Refining Partnership enters into commodity swap contracts in order to fix the margin on a portion of future production. The physical volumes are not exchanged and these contracts are net settled with cash. The contract fair value of the commodity swaps is reflected on the Condensed Consolidated Balance Sheets with changes in fair value currently recognized in the Condensed Consolidated Statements of Operations. At June 30, 2013 and December 31, 2012, the Refining Partnership had open commodity hedging instruments consisting of 20.0 million barrels and 23.3 million barrels of crack spreads, respectively, primarily to fix the margin on a portion of future gasoline and distillate production. None of these swap contracts were designated as cash flow hedges, and all changes in fair market value will be reported in earnings in the period in which the value change occurs. For the three months ended June 30, 2013 and 2012, the Refining Partnership recognized net gains of $120.7 million and $34.7 million, respectively. For the six months ended June 30, 2013 and 2012, the Refining Partnership recognized a net gain of $102.9 million and a net loss of $104.6 million, respectively.


Results of Operations

        The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and six months ended June 30, 2013 and 2012. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Report. 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, 2012, is unaudited.

 
  Three Months Ended
June 30,
  Change from 2012  
 
  2013   2012   Change   Percent  
 
  (in millions, except per share amount)
 

Consolidated Statement of Operations Data:

                         

Net sales

  $ 2,220.3   $ 2,308.3   $ (88.0 )   (3.8 )%

Cost of product sold(1)

    1,785.4     1,874.2     (88.8 )   (4.7 )

Direct operating expenses(1)

    108.3     94.1     14.2     15.1  

Selling, general and administrative expenses(1)

    28.9     72.0     (43.1 )   (59.9 )

Depreciation and amortization(1)

    35.0     32.2     2.8     8.7  
                     

Operating income

    262.7     235.8     26.9     11.4  

Interest expense and other financing costs

    (12.5 )   (19.0 )   6.5     (34.2 )

Gain on derivatives, net

    120.5     38.8     81.7     210.6  

Other income, net

    0.5     0.8     (0.3 )   (37.5 )
                     

Income before income tax expense

    371.2     256.4     114.8     44.8  

Income tax expense

    99.5     91.1     8.4     9.2  
                     

Net income(2)

    271.7     165.3     106.4     64.4  

Less: Net income attributable to noncontrolling interest

    88.3     10.6     77.7     733.0  
                     

Net income attributable to CVR Energy stockholders

  $ 183.4   $ 154.7   $ 28.7     18.6 %
                     

Basic earnings per share

  $ 2.11   $ 1.78   $ 0.33     18.5 %

Diluted earnings per share

  $ 2.11   $ 1.75   $ 0.36     20.6 %

Weighted-average common shares outstanding:

                         

Basic

    86.8     86.8         %

Diluted

    86.8     88.4     (1.6 )   (1.8 )%

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  Six Months Ended
June 30,
  Change from 2012  
 
  2013   2012   Change   Percent  
 
  (in millions, except per share amount)
 

Consolidated Statement of Operations Data:

                         

Net sales

  $ 4,572.7   $ 4,276.9   $ 295.8     6.9 %

Cost of product sold(1)

    3,599.0     3,509.4     89.6     2.6  

Direct operating expenses(1)

    216.8     209.6     7.2     3.4  

Selling, general and administrative expenses(1)

    57.4     117.3     (59.9 )   (51.1 )

Depreciation and amortization(1)

    69.2     64.3     4.9     7.6  
                     

Operating income

    630.3     376.3     254.0     67.5  

Interest expense and other financing costs

    (27.9 )   (38.2 )   10.3     (27.0 )

Gain (loss) on derivatives, net

    100.5     (108.5 )   209.0     (192.6 )

Loss on extinguishment of debt

    (26.1 )       (26.1 )    

Other income, net

    0.9     1.1     (0.2 )   (18.2 )
                     

Income before income tax expense

    677.7     230.7     447.0     193.8  

Income tax expense

    193.3     81.4     111.9     137.5  
                     

Net income(2)

    484.4     149.3     335.1     224.4  

Less: Net income attributable to noncontrolling interest

    136.0     19.8     116.2     586.9  
                     

Net income attributable to CVR Energy stockholders

  $ 348.4   $ 129.5   $ 218.9     169.0 %
                     

Basic earnings per share

  $ 4.01   $ 1.49   $ 2.52     169.1 %

Diluted earnings per share

  $ 4.01   $ 1.46   $ 2.55     174.7 %

Weighted-average common shares outstanding:

                         

Basic

    86.8     86.8         %

Diluted

    86.8     88.5     (1.7 )   (1.9 )%

 

 
  As of June 30,
2013
  As of December 31,
2012
 
 
   
  (audited)
 
 
  (in millions)
 

Balance Sheet Data

             

Cash and cash equivalents

  $ 1,134.5   $ 896.0  

Working capital

    1,461.8     1,135.4  

Total assets

    4,023.4     3,610.9  

Total debt, including current portion

    676.8     898.2  

Total CVR Energy stockholders' equity

    1,299.0     1,525.1  

 

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Cash Flow Data

                         

Net cash flow provided by (used in):

                         

Operating activities

  $ 84.1   $ 249.6   $ 362.4   $ 435.9  

Investing activities

    (50.8 )   (45.4 )   (114.5 )   (104.8 )

Financing activities

    60.4     (12.4 )   (9.4 )   (26.8 )
                   

Net cash flow

  $ 93.7   $ 191.8   $ 238.5   $ 304.3  
                   

Other Financial Data

                         

Capital expenditures for property, plant and equipment

  $ 50.9   $ 45.6   $ 114.6   $ 105.2  

(1)
Amounts are shown exclusive of depreciation and amortization.

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  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Depreciation and amortization excluded from cost of product sold

  $ 1.3   $ 0.9   $ 2.4   $ 1.6  

Depreciation and amortization excluded from direct operating expenses

    33.2     30.7     65.7     61.5  

Depreciation and amortization excluded from selling, general and administrative expenses

    0.5     0.6     1.1     1.2  
                   

Total depreciation and amortization

  $ 35.0   $ 32.2   $ 69.2   $ 64.3  
                   
(2)
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 due to their unusual or infrequent nature. Positive amounts represent expenses which should be added to reported operating income for comparability, while negative amounts should be subtracted for comparability:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Loss on extinguishment of debt(a)

  $   $   $ 26.1   $  

Letter of credit expense included in selling, general and administrative expenses(b)

    0.1     0.4     0.2     0.7  

Major scheduled turnaround expenses(c)

        2.5         23.5  

Share-based compensation expense(d)

    4.3     17.8     10.3     21.9  

Acquisition and integration expenses—Gary-Williams(e)

        4.6         8.3  

(a)
On January 23, 2013, $253.0 million of the proceeds from the Refining Partnership's IPO were utilized to satisfy and discharge the indenture governing the Second Lien Notes. The repurchase of the Second Lien Notes resulted in a loss on extinguishment of debt of approximately $26.1 million for the six months ended June 30, 2013, which includes the premium paid of $20.6 million, the write-off of previously deferred financing fees of $3.7 million and unamortized original issue discount of $1.8 million.

(b)
Consists of fees which are expensed to selling, general and administrative expenses in connection with letters of credit outstanding.

(c)
Represents expenses associated with major scheduled turnarounds in the petroleum segment.

(d)
Represents the impact of share-based compensation awards.

(e)
On December 15, 2011, CRLLC acquired the stock of WEC (formerly known as Gary-Williams Energy Corporation) and its wholly-owned subsidiaries which owned a 70,000 barrel per day refinery in Wynnewood, Oklahoma. Included in "Acquisition and integration expenses—Gary-Williams" are legal and other professional fees associated with the acquisition and certain costs incurred in 2012 associated with the preliminary integration of the acquired business.

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        Net Sales.    Consolidated net sales were $2,220.3 million for the three months ended June 30, 2013 compared to $2,308.3 million for the three months ended June 30, 2012. The decrease of $88.0 million was primarily due to lower overall sales volume and lower product prices in the petroleum segment. The petroleum segment's average sales price per gallon for the three months ended June 30, 2013 of $2.88 for gasoline decreased by 0.6% while the average sales price for distillates of $2.95 remained unchanged, as compared to the three months ended June 30, 2012. The nitrogen fertilizer segment net sales increased primarily due to higher UAN sales volumes and higher ammonia prices, partially offset by lower ammonia sales volumes. The higher UAN sales volumes were primarily attributable to the UAN expansion being fully operational during the quarter.

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Consolidated cost of product sold (exclusive of depreciation and amortization) was $1,785.4 million for the three months ended June 30, 2013, as compared to $1,874.2 million for the three months ended June 30, 2012. The decrease of $88.8 million primarily resulted from a decrease in refined fuel sales volume, partially offset by an increase in the cost of RINs at the petroleum segment. The decrease in the petroleum segment was partially offset by higher cost of product sold (exclusive of depreciation and amortization) in the nitrogen fertilizer segment, which was primarily driven by increased freight costs and increased ammonia purchases.

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Consolidated direct operating expenses (exclusive of depreciation and amortization) were $108.3 million for the three months ended June 30, 2013, as compared to $94.1 million for the three months ended June 30, 2012. The increase of $14.2 million was due primarily to increases in repairs and maintenance costs, labor and energy and utility costs in the petroleum segment, partially offset by decreased expenses for the major scheduled turnaround performed in the prior year. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of higher costs for repairs and maintenance and utilities, partially offset by lower property taxes.

        Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).    Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $28.9 million for the three months ended June 30, 2013, as compared to $72.0 million for the three months ended June 30, 2012. The $43.1 million decrease was primarily the result of a decrease of $29.4 million related to costs incurred in the prior year period associated with the tender offer by certain entities affiliated with IEP and a decrease in share-based compensation of approximately $13.0 million primarily related to the modification of restricted shares to liability-classified restricted stock unit awards in the prior year.

        Operating Income.    Consolidated operating income was $262.7 million for the three months ended June 30, 2013, as compared to operating income of $235.8 million for the three months ended June 30, 2012, an increase of $26.9 million. The increase in operating income was primarily the result of a decrease in the corporate selling, general, and administrative expenses discussed above, partially offset by a decrease in the Petroleum segment operating income of $19.8 million as a result of higher direct operating expenses and higher selling, general and administrative expenses. Nitrogen fertilizer segment operating income increased $1.0 million primarily as a result of higher net sales and lower selling, general and administrative expenses.

        Interest Expense.    Consolidated interest expense for the three months ended June 30, 2013 was $12.5 million as compared to $19.0 million for the three months ended June 30, 2012. This $6.5 million decrease resulted primarily from lower interest expense on the outstanding 2022 Notes for the three

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months ended June 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the three months ended June 30, 2012.

        Gain on Derivatives, net.    For the three months ended June 30, 2013, we recorded a $120.5 million net gain on derivatives. This compares to a $38.8 million net gain on derivatives for the three months ended June 30, 2012. The change in the net gain on derivatives was primarily due to changes in crack spreads and an increase in the number of positions closing during the quarter to 7.7 million barrels from 5.3 million barrels in the prior year period. The petroleum segment entered into several over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014.

        Income Tax Expense.    Income tax expense for the three months ended June 30, 2013 was $99.5 million or 26.8% of income before income taxes, as compared to an income tax expense for the three months ended June 30, 2012 of $91.1 million or 35.5% of income before income taxes. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with our noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings and the benefits related to the domestic production activities deduction.

        Net Sales.    Consolidated net sales were $4,572.7 million for the six months ended June 30, 2013 compared to $4,276.9 million for the six months ended June 30, 2012. The increase of $295.8 million was primarily due to higher overall sales volume at the petroleum segment, which was partially offset by lower product prices. The increase in overall sales volume was largely a result of increased production due to the downtime associated with the completion of the second phase of the Coffeyville refinery's turnaround during the first quarter of 2012. The petroleum segment's average sales price per gallon for the six months ended June 30, 2013 of $2.85 for gasoline decreased by 1.2% while the average sales price for distillates of $3.03 remained unchanged, as compared to the six months ended June 30, 2012. The nitrogen fertilizer segment net sales increased by $10.5 million primarily due to higher UAN sales volumes as a result of the completion of the UAN expansion and higher ammonia sales prices, partially offset by lower UAN sales prices and lower ammonia sales volumes.

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,599.0 million for the six months ended June 30, 2013, as compared to $3,509.4 million for the six months ended June 30, 2012. The increase of $89.6 million primarily resulted from an increase in crude oil throughputs and an increase in the cost of RINs in the petroleum segment, which was partially offset by a decrease in crude oil prices. The nitrogen fertilizer segment cost of product sold (exclusive of depreciation and amortization) also increased primarily due to higher freight costs due to increased UAN sales volumes and increased ammonia purchases.

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Consolidated direct operating expenses (exclusive of depreciation and amortization) were $216.8 million for the six months ended June 30, 2013, as compared to $209.6 million for the six months ended June 30, 2012. The increase of $7.2 million was due primarily to increases in repairs and maintenance costs, energy and utility costs, labor and outside services in the petroleum segment, partially offset by decreases in major scheduled turnaround expenses performed in the prior year. The nitrogen fertilizer segment also had an increase in direct operating expenses (exclusive of depreciation and amortization), which was primarily the result of increases in utilities, repairs and maintenance costs and labor, partially offset by lower property taxes.

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        Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).    Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $57.4 million for the six months ended June 30, 2013, as compared to $117.3 million for the six months ended June 30, 2012. The decrease of $59.9 million was primarily the result of a decrease of $44.2 million related to costs incurred in the prior year associated with the tender offer by certain entities affiliated with IEP and a decrease in share-based compensation of approximately $11.4 million primarily related to the modification of restricted shares to liability-classified restricted stock unit awards during the three months ended June 30, 2012.

        Operating Income.    Consolidated operating income was $630.3 million for the six months ended June 30, 2013, as compared to operating income of $376.3 million for the six months ended June 30, 2012, an increase of $254.0 million. Petroleum segment operating income increased $180.9 million primarily as a result of higher refining margins. Nitrogen fertilizer segment operating income increased $6.4 million primarily as a result of higher net sales. Decreased corporate selling, general and administrative expenses discussed above also had a favorable impact on operating income for the period.

        Interest Expense.    Consolidated interest expense for the six months ended June 30, 2013 was $27.9 million as compared to $38.2 million for the six months ended June 30, 2012. The decrease of $10.3 million resulted primarily from lower interest expense on the outstanding 2022 Notes for the six months ended June 30, 2013 as compared to the outstanding First and Second Lien Senior Secured Notes for the six months ended June 30, 2012.

        Gain (loss) on Derivatives, net.    For the six months ended June 30, 2013, we recorded a $100.5 million net gain on derivatives. This compares to a $108.5 million net loss on derivatives for the six months ended June 30, 2012. The change in gain (loss) on derivatives was primarily due to changes in crack spreads and an increase in the number of positions closing during the six month period to 14.3 million barrels from 8.2 million barrels in the prior year period. The petroleum segment entered into several over-the-counter commodity swaps to fix the margin on a portion of its future gasoline and distillate production beginning in the fourth quarter of 2011 and continuing throughout 2014.

        Loss on Extinguishment of Debt.    For the six months ended June 30, 2013, we incurred a $26.1 million loss on extinguishment of debt. The loss on extinguishment of debt was the result of the extinguishment of the Second Lien Notes and included amounts related to the premium paid, the write-off of previously deferred financing costs and the write-off of the unamortized original issuance discount.

        Income Tax Expense.    Income tax expense for the six months ended June 30, 2013 was $193.3 million or 28.5% of income before income taxes, as compared to an income tax expense for the six months ended June 30, 2012 of $81.4 million or 35.3% of income before income taxes. Our 2013 effective tax rate is lower than the expected statutory rate primarily due to the reduction of income subject to tax associated with our noncontrolling ownership interests in CVR Refining's and CVR Partners' earnings and the benefits related to the domestic production activities deduction.

        The petroleum business includes the operations of both the Coffeyville and Wynnewood refineries. The following tables below provide an overview of the petroleum business' results of operations,

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relevant market indicators and its key operating statistics for the three and six months ended June 30, 2013 and 2012:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions, except as otherwise indicated)
 

Consolidated Petroleum Segment Summary Financial Results

                         

Net sales

  $ 2,138.1   $ 2,229.5   $ 4,412.1   $ 4,128.0  

Cost of product sold(1)

    1,776.6     1,866.1     3,582.3     3,496.8  

Direct operating expenses(1)

    83.8     69.1     169.9     140.8  

Major scheduled turnaround expenses

        2.5         23.5  

Depreciation and amortization

    28.4     26.6     56.4     52.9  
                   

Gross profit(3)

    249.3     265.2     603.5     414.0  

Plus:

                         

Direct operating expenses and major scheduled turnaround expenses(1)

    83.8     71.6     169.9     164.3  

Depreciation and amortization

    28.4     26.6     56.4     52.9  
                   

Refining margin(4)

    361.5     363.4     829.8     631.2  

Operating income (loss)

  $ 229.1   $ 248.9   $ 564.7   $ 383.8  

Adjusted Petroleum EBITDA(5)

  $ 250.6   $ 381.4   $ 560.5   $ 535.2  

 

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (dollars per barrel)
 

Key Operating Statistics

                         

Per crude oil throughput barrel:

                         

Refining margin(4)

  $ 20.56   $ 20.98   $ 23.63   $ 20.58  

Gross profit(3)

  $ 14.18   $ 15.31   $ 17.19   $ 13.50  

Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)(1)(2)

  $ 4.77   $ 4.13   $ 4.84   $ 5.36  

Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold(1)(6)

  $ 4.60   $ 3.81   $ 4.62   $ 4.75  

Barrels sold (barrels per day)(6)

    200,314     206,606     203,079     181,589  

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  Three Months Ended June 30,   Six Months Ended June 30,  
 
  2013   2012   2013   2012  
 
   
  %    
  %    
  %    
  %  

Refining Throughput and Production Data (barrels per day)

                                                 

Throughput:

                                                 

Sweet

    153,944     76.2     148,912     74.6     155,304     76.4     129,781     73.1  

Medium

    18,089     9.0     20,488     10.3     16,455     8.1     22,728     12.8  

Heavy sour

    21,168     10.5     20,972     10.5     22,244     10.9     16,006     9.0  
                                   

Total crude oil throughput

    193,201     95.7     190,372     95.4     194,003     95.4     168,515     94.9  

All other feedstocks and blendstocks

    8,724     4.3     9,129     4.6     9,248     4.6     8,929     5.1  
                                   

Total throughput

    201,925     100.0     199,501     100.0     203,251     100.0     177,444     100.0  
                                   

Production:

                                                 

Gasoline

    95,253     47.1     96,972     48.7     96,710     47.4     89,131     50.4  

Distillate

    84,617     41.8     82,075     41.3     84,232     41.3     72,202     40.9  

Other (excluding internally produced fuel)

    22,546     11.1     19,910     10.0     23,043     11.3     15,396     8.7  
                                   

Total refining production (excluding

                                                 

internally produced fuel)

    202,416     100.0     198,957     100.0     203,985     100.0     176,729     100.0  
                                   

Product price (dollars per gallon):

                                                 

Gasoline

  $ 2.88         $ 2.89         $ 2.85         $ 2.88        

Distillate

  $ 2.95         $ 2.95         $ 3.03         $ 3.03        

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  

Market Indicators (dollars per barrel)

                         

West Texas Intermediate (WTI) NYMEX

  $ 94.17   $ 93.35   $ 94.26   $ 98.15  

Crude Oil Differentials:

                         

WTI less WTS (light/medium sour)

    0.06     5.28     3.09     4.48  

WTI less WCS (heavy sour)

    16.79     20.45     21.94     23.79  

NYMEX Crack Spreads:

                         

Gasoline

    24.72     30.42     27.87     27.95  

Heating Oil

    27.19     28.13     30.21     28.87  

NYMEX 2-1-1 Crack Spread

    25.95     29.27     29.04     28.41  

PADD II Group 3 Basis:

                         

Gasoline

    1.52     (3.24 )   (2.88 )   (5.00 )

Ultra Low Sulfur Diesel

    2.13     2.16     2.11     0.28  

PADD II Group 3 Product Crack:

                         

Gasoline

    26.23     27.18     24.99     22.95  

Ultra Low Sulfur Diesel

    29.33     30.29     32.32     29.14  

PADD II Group 3 2-1-1

    27.78     28.74     28.66     26.05  

(1)
Amounts are shown exclusive of depreciation and amortization.

(2)
Direct operating expense is presented on a per crude oil throughput barrel basis. In order to derive the direct operating expenses per crude oil throughput barrel, we utilize 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.

(3)
Gross profit is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of

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(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 the refineries' performance as a general indication of the amount above the cost of product sold that it is 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 the petroleum business' Statements of Operations. The petroleum business' calculation of refining margin may differ from similar calculations of other companies in its 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 for greater transparency in the review of our overall business, financial, operational and economic financial performance.

(5)
Adjusted Petroleum EBITDA represents operating income for the petroleum segment adjusted for (i) FIFO impacts (favorable) unfavorable, (ii) share-based compensation, non-cash, (iii) major scheduled turnaround expenses, (iv) current period settlements on derivative contracts, (v) depreciation and amortization and (vi) other income (expense). We present Adjusted Petroleum EBITDA because it is the starting point for the Refining Partnership's available cash for distribution. Adjusted Petroleum EBITDA is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance. Management believes that Adjusted Petroleum EBITDA enables investors to better understand the Refining Partnership's ability to make distributions to its common unitholders, evaluate the petroleum segment's ongoing operating results and allows for greater transparency in reviewing the petroleum segment's overall financial, operational and economic performance. Adjusted Petroleum EBITDA presented by other companies may not be comparable to our presentation, since each company may define these terms differently. Below is a reconciliation of operating income for the petroleum segment to Adjusted Petroleum EBITDA for the three and six months ended June 30, 2013 and 2012:

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Petroleum Consolidated:

                         

Petroleum operating income

  $ 229.1   $ 248.9   $ 564.7   $ 383.8  

FIFO impacts (favorable), unfavorable(a)

    (24.2 )   105.4     (29.0 )   95.0  

Share-based compensation, non-cash

    2.5     5.4     6.1     6.4  

Major scheduled turnaround expenses(b)

        2.5         23.5  

Current period settlements on derivative contracts

    14.7     (8.1 )   (37.8 )   (27.2 )

Depreciation and amortization

    28.4     26.6     56.4     52.9  

Other income (expense)

    0.1     0.7     0.1     0.8  
                   

Adjusted Petroleum EBITDA

  $ 250.6   $ 381.4   $ 560.5   $ 535.2  
                   

(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,

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(b)
Represents expense associated with a major scheduled turnaround at the petroleum segment.
(6)
Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refineries. We utilize direct operating expenses, which does not include depreciation or amortization expense, and divide the applicable number of barrels sold for the period to derive the metric.

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (in millions)
 

Coffeyville Refinery Financial Results

                         

Net sales

  $ 1,349.2   $ 1,447.0   $ 2,841.7   $ 2,579.5  

Cost of product sold (exclusive of depreciation and amortization)

    1,117.6     1,219.4     2,312.6     2,192.5  

Direct operating expenses (exclusive of depreciation and amortization)

    50.1     43.6     102.3     87.4  

Major scheduled turnaround expenses

        0.9         21.0  

Depreciation and amortization

    17.7     17.4     35.2     34.7  
                   

Gross profit

    163.8     165.7     391.6     243.9  

Plus:

                         

Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)

    50.1     44.5     102.3     108.4  

Depreciation and amortization

    17.7     17.4     35.2     34.7  
                   

Refining margin

  $ 231.6   $ 227.6   $ 529.1   $ 387.0  

 

 
  Three Months Ended
June 30,
  Six Months Ended
June 30,
 
 
  2013   2012   2013   2012  
 
  (dollars per barrel)
 

Coffeyville Refinery Key Operating Statistics

                         

Per crude oil throughput barrel:

                         

Refining margin

  $ 21.71   $ 20.61   $ 24.27   $ 20.27  

Gross profit

  $ 15.35   $ 15.00   $ 17.97   $ 12.78  

Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization)

  $ 4.69   $ 4.03   $ 4.69   $ 5.68  

Direct operating expenses and major scheduled turnaround expenses (exclusive of depreciation and amortization) per barrel sold

  $ 4.37   $ 3.69   $ 4.35   $ 5.41  

Barrels sold (barrels per day)

    125,851     132,534     129,777     110,034  

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  Three Months Ended June 30,   Six Months Ended June 30,  
 
  2013   2012   2013   2012  
 
   
  %    
  %    
  %    
  %  

Coffeyville Refinery Throughput and Production Data (bpd)

                                                 

Throughput:

                                                 

Sweet

    95,763     77.1     100,166     78.4     97,767     76.6     86,041     77.7  

Medium

    334     0.3     187     0.1     423     0.3     2,817     2.5  

Heavy sour

    21,168     17.0     20,972     16.4     22,244     17.4     16,006     14.4  
                                   

Total crude oil throughput

    117,265     94.4     121,325     94.9     120,434     94.3     104,864     94.6  

All other feedstocks and blendstocks

    6,962     5.6     6,500     5.1     7,265     5.7     5,934     5.4  
                                   

Total throughput

    124,227     100.0     127,825     100.0     127,699     100.0     110,798     100.0  
       </