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TABLE OF CONTENTS
Item 8. Financial Statements and Supplementary Data

Table of Contents

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


Form 10-K

(Mark One)    

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

 
 
For the fiscal year ended December 31, 2011

OR

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

 
 
For the transition period from                                    to                                   

Commission file number: 001-33492


CVR Energy, Inc.
(Exact name of registrant as specified in its charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)		   61-1512186
(I.R.S. Employer
Identification No.)

2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of Principal Executive Offices)
 

77479
(Zip Code)

Registrant's Telephone Number, including Area Code:
(281) 207-3200


          Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class
 
Name of Each Exchange on Which Registered
Common Stock, $0.01 par value per share
Series A Preferred Stock Purchase Right, par value $0.01 per share		   The New York Stock Exchange
The New York Stock Exchange

          Securities registered pursuant to Section 12(g) of the Act:
None

          Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes þ        No o

          Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes o        No þ

          Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes þ        No o.

          Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes þ        No o.

          Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    þ

          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 þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
    (Do not check if a smaller reporting company)          
 		   

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

          The aggregate market value of the registrant's common stock (based upon the closing sale price of the common stock on the New York Stock Exchange on June 30, 2011) held by those persons deemed by the registrant to be non-affiliates was approximately $2.18 billion. Shares of the registrant's common stock held by each executive officer and director and by each entity or person that, to the registrant's knowledge, owned 10% or more of the registrant's outstanding common stock as of June 30, 2011 have been excluded from this number in that these persons may be deemed affiliates of the registrant. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

          Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date.

Class
 
Outstanding at February 17, 2012
Common Stock, par value $0.01 per share   86,808,150 shares

Documents Incorporated By Reference

Document
 
Parts Incorporated
Proxy Statement for the 2012 Annual Meeting of Stockholders   Items 10, 11, 12, 13 and 14 of Part III

   

Table of Contents


TABLE OF CONTENTS

 
    
   Page
PART I
Item 1.   Business   5
Item 1A.   Risk Factors   23
Item 1B.   Unresolved Staff Comments   55
Item 2.   Properties   56
Item 3.   Legal Proceedings   56
Item 4.   Mine Safety Disclosures   57
PART II
Item 5.   Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   58
Item 6.   Selected Financial Data   62
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   65
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk   113
Item 8.   Financial Statements and Supplementary Data   116
Item 9.   Changes in and Disagreements With Accountants on Accounting and Financial Disclosure   181
Item 9A.   Controls and Procedures   181
Item 9B.   Other Information   181
PART III
Item 10.   Directors, Executive Officers and Corporate Governance   182
Item 11.   Executive Compensation   182
Item 12.   Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters   182
Item 13.   Certain Relationships and Related Transactions, and Director Independence   182
Item 14.   Principal Accounting Fees and Services   182
PART IV
Item 15.   Exhibits, Financial Statement Schedules   183

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GLOSSARY OF SELECTED TERMS

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

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

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

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

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

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

        bpd — Abbreviation for barrels per day.

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

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

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

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

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

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

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

        distillates — Primarily diesel fuel, kerosene and jet fuel.

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

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        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, that are produced by a refinery.

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

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

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

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

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

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

        NYSE — the New York Stock Exchange.

        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.

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

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

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

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

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

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

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

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

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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 our refineries and every two years for the nitrogen fertilizer plant.

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

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

        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.

        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.

        Wynnewood Acquisition — The acquisition by the Company of all the outstanding shares of the Gary-Williams Energy Corporation and its subsidiaries ("GWEC"), which owns the 70,000 bpd Wynnewood, Oklahoma refinery and 2.0 million barrels of storage tanks, on December 15, 2011.

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

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PART I

Item 1.    Business

        CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries ("CVR Energy", the "Company", "we", "us", or "our") is an independent petroleum refiner and marketer of high value transportation fuels. In addition, we own the general partner and approximately 70% of the common units of CVR Partners, LP (the "Partnership"), a limited partnership which produces nitrogen fertilizers in the form of ammonia and UAN. CVR Energy's common stock is listed on the NYSE under the symbol "CVI."

        Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma. In addition to the refineries, we own and operate supporting businesses that include:

        The nitrogen fertilizer business consists of a nitrogen fertilizer facility in Coffeyville, Kansas that is the only operation in North America that uses a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer. The nitrogen fertilizer facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day. The nitrogen fertilizer business' gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving its reliability. A majority of the ammonia produced by the nitrogen fertilizer plant is further upgraded to UAN, which has historically commanded a premium price over ammonia.

        We have two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2011, 2010 and 2009, we generated consolidated net sales of $5.0 billion, $4.1 billion and $3.1 billion, respectively, and operating income of $566.6 million, $93.1 million and $208.2 million, respectively. Our petroleum business generated $4.8 billion, $3.9 billion and $2.9 billion of net sales and the nitrogen fertilizer business generated $302.9 million, $180.5 million and $208.4 million of net sales, in each case, for the years ended December 31, 2011, 2010 and 2009, respectively. Our petroleum business generated operating income of $465.7 million, $104.6 million and $170.2 million and the nitrogen fertilizer business generated operating income of $136.2 million, $20.4 million and $48.9 million, in each case, for the years ended December 31, 2011, 2010 and 2009, respectively. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and, therefore, are not a sum of the operating results of the petroleum and nitrogen fertilizer businesses.

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Our History

        Our Coffeyville refinery, which began operations in 1906, and the nitrogen fertilizer plant, built in 2000, were operated as components of Farmland Industries, Inc. ("Farmland"), an agricultural cooperative, and its predecessors until March 3, 2004.

        Coffeyville Resources, LLC ("CRLLC"), a subsidiary of Coffeyville Group Holdings, LLC, won a bankruptcy court auction for Farmland's petroleum business and a nitrogen fertilizer plant located in Coffeyville, Kansas and completed the purchase of these assets on March 3, 2004. Coffeyville Group Holdings, LLC operated our business from March 3, 2004 through June 24, 2005.

        On June 24, 2005, Coffeyville Acquisition LLC ("CALLC"), which was formed by certain funds affiliated with Goldman, Sachs & Co. and Kelso & Company, L.P. (the "Goldman Sachs Funds" and the "Kelso Funds," respectively), acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. CALLC operated our business from June 24, 2005 until CVR Energy's initial public offering in October 2007.

        CVR Energy was formed in September 2006 as a subsidiary of CALLC in order to consummate an initial public offering of the businesses operated by CALLC. Immediately prior to CVR Energy's initial public offering in October 2007:

        CVR Energy consummated its initial public offering on October 26, 2007. In February 2011, the Goldman Sachs Funds sold their remaining ownership interests in CVR Energy in a registered offering and in May 2011, the Kelso Funds sold their remaining ownership interests in CVR Energy in a registered offering.

        On April 13, 2011, the Partnership completed its initial public offering of its common units representing limited partner interests (the "Partnership IPO"). The Partnership sold 22,080,000 common units at a price of $16.00 per common unit, resulting in gross proceeds of $353.3 million, before giving effect to underwriting discounts and other offering costs. The Partnership's common units are listed on the NYSE and are traded under the symbol "UAN." In connection with the Partnership IPO, the Partnership paid approximately $24.7 million in underwriting fees and incurred approximately $4.4 million of other offering costs. Approximately $5.7 million was paid to an affiliate of Goldman, Sachs & Co. which was acting as a joint book-running manager. Until the completion of the February 2011 secondary offering described above, an affiliate of Goldman, Sachs & Co. was a stockholder and a related party of the Company. As a result of the Partnership IPO, CVR Energy indirectly owns approximately 70% of the Partnership's outstanding common units and 100% of the Partnership's general partner with its non-economic general partner interest. On February 13, 2012, we announced our intention to sell a portion of our investment in the Partnership and use the proceeds to pay a special dividend to holders of our common stock. There can be no assurance as to the terms, conditions, amount or timing of such sale or dividend, or whether such sale or dividend will take place

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at all. This announcement does not constitute an offer of any securities for sale and is being made in accordance with Rule 135 under the Securities Act.

        On December 15, 2011, CVR Energy acquired all of the issued and outstanding shares of Gary-Williams Energy Corporation (subsequently converted to Gary-Williams Energy Company, LLC or "GWEC") for $592.3 million, consisting of an initial cash payment of $525.0 million, capital expenditure adjustments of $1.5 million and $65.8 million for working capital (the "Wynnewood Acquisition"). Assets acquired include a 70,000 bpd refinery in Wynnewood, Oklahoma and approximately 2.0 million barrels of company-owned storage tanks.

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


Organizational Structure and Related Ownership as of December 31, 2011

        The following chart illustrates our organizational structure and the organizational structure of the Partnership.

GRAPHIC

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Petroleum Business

        We operate a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma. Our combined production capacity represents approximately 15% of our region's output. The Coffeyville facility is situated on approximately 440 acres in southeast Kansas, approximately 100 miles from Cushing, Oklahoma, a major crude oil trading and storage hub. The Wynnewood facility is situated on approximately 400 acres located approximately 65 miles south of Oklahoma City, Oklahoma and approximately 130 miles from Cushing, Oklahoma.

        For the year ended December 31, 2011, our Coffeyville refinery's product yield included gasoline (mainly regular unleaded) (44%), diesel fuel (primarily ultra-low sulfur diesel) (42%), and pet coke and other refined products such as natural gas liquids ("NGL") (propane and butane), slurry, sulfur and gas oil (14%). Our Wynnewood refinery's product yield included gasoline (54%), diesel fuel (primarily ultra-low sulfur diesel) (31%), asphalt (6%), jet fuel (3%) and other products (6%).

        Our petroleum business also includes the following auxiliary operating assets:

        Our refineries' complexity allows us to optimize the yields (the percentage of refined product that is produced from crude oil and other feedstocks) of higher value transportation fuels (gasoline and diesel). Complexity is a measure of a refinery's ability to process lower quality crude oil in an economic manner. As a result of key investments in our refining assets, our Coffeyville refinery's complexity score increased to 12.9 from 12.2 in 2010, and we have achieved significant increases in our refinery crude oil throughput rate over historical levels. The Wynnewood refinery has a complexity of 9.3 and is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and U.S. Gulf Coast crudes. Our higher complexity provides us the flexibility to increase our refining margin over comparable refiners with lower complexities.

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        Our Coffeyville refinery has the capability to process blends of a variety of crude oil ranging from heavy sour to light sweet crude oil. Currently, our refinery processes crude oil from a broad array of sources. We have access to foreign crude oil from Latin America, South America, West Africa, the Middle East, the North Sea and Canada. We purchase domestic crude oil from Kansas, Oklahoma, Nebraska, Texas, North Dakota, Missouri, and offshore deepwater Gulf of Mexico production. While crude oil has historically constituted over 90% of our feedstock inputs during the last five years, other feedstock inputs include normal butane, natural gasoline, alky feed, naphtha, gas oil and vacuum tower bottoms.

        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 isobutane, gasoline components, and normal butane are also typically used. Historically most of the Wynnewood refinery's crude oil has been acquired domestically, mainly from Texas and Oklahoma.

        Crude oil is supplied to our Coffeyville refinery through our wholly-owned gathering system and by pipeline. We have continued to increase the number of barrels of crude oil supplied through our crude oil gathering system in 2011 and it now has the capacity of supplying approximately 38,000 bpd of crude oil to the refinery. In the year ended December 31, 2011, the gathering system supplied approximately 35% of the Coffeyville refinery's crude oil demand. Locally produced crude oils are delivered to the refinery at a discount to WTI, and although slightly heavier and more sour, offer good economics to the refinery. These crude oils are light and sweet enough to allow us to blend higher percentages of lower cost crude oils such as heavy sour Canadian crude oil while maintaining our target medium sour blend with an API gravity of between 28 and 36 degrees and between 0.9% and 1.2% sulfur. Crude oils sourced outside of our proprietary gathering system are delivered to Cushing, Oklahoma by various pipelines including Seaway, Basin and Spearhead and subsequently to Coffeyville via the Plains pipeline and our own 145,000 bpd proprietary pipeline system. Beginning in March 2011, crude oils were also delivered through the Keystone pipeline. Crude oil is supplied to the Wynnewood refinery by two separate pipelines, and received into storage tanks at terminals located on or near the refinery.

        For the year ended December 31, 2011, our Coffeyville crude oil supply blend was comprised of approximately 80% light sweet crude oil, 2% light/medium sour crude oil and 18% heavy sour crude oil. The light sweet crude oil includes our locally gathered crude oil. For the year ended December 31, 2011, Wynnewood's crude oil supply blend was comprised of approximately 88% sweet crude oil and 12% light/medium sour crude oil.

        For the year ended December 31, 2011, we obtained approximately 65% of the crude oil for our Coffeyville refinery under a Crude Oil Supply Agreement, as amended, (the "Supply Agreement") with Vitol Inc. ("Vitol") that expires on December 31, 2013. Under the Supply Agreement, Vitol supplies us with crude oil and intermediation logistics, which helps us reduce our inventory position and mitigate crude oil pricing risk.

        We focus our Coffeyville petroleum product marketing efforts in the central mid-continent and Rocky Mountain areas because of their relative proximity to our refinery and their pipeline access. We engage in rack marketing, which is the supply of product through tanker trucks directly to customers located in close geographic proximity to our refinery and to customers at throughput terminals on Magellan's and NuStar's refined products distribution systems. For the year ended December 31, 2011, approximately 35% of the Coffeyville refinery's products were sold through the rack system directly to retail and wholesale customers while the remaining 65% was sold through pipelines via bulk spot and term contracts. We make bulk sales (sales into third party pipelines) into the mid-continent markets via

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Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. ("Enterprise") and NuStar.

        The Wynnewood refinery ships its finished product via pipeline, rail car, and truck. Approximately 60% of the Wynnewood refinery's finished products sold are distributed in Oklahoma. Non-Oklahoma gasoline and ultra-low sulfur diesel volumes are distributed throughout the Mid-Continent region via the Magellan Pipeline. Wynnewood distributes approximately 12,000 bpd of gasoline and ultra-low sulfur diesel via the refinery's truck rack, and has the ability to distribute volumes via the NuStar pipeline system to South Dakota, Nebraska, Iowa, and Kansas. Wynnewood also sells jet fuel to the U.S. Department of Defense via the truck rack. In addition, Wynnewood maintains exchange agreements with five refineries in nearby states. The agreements allow volumes to be exchanged between the refineries and directly distributed to customers in order to reduce the transportation costs.

        Customers for our petroleum products include other refiners, convenience store companies, railroads and farm cooperatives. We have bulk term contracts in place with many of these customers, which typically extend from a few months to one year in length. Additionally, effective December 15, 2011, as a result of the Wynnewood Acquisition, we have a 4,000 bpd jet fuel contract with the U.S Department of Defense that has been maintained since 1996. For the year ended December 31, 2011, our two largest customers accounted for approximately 15% and 12% of our petroleum business sales and approximately 66% of our petroleum sales were made to our ten largest customers. We sell bulk products based on industry market related indices such as Platts, Oil Price Information Service or at a spot market price based on a Group 3 differential to the New York Mercantile Exchange ("NYMEX"). Through our rack marketing division, the rack sales are at daily posted prices which are influenced by the NYMEX, competitor pricing and Group 3 spot market differentials.

        Our petroleum business competes primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are cost of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refineries provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors. We primarily compete against six refineries operated in the mid-continent region. In addition to these refineries, our crude oil refinery in Coffeyville, Kansas competes against trading companies, as well as other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the U.S. Gulf Coast and the Texas panhandle region. Our refinery competition also includes branded, integrated and independent oil refining companies, such as BP, Conoco Phillips, HollyFrontier, NCRA, Valero, Flint Hills Resources, CHS and Shell.

        Our petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel during the winter months also decreases due to winter agricultural work declines. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third calendar quarters. In addition, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products can impact the demand for gasoline and diesel fuel.

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Nitrogen Fertilizer Business

        The nitrogen fertilizer business, operated by the Partnership, is the only nitrogen fertilizer plant in North America that utilizes a pet coke gasification process to produce nitrogen fertilizer.

        The nitrogen fertilizer facility's primary input is pet coke. On average, during the past five years, over 70% of the nitrogen fertilizer business' pet coke requirements were supplied by our adjacent crude oil refinery. Historically the nitrogen fertilizer business has obtained the remainder of its pet coke requirements from third parties such as other Midwestern refineries or pet coke brokers at spot prices. If necessary, the gasifier can also operate on low grade coal as an alternative.

        Linde LLC ("Linde") owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to the gasifier for a monthly fee. The nitrogen fertilizer business provides and pays for all utilities required for operation of the air separation plant. The agreement with Linde expires in 2020.

        The nitrogen fertilizer business imports start-up steam for the nitrogen fertilizer plant from our adjacent Coffeyville crude oil refinery, and then exports steam back to the adjacent crude oil refinery once all units in the nitrogen fertilizer plant are in service. Monthly charges and credits are recorded with steam valued at the natural gas price for the month.

        The nitrogen fertilizer plant was completed in 2000 and is the newest nitrogen fertilizer plant built in North America. The nitrogen fertilizer plant has two separate gasifiers to provide redundancy and reliability. The plant uses a gasification process to convert pet coke to high purity hydrogen for subsequent conversion to ammonia. The nitrogen fertilizer plant is capable of processing approximately 1,400 tons per day of pet coke from our Coffeyville crude oil refinery and third party sources and converting it into approximately 1,200 tons per day of ammonia. A majority of the ammonia is converted to approximately 2,000 tons per day of UAN. Typically 0.41 tons of ammonia is required to produce one ton of UAN.

        The nitrogen fertilizer business schedules and provides routine maintenance to its critical equipment using its own maintenance technicians. Pursuant to a Technical Services Agreement with an affiliate of the General Electric Company ("General Electric"), which licenses the gasification technology to the nitrogen fertilizer business, General Electric experts provide technical advice and technological updates from their ongoing research as well as other licensees' operating experiences. The pet coke gasification process is licensed from General Electric pursuant to a license agreement that is fully paid. The license grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions.

        The primary geographic markets for the nitrogen fertilizer business' fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas. The nitrogen fertilizer business markets the ammonia products to industrial and agricultural customers and the UAN products to agricultural customers. The demand for nitrogen fertilizers occurs during three key periods. The highest level of ammonia demand is traditionally in the spring pre-plant, from March through May. The second-highest period of demand occurs during fall pre-plant in late October and November. The summer wheat pre-plant occurs in August and September. In addition, smaller quantities of ammonia are sold in the off-season to fill available storage at the dealer level.

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        Ammonia and UAN are distributed by truck or by railcar. If delivered by truck, products are sold on a freight-on-board basis, and freight is normally arranged by the customer. The nitrogen fertilizer business leases a fleet of railcars for use in product delivery, and also negotiates with distributors that have their own leased railcars to utilize these assets to deliver products. The nitrogen fertilizer business operates two truck loading and four rail loading racks for each of ammonia and UAN, with an additional four rail loading racks for UAN. The nitrogen fertilizer business owns all of the truck and rail loading equipment at the nitrogen fertilizer facility.

        The nitrogen fertilizer business markets agricultural products to destinations that produce strong margins. The UAN market is primarily located near the Union Pacific Railroad lines or destinations that can be supplied by truck. The ammonia market is primarily located near the Burlington Northern Santa Fe or Kansas City Southern Railroad lines or destinations that can be supplied by truck.

        The nitrogen fertilizer business uses forward sales of fertilizer products to optimize its asset utilization, planning process and production scheduling. These sales are made by offering customers the opportunity to purchase product on a forward basis at prices and delivery dates that it proposes. The nitrogen fertilizer business uses this program to varying degrees during the year and between years depending on market conditions and has the flexibility to increase or decrease forward sales depending on management's view as to whether price environments will be increasing or decreasing. Fixing the selling prices of nitrogen fertilizer products months in advance of their ultimate delivery to customers typically causes the nitrogen fertilizer business reported selling prices and margins to differ from spot market prices and margins available at the time of shipment. Cash received as a result of prepayments is recognized as deferred revenue on the balance sheet upon receipt; revenue and resultant net income are recorded as the product is actually delivered to the customer.

        The nitrogen fertilizer business sells ammonia to agricultural and industrial customers. Based upon a three-year average, the nitrogen fertilizer business has sold approximately 87% of the ammonia it produces to agricultural customers primarily located in the mid-continent area between North Texas and Canada, and approximately 13% to industrial customers. Agricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., Gavilon Fertilizer LLC, Transammonia, Inc., Agri Services of Brunswick, LLC, Interchem, and CHS Inc. Industrial customers include Tessenderlo Kerley, Inc., National Cooperative Refinery Association, and Dyno Nobel, Inc. The nitrogen fertilizer business sells UAN products to retailers and distributors. Given the nature of its business, and consistent with industry practice, the nitrogen fertilizer business does not have long-term minimum purchase contracts with any of its customers.

        For the year ended December 31, 2011, the top five ammonia customers in the aggregate represented 61.3% of the nitrogen fertilizer business' ammonia sales and the top five UAN customers in the aggregate represented 49.0% of the nitrogen fertilizer business' UAN sales. For the year ended December 31, 2011, our two largest customers accounted for approximately 17% and 12% of the nitrogen fertilizer business' sales.

        Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. The nitrogen fertilizer business maintains a large fleet of leased rail cars and seasonally adjusts inventory to enhance its manufacturing and distribution operations.

        Domestic competition, mainly from regional cooperatives and integrated multinational fertilizer companies, is intense due to customers' sophisticated buying tendencies and production strategies that focus on cost and service. Also, foreign competition exists from producers of fertilizer products

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manufactured in countries with lower cost natural gas supplies. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments. The nitrogen fertilizer business' major competitors include Agrium, Koch Nitrogen, Potash Corporation and CF Industries.

        Based on third-party expert data regarding total U.S. demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant's UAN production in 2011 represented approximately 6% of the total U.S. demand and that the net ammonia produced and marketed at Coffeyville represented approximately 1% of the total U.S. demand.

        Because the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, the nitrogen fertilizer business typically generates greater net sales in the first half of each calendar year, which we refer to as the planting season, and our net sales tend to be lower during the second half of each calendar year, which we refer to as the fill season.

Environmental Matters

        The petroleum and nitrogen fertilizer businesses 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 storage, handling, use and transportation of petroleum and nitrogen products, and the characteristics and composition of gasoline and diesel fuels. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact our petroleum business and operations and the nitrogen fertilizer business and operations by imposing:

        Our operations require numerous permits and authorizations. Failure to comply with these permits or environmental laws and regulations could result in fines, penalties or other sanctions or a revocation of our permits. In addition, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal or state agencies. The ultimate impact on our business 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.

        The principal environmental risks associated with our businesses are outlined below.

        The federal Clean Air Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air, affect our petroleum operations and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through the federal Clean Air Act's permitting requirements and/or emission control requirements relating to

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specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases of certain regulated substances. The federal Clean Air Act indirectly affects our petroleum operations and the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide ("SO2"), volatile organic compounds, nitrogen oxides and other substances, including those emitted by mobile sources, which are direct or indirect users of our products.

        Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to our petroleum operations or the nitrogen fertilizer facilities in order to comply. If new controls or changes to operations are needed, the costs could be significant. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to comply and/or permit our facilities to produce products that meet applicable requirements.

        The regulation of air emissions under the federal Clean Air Act requires that we obtain various construction and operating permits and incur capital expenditures for the installation of certain air pollution control devices at our petroleum and nitrogen fertilizer operations when regulations change or we add new or modify our equipment. Various regulations specific to our operations have been implemented, such as National Emission Standard for Hazardous Air Pollutants, New Source Performance Standards and New Source Review/Prevention of Significant Deterioration ("NSR"). We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future. The EPA recently proposed revisions to the New Source Performance Standards for nitric acid plants. We do not expect to incur capital expenditures or any significant additional operational expenses associated with the revised standards, as proposed.

        In March 2004, Coffeyville Resources Refining & Marketing, LLC ("CRRM") and Coffeyville Resources Terminal, LLC ("CRT") entered into a Consent Decree (the "Coffeyville Consent Decree") with the U.S. Environmental Protection Agency (the "EPA") and the Kansas Department of Health and Environment (the "KDHE") to resolve air compliance concerns raised by the EPA and KDHE related to Farmland's prior ownership and operation of our Coffeyville crude oil refinery and the now-closed Phillipsburg terminal facilities. As a result of CRRM's agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland's alleged noncompliance with the issues addressed by the Coffeyville Consent Decree. Under the Coffeyville Consent Decree, CRRM agreed to install controls to reduce emissions of SO2, nitrogen oxides and particulate matter from its fluid catalytic cracking unit ("FCCU") by January 1, 2011. In addition, pursuant to the Coffeyville Consent Decree, CRRM and CRT assumed cleanup obligations at the Coffeyville refinery and the now-closed Phillipsburg terminal facilities. The remaining costs of complying with the Coffeyville Consent Decree are expected to be approximately $49 million, of which approximately $47 million is expected to be capital expenditures which does not include the cleanup obligations for historic contamination at the site that are being addressed pursuant to administrative orders issued under the Resource Conservation and Recovery Act ("RCRA"). To date, CRRM and CRT have materially complied with the Coffeyville Consent Decree. On June 30, 2009, CRRM submitted a force majeure notice to the EPA and KDHE in which CRRM indicated that it might be unable to meet the Coffeyville Consent Decree's January 1, 2011 deadline related to the installation of controls on the FCCU to reduce emissions of SO2 and nitrogen oxides because of delays caused by the June/July 2007 flood. In February 2010, CRRM and the EPA agreed to a fifteen month extension of the January 1, 2011, deadline for the installation of controls which was approved by the Court as a material modification to the existing Coffeyville Consent Decree. Pursuant to this agreement, CRRM agreed to offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe.

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        In the meantime, CRRM has been negotiating with the EPA and KDHE to replace the current Coffeyville Consent Decree, including the fifteen month extension, with a global settlement under the National Petroleum Refining Initiative. Over the course of the last decade, the EPA has embarked on a National Petroleum Refining Initiative alleging industry-wide noncompliance with four "marquee" issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The National Petroleum Refining Initiative has resulted in most U.S. refineries entering into consent decrees imposing civil penalties and requiring the installation of pollution control equipment and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into "global settlements" pertaining to all "marquee" issues. The Coffeyville Consent Decree covers some, but not all, of the "marquee" issues. We have been negotiating with the EPA to expand the Coffeyville Consent Decree obligations to include all of the "marquee" issues under the Petroleum Refining Initiative, and the parties have reached an agreement which includes an agreement to further extend the deadline for the installation of controls on the FCCU. Under the global settlement, we will be required to pay a civil penalty, but our incremental capital expenditures would not be material and would be limited primarily to the retrofit and replacement of heaters and boilers over a five to seven year timeframe. The new Consent Decree is awaiting final EPA approval after which it will be lodged with the court and then subject to a public notice and comment period before it becomes final.

        The Wynnewood Refining Company, LLC ("WRC") 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 ODEQ about doing so. Instead, Wynnewood entered into a Consent Order with 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. The costs of complying with the Wynnewood Consent Order, other than costs associated with a planned turnaround, are expected to be approximately $1.5 million. In consideration for entering into the Wynnewood Consent Order, WRC received a broad release from liability from ODEQ. The EPA may later request that WRC enter into a global settlement which, if WRC agreed to do so, would necessitate the payment of a civil penalty and the installation of additional controls.

        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 civil penalties and injunctive relief related to alleged non compliance with the Clean Air Act's Risk Management Program ("RMP") (in addition to other matters described below (see "— Environmental Remediation"). CRRM is currently in settlement negotiations with the EPA and anticipates that civil penalties associated with the proceeding will exceed $100,000; however, CRRM does not anticipate that civil penalties or any other costs associated with the proceeding will be material.

        The federal Clean Water Act and its implementing regulations, as well as the corresponding state laws and regulations that regulate the discharge of pollutants into the water, affect our petroleum operations and the nitrogen fertilizer business. Direct impacts occur through the federal Clean Water Act's permitting requirements, which establish discharge limitations based on technology standards, water quality standards, and restrictions on the total maximum daily load ("TMDL") of pollutants that may be released to a particular water body based on its use. In addition, water resources are becoming and in the future may become more scarce, and many refiners, including Coffeyville and WRC, are

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subject to restrictions on their ability to use water in the event of low availability conditions. Both Coffeyville and WRC have contracts in place to receive additional water during low-flow conditions.

        The Wynnewood refinery's Clean Water Act permit ("OPDES permit") has expired and has not yet been re-issued by ODEQ. The refinery currently operates under a permit shield, which authorizes permittees to continue discharging under an expired permit until the ODEQ re-issues the permit. The permit renewal process has begun, and ODEQ has proposed modifications to Oklahoma's Water Quality Management Plan for the Wynnewood refinery, which are pending EPA approval. Capital costs or expenses, if any, related to changes to the permit are not expected to be material.

        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 OPDES 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, we do not believe that the costs of the potential corrective actions would be material.

        Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. For example, the nitrogen fertilizer facility periodically experiences minor releases of hazardous and extremely hazardous substances from our equipment. It experienced more significant releases in August 2007 due to the failure of a high pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. Such releases are reported to the EPA and relevant state and local agencies. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with risk reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act and the Emergency Planning and Community Right-to-Know Act and the Risk Management Planning under the federal Clean Air Act. If we fail to properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.

        The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. On February 24, 2010, we received a letter from the United States Department of Justice on behalf of the EPA seeking a $0.9 million penalty under the Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right to Know Act related to alleged late and incomplete reporting of air releases by CRRM that occurred between June 13, 2004 and April 10, 2008. We have entered into a tolling agreement relating to EPA's allegations and are currently in settlement discussions with the EPA. We anticipate that CRRM will be required to pay a penalty in excess of $100,000 in connection with these allegations, but do not anticipate that the penalty will be material. The penalty will be included in the global settlement, described above in "Business — Environmental Matters — The Federal Clean Air Act."

        Tier II, Low Sulfur Fuels.    In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in

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gasoline that were required to be met by 2006. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel fuel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. Our refineries are in compliance with the EPA's low sulfur gasoline and diesel fuel standards. The EPA is expected to propose "Tier 3" gasoline sulfur standards in March 2012. If the EPA were to propose a standard at the level recently being discussed in the pre-proposal phase by the EPA, CRRM will need to make modifications to its equipment in order to meet the anticipated new standard. The Wynnewood refinery would not appear to require additional capital to meet the anticipated new standard. We do not believe that costs associated with the EPA's proposed Tier 3 rule would be material.

        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 each are considered to be "small refiners" under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. The EPA has confirmed that the Wynnewood Acquisition will not affect the companies' "small refiner" status because the combination of two previously approved "small refiners" does not result in the loss of "small refiner" status. Capital expenditures to comply with the rule are expected to be approximately $10.0 million for CRRM and $20.5 million for WRC.

        In 2007, the EPA promulgated the Renewable Fuel Standard ("RFS"), which requires refiners to blend "renewable fuels" in with their 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. Thus, in 2011, about 8% of all fuel used will be "renewable fuel." In 2012, the renewable fuel percentage standard is about 9%. Beginning on January 1, 2011, CRRM was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs, in lieu of blending. For the year ended December 31, 2011, CRRM incurred approximately $19.0 million of expense associated with purchasing RINs and will need to purchase additional RINs for compliance for 2011, which was included in cost of product sold in the Consolidated Statements of Operations. CRRM requested additional time to comply in the form of "hardship relief" from the EPA based on the disproportionate economic impact of the rule on CRRM, but the EPA denied CRRM's request on February 17, 2012. CRRM may appeal the denial of its hardship petition. The Wynnewood refinery is a small refinery under the RFS and has received a two year extension of time to comply. Therefore, the Wynnewood refinery will have to begin complying with the RFS in 2013 unless a further extension is requested and granted.

        Various regulatory and legislative measures to address greenhouse gas emissions (including carbon dioxide ("CO2"), methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 "endangerment finding" that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the authority granted to it under the federal Clean Air Act

        In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting our greenhouse gas emissions and are reporting the emissions to the EPA. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new greenhouse gas emissions thresholds that determine when stationary sources, such as our refineries and

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the nitrogen fertilizer plant, must obtain permits under the Prevention of Significant Deterioration ("PSD") and Title V programs of the federal Clean Air Act. In cases where a new source is constructed or an existing source undergoes a major modification, the facility would need to evaluate and install best available control technology ("BACT") for its greenhouse gas emissions. Phase-in permit requirements began for the largest stationary sources in 2011. A major modification resulting in a significant expansion of production and a significant increase in greenhouse gas emissions at the nitrogen fertilizer plant or refineries may require the installation of BACT as part of the permitting process. The EPA is expected to revise certain existing New Source Performance Standards ("NSPS") applicable to refineries to include performance standards for greenhouse gas emissions. The revised regulations, under NSPS subpart J, are expected to be finalized by November 2012. We do not currently believe that any currently anticipated projects at the nitrogen fertilizer plant will result in a significant increase in greenhouse gas emissions triggering the need to install BACT controls. At the federal legislative level, Congressional passage of legislation adopting some form of federal mandatory greenhouse gas emission reduction, such as a nationwide cap-and-trade program, does not appear likely at this time, although it could be adopted at a future date. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.

        In addition to potential federal legislation, a number of states have adopted regional greenhouse gas initiatives to reduce CO2 and other greenhouse gas emissions. In 2007, a group of Midwestern states, including Kansas (where our Coffeyville refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control greenhouse gas emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is unclear whether Kansas still intends to do so.

        The implementation of EPA regulations will result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. Increased costs associated with compliance with any current or future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.

        In addition, climate change legislation and regulations may result in increased costs not only for our business but also users of our refined and fertilizer products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.

        Our operations are subject to the RCRA requirements for the generation, transportation, treatment, storage and disposal of solid and hazardous wastes. When feasible, RCRA-regulated materials are recycled instead of being disposed of on-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal practices, the recycling of wastes and the regulation of underground storage tanks containing regulated substances.

        Waste Management.    There are two closed hazardous waste units at the Coffeyville refinery and eight other hazardous waste units in the process of being closed pending state agency approval. There is one closed hazardous waste unit and one active hazardous waste storage tank at the Wynnewood refinery. In addition, one closed interim status hazardous waste land farm located at the now-closed Phillipsburg terminal is under long-term post closure care.

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        Impacts of Past Manufacturing.    The Coffeyville Consent Decree that we signed with the EPA and KDHE required us to assume two RCRA corrective action orders issued to Farmland. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and groundwater conditions, which require investigation or remediation projects. The now-closed Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. Remediation at both sites, if necessary, will be based on the results of the investigations. The Wynnewood refinery operates under a RCRA permit. A RCRA facility investigation has been completed in accordance with the terms of the permit. Based on the facility investigation and other available information, the ODEQ has required further investigations of groundwater conditions. Remediation, if necessary, will be based upon the results of further investigation.

        The anticipated investigation and remediation costs through 2015 were estimated, as of December 31, 2011, to be as follows:

Facility
  Site
Investigation
Costs 		  Capital
Costs 		  Total Operation &
Maintenance
Costs
Through 2015 		  Total
Estimated
Costs
Through 2015 		 
 
   (in millions)
  

Coffeyville Refinery

   $ 0.6   $ —   $ 0.7   $ 1.3  

Phillipsburg Terminal

     0.4     —     0.9     1.3  

Wynnewood Refinery

     0.3     —     0.4     0.7  
                   

Total Estimated Costs

   $ 1.3   $ —   $ 2.0   $ 3.3  
                   

        These estimates are based on current information and could go up or down as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2012, we will spend $4.0 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the now-closed Phillipsburg terminal and Wynnewood refinery. It is possible that additional costs will be required after this ten year period. We spent approximately $2.4 million in 2011 associated with related remediation.

        Financial Assurance.    We are required in the Consent Decree to establish financial assurance to secure the projected clean-up costs posed by the Coffeyville and the now-closed Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the Coffeyville Consent Decree as modified by a 2010 agreement between CRRM, CRT, the EPA and the KDHE, this financial assurance is currently provided by a bond in the amount of $5.0 million for clean-up obligations at the Phillipsburg terminal and additional self-funded financial assurance of approximately $1.7 million and $2.1 million for clean-up obligations at the Coffeyville refinery and Phillipsburg terminal, respectively. Current RCRA financial assurance requirements for the Wynnewood refinery total $0.3 million for hazardous waste storage tank closure and post-closure monitoring of a closed storm water retention pond.

        Under the Comprehensive Environmental Response, Compensation, and Liability Act ("CERCLA"), 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

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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 Oil Pollution Act of 1990 ("OPA") generally subjects owners and operators of facilities to strict, joint and several liability for all containment and cleanup costs, natural resource damages, and potential governmental oversight costs arising from oil spills into the waters of the United States. In connection with governmental oversight of our cleanup of the oil spill resulting from the June/July 2007 flood at our Coffeyville refinery, on October 25, 2010 the U.S. Coast Guard on behalf of the EPA is seeking to recover a civil penalty and 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 DOJ, acting on behalf of the EPA and the Coast Guard, filed suit against CRRM in the United States District Court for the District of Kansas seeking (i) recovery from CRRM of EPA's oversight costs, (ii) a civil penalty under the Clean Water Act (as amended by the OPA) and (iii) recovery from CRRM related to alleged non-compliance with the Clean Air Act's RMP. (See "The Federal Clean Air Act" above.) As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by crude oil or hazardous substances that we manufactured, handled, used, stored, transported, spilled, disposed of or released. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or crude oil or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material.

        We are covered by premises pollution liability insurance policies with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $5.0 million. The policies include business interruption coverage, subject to a 10-day waiting period deductible. This insurance expires on July 1, 2012. The policies insure specific covered locations, including our [refineries and the] nitrogen fertilizer facility. The policies insure (i) claims, remediation costs, and associated legal defense expenses for pollution conditions at or migrating from a covered location, and (ii) the transportation risks associated with moving waste from a covered location to any location for unloading or depositing waste. The policies cover any claim made during the policy period as long as the pollution conditions giving rise to the claim commenced on or after March 3, 2004. The premises pollution liability policies contain exclusions, conditions, and limitations that could apply to a particular pollution condition claim, and there can be no assurance such claim will be adequately insured for all potential damages.

        In addition to the premises pollution liability insurance policies, we benefit from casualty insurance policies having an aggregate and occurrence limit of $150.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. Coverage under the casualty insurance policies for pollution does not apply to damages at or within our insured premises. The pollution coverage provided in the casualty insurance policies contains exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.

Safety, Health and Security Matters

        We operate a comprehensive safety, health and security program, involving active participation of employees at all levels of the organization. We have developed comprehensive safety programs aimed at preventing recordable incidents. Despite our efforts to achieve excellence in our safety and health

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performance, there can be no assurances that there will not be accidents resulting in injuries or even fatalities. We routinely audit our programs and consider improvements in our management systems.

        The Wynnewood refinery has been the subject of a number of federal Occupational Safety and Health Act ("OSHA") inspections since 2006. As a result of these inspections, the Wynnewood refinery has entered into four OSHA settlement agreements in 2008, pursuant to which it has agreed to undertake certain studies, conduct abatement activities, and revise and enhance certain OSHA compliance programs. The costs associated with these studies, abatement activities and program revisions are expected to be approximately $9.3 million over the next five years.

        Process Safety Management.    We maintain a process safety management ("PSM") program. This program is designed to address all aspects of the OSHA guidelines for developing and maintaining a comprehensive PSM program. We will continue to audit our programs and consider improvements in our management systems and equipment.

        Emergency Planning and Response.    We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facilities. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.

Employees

        At December 31, 2011, 764 employees were employed by the petroleum business, 124 were employed by the nitrogen fertilizer business and 108 employees were employed by the Company at our offices in Sugar Land, Texas, Kansas City, Kansas and Oklahoma City, Oklahoma.

        At December 31, 2011, the Coffeyville refinery employed approximately 500 of the petroleum business employees, about 56% of whom were covered by a collective bargaining agreement. These employees are affiliated with six unions of the Metal Trades Department of the AFL-CIO ("Metal Trade Unions") and the United Steel, Paper and Forestry, Rubber, Manufacturing, Energy, Allied Industrial and Service Workers International Union, AFL-CIO-CLC ("United Steelworkers"). A new collective bargaining agreement, which covers union members who work directly at the Coffeyville refinery, was entered into with the Metal Trade Unions effective August 31, 2008 and is effective through March 2013. No substantial changes were made to the prior agreement. In addition, a new collective bargaining agreement, which covers the balance of the Company's unionized employees who work in the terminalling and related operations, was entered into with the United Steelworkers on March 3, 2009. The United Steelworkers collective bargaining agreement is effective through March 2012 and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. There were no substantial changes to the prior agreement.

        At December 31, 2011, the Wynnewood refinery employed approximately 270 people, about 65% of whom were represented by the International Union of Operating Engineers. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2012. We believe that our relationship with our employees is good.

Available Information

        Our website address is www.cvrenergy.com. Our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and all amendments to those reports, are available free of charge through our website under "Investor Relations," as soon as reasonably practicable after the electronic filing of these reports is made with the SEC. In addition, our Corporate Governance Guidelines, Codes of Ethics and Charters of the Audit Committee, the Nominating and Corporate

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Governance Committee and the Compensation Committee of the Board of Directors are available on our website. These guidelines, policies and charters are available in print without charge to any stockholder requesting them. Our SEC filings, including exhibits filed therewith, are also available at the SEC's website at www.sec.gov. You may obtain and copy any document we furnish or file with the SEC at the SEC's public reference room at 100 F Street, NE, Room 1580, Washington, D.C. 20549. You may obtain information on the operation of the SEC's public reference facilities by calling the SEC at 1-800-SEC-0330. You may request copies of these documents, upon payment of a duplicating fee, by writing to the SEC at its principal office at 100 F Street, NE, Room 1580, Washington, D.C. 20549.

Trademarks, Trade Names and Service Marks

        This Annual Report on Form 10-K for the year ended December 31, 2011 (the "Report") may include our and our affiliates' trademarks, including CVR Energy, the CVR Energy logo, Coffeyville Resources, the Coffeyville Resources logo, CVR Partners, LP and the CVR Partners, LP logo, each of which is registered with the United States Patent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.

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Item 1A.    Risk Factors

        You should carefully consider each of the following risks together with the other information contained in this Report and all of the information set forth in our filings with the SEC. If any of the following risks and uncertainties develops into actual events, our business, financial condition or results of operations could be materially adversely affected.


 Risks Related to the Petroleum Business

        Our petroleum business' financial results are primarily affected by the relationship, or margin, between refined product prices and the prices for crude oil and other feedstocks. When the margin between refined product prices and crude oil and other feedstock prices tightens, our earnings, profitability and cash flows are negatively affected. Refining margins historically have been volatile and are likely to continue to be volatile, as a result of a variety of factors including fluctuations in prices of crude oil, other feedstocks and refined products. Continued future volatility in refining industry margins may cause a decline in our results of operations, since the margin between refined product prices and feedstock prices may decrease below the amount needed for us to generate net cash flow sufficient for our needs. Although an increase or decrease in the price for crude oil generally results in a similar increase or decrease in prices for refined products, there is normally a time lag in the realization of the similar increase or decrease in prices for refined products. The effect of changes in crude oil prices on our results of operations therefore depends in part on how quickly and how fully refined product prices adjust to reflect these changes. A substantial or prolonged increase in crude oil prices without a corresponding increase in refined product prices, or a substantial or prolonged decrease in refined product prices without a corresponding decrease in crude oil prices, could have a significant negative impact on our earnings, results of operations and cash flows.

        Our profitability is also impacted by the ability to purchase crude oil at a discount to benchmark crude oils, such as WTI, as we do not produce any crude oil and must purchase all of the crude oil we refine. These crude oils include, but are not limited to, crude oil from our gathering system that we use at the Coffeyville refinery and crude oils that we purchase in support of the Wynnewood refinery. Crude oil differentials can fluctuate significantly based upon overall economic and crude oil market conditions. Declines in crude oil differentials can adversely impact refining margins, earnings and cash flows.

        Refining margins are also impacted by domestic and global refining capacity. Continued downturns in the economy impact the demand for refined fuels and, in turn, generate excess capacity. In addition, the expansion and construction of refineries domestically and globally can increase refined fuel production capacity. Excess capacity can adversely impact refining margins, earnings and cash flows.

        During 2011, favorable crack spreads and access to a variety of price advantaged crude oils have resulted in EBITDA and cash flow generation that is higher than usual. We cannot assure you that these favorable conditions will continue and, in fact, crack spreads, refining margins and crude oil prices could decline, possibly materially, at any time. In particular, this may be mitigated in the future as a result of Enbridge's purchase of 50% of the Seaway pipeline and intent to reverse the pipeline to make it flow from Cushing to the U.S. Gulf Coast. Any such decline would have a material adverse effect on our earnings, results of operations and cash flows. Volatile prices for natural gas and electricity also affect our manufacturing and operating costs. Natural gas and electricity prices have been, and will continue to be, affected by supply and demand for fuel and utility services in both local and regional markets.

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        Since December 31, 2009, we have obtained the majority of our crude oil supply for the Coffeyville refinery through a Supply Agreement with Vitol, which was entered into on March 30, 2011 to replace an existing supply agreement with Vitol. The Supply Agreement, whose initial term expires on December 31, 2013, minimizes the amount of in-transit inventory and mitigates crude oil pricing risks by ensuring pricing takes place extremely close to the time when the crude oil is refined and the yielded products are sold. If we were required to obtain our crude oil supply without the benefit of a supply intermediation agreement, our exposure to crude oil pricing risks may increase, despite any hedging activity in which we may engage, and our liquidity would be negatively impacted due to the increased inventory and the negative impact of market volatility.

        In addition, there is currently no crude oil supply intermediation agreement in place with respect to the Wynnewood refinery. We are, therefore, more exposed to crude oil pricing risks than we were prior to the Wynnewood Acquisition. Although we may choose to enter into such an agreement in the future, or seek to expand our existing crude oil supply intermediation agreement with Vitol to cover the Wynnewood refinery, there can be no assurance that we will be able to do so on commercially reasonable terms or at all.

        For the Coffeyville refinery, in addition to the crude oil we gather locally in Kansas, Oklahoma, Missouri, and Nebraska, we purchase an additional 80,000 to 90,000 bpd of crude oil to be refined into liquid fuels. Although the Wynnewood refinery has historically acquired most of its crude oil from Texas and Oklahoma, it also purchases crude oil from other regions. Coffeyville obtains a portion of its non-gathered crude oil, approximately 19% in 2011, from foreign sources and Wynnewood obtained a small amount from foreign sources as well. The majority of these foreign sourced crude oil barrels were derived from Canada. In addition to Canadian crude oil, we have access to crude oils from Latin America, South America, the Middle East, West Africa and the North Sea. The actual amount of foreign crude oil we purchase is dependent on market conditions and will vary from year to year. We are subject to the political, geographic, and economic risks attendant to doing business with suppliers located in those regions. Disruption of production in any of such regions for any reason could have a material impact on other regions and our business.

        In the event that one or more of our traditional suppliers becomes unavailable to us, we may be unable to obtain an adequate supply of crude oil, or we may only be able to obtain our crude oil supply at unfavorable prices. As a result, we may experience a reduction in our liquidity and our results of operations could be materially adversely affected.

        Severe weather, including hurricanes along the U.S. Gulf Coast, have in the past and could in the future interrupt our supply of crude oil. Supplies of crude oil to our refinery are periodically shipped from U.S. Gulf Coast production or terminal facilities. U.S. Gulf Coast facilities could be subject to damage or production interruption from hurricanes or other severe weather in the future which could interrupt or materially adversely affect our crude oil supply. If our supply of crude oil is interrupted, our business, financial condition and results of operations could be materially adversely impacted.

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        If one of the pipelines on which either of the Coffeyville or Wynnewood refineries relies for supply of crude oil becomes inoperative, we would be required to obtain crude oil through alternative pipelines or from additional tanker trucks, which could increase our costs and result in lower production levels and profitability. Similarly, if a major refined fuels pipeline becomes inoperative, we would be required to keep refined fuels in inventory or supply refined fuels to our customers through an alternative pipeline or by additional tanker trucks, which could increase our costs and result in a decline in profitability.

        Pursuant to the Energy Independence and Security Act of 2007, the U.S. Environmental Protection Agency, or the EPA, has promulgated the Renewable Fuel Standard, or RFS, which requires refiners to blend "renewable fuels," such as ethanol, with their petroleum fuels or purchase renewable energy credits, known as renewable identification numbers, or RINs, in lieu of blending. Annually, the EPA establishes the volume of renewable fuels that refineries must blend into their finished petroleum fuels. Beginning in 2011, our Coffeyville refinery was required to blend renewable fuels into its gasoline and diesel fuel or purchase RINs in lieu of blending. We have requested additional time to comply in the form of "hardship relief" from the EPA based on the disproportionate impact of the rule on our Coffeyville refinery, but the EPA denied our request. The Wynnewood refinery is a small refinery under the RFS and has received a two year extension of time to comply. If we are unable to pass the costs of compliance with RFS on to our customers, our profits would be significantly lower. Moreover, if sufficient RINs are unavailable for purchase or if we have to pay a significantly higher price for RINs, if our "hardship relief" request is denied, or if we are otherwise unable to meet the EPA's RFS mandates, our business, financial condition and results of operations could be materially adversely affected.

        Demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third quarters. Further, reduced agricultural work during the winter months somewhat depresses demand for diesel fuel in the winter months. In addition to the overall seasonality of the petroleum business, unseasonably cool weather in the summer months and/or unseasonably warm weather in the winter months in the areas in which we sell our petroleum products could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce operating margins.

        The refining industry is highly competitive with respect to both feedstock supply and refined product markets. We may be unable to compete effectively with our competitors within and outside of our industry, which could result in reduced profitability. We compete with numerous other companies

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for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore we do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon others for outlets for our refined products. We do not have any long-term arrangements (those exceeding more than a twelve-month period) for much of our output. Many of our competitors obtain significant portions of their feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages.

        A number of our competitors also have materially greater financial and other resources than us. These competitors may have a greater ability to bear the economic risks inherent in all aspects of the refining industry. An expansion or upgrade of our 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 and may add additional competitive pressure on us.

        In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental incentives or regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the negative impact on pricing and demand for our products and our profitability. There are presently significant governmental incentives and consumer pressures to increase the use of alternative fuels in the United States.

        Changes in our credit profile may affect the way crude oil suppliers view our ability to make payments and may induce them to shorten the payment terms for our purchases or require us to post security prior to payment. Given the large dollar amounts and volume of our crude oil and other feedstock purchases, a burdensome change in payment terms may have a material adverse effect on our liquidity and our ability to make payments to our suppliers. This, in turn, could cause us to be unable to operate our refineries at full capacity. A failure to operate our refineries at full capacity could adversely affect our profitability and cash flows.

        The U.S. Congress has adopted the Dodd-Frank Act, comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market, and requires the Commodities Futures Trading Commission ("CFTC") to institute broad new position limits for futures and options traded on regulated exchanges. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations implementing the new legislation. The rulemaking process is still ongoing, and we cannot predict the ultimate outcome of the rulemakings. New regulations in this area may result in increased costs and cash collateral for derivative instruments we may use to hedge and otherwise manage our financial risks related to volatility in oil and gas commodity prices.

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 Risks Related to the Nitrogen Fertilizer Business

        The nitrogen fertilizer business is exposed to fluctuations in nitrogen fertilizer demand in the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices across all nitrogen fertilizer products and, in turn, our results of operations, financial condition and cash flows.

        Nitrogen fertilizer products are commodities, the price of which can be highly volatile. The prices of nitrogen fertilizer products depend on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which the nitrogen fertilizer business bases production, customers may acquire nitrogen fertilizer products from competitors, and the profitability of the nitrogen fertilizer business will be negatively impacted. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory that will have to be stored or liquidated.

        Demand for nitrogen fertilizer products is dependent on demand for crop nutrients by the global agricultural industry. Nitrogen-based fertilizers are currently in high demand, driven by a growing world population, changes in dietary habits and an expanded use of corn for the production of ethanol. Supply is affected by available capacity and operating rates, raw material costs, government policies and global trade. A decrease in nitrogen fertilizer prices would have a material adverse effect on our results of operations, financial condition and cash flows.

        Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, the nitrogen fertilizer business has largely fixed costs that are not dependent on the price of natural gas because it uses pet coke as the primary feedstock in the nitrogen fertilizer plant. As a result of the fixed cost nature of our operations, downtime, interruptions or low productivity due to reduced demand, adverse weather conditions, equipment failure, a decrease in nitrogen fertilizer prices or other causes can result in significant operating losses could have a material adverse effect on our results of operations, financial condition and cash flows.

        Most nitrogen fertilizer manufacturers rely on natural gas as their primary feedstock, and the cost of natural gas is a large component of the total production cost for natural gas-based nitrogen fertilizer manufacturers. The dramatic increase in nitrogen fertilizer prices in recent years has not been the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to historically low stocks of global grains and a surge in the prices of corn and wheat, the primary crops in the nitrogen fertilizer business' region. This increase in demand for nitrogen-based fertilizers has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation with natural gas prices. A decrease in natural gas prices would benefit the nitrogen fertilizer business' competitors and could disproportionately impact our operations by making the nitrogen fertilizer business less competitive with natural gas-based nitrogen

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fertilizer manufacturers. A decline in natural gas prices could impair the nitrogen fertilizer business' ability to compete with other nitrogen fertilizer producers who utilize natural gas as their primary feedstock, and therefore have a material adverse impact on the cash flows of the nitrogen fertilizer business. In addition, if natural gas prices in the United States were to decline to a level that prompts those U.S. producers who have permanently or temporarily closed production facilities to resume fertilizer production, this would likely contribute to a global supply/demand imbalance that could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on our results of operations, financial condition and cash flows.

        Conditions in the U.S. agricultural industry significantly impact the operating results of the nitrogen fertilizer business. The U.S. agricultural industry can be affected by a number of factors, including weather patterns and field conditions, current and projected grain inventories and prices, domestic and international population changes and demand for U.S. agricultural products and U.S. and foreign policies regarding trade in agricultural products.

        State and federal governmental policies, including farm and biofuel subsidies and commodity support programs, as well as the prices of fertilizer products, may also directly or indirectly influence the number of acres planted, the mix of crops planted and the use of fertilizers for particular agricultural applications. Developments in crop technology, such as nitrogen fixation (the conversion of atmospheric nitrogen into compounds that plants can assimilate), could also reduce the use of chemical fertilizers and adversely affect the demand for nitrogen fertilizer. In addition, from time to time various state legislatures have considered limitations on the use and application of chemical fertilizers due to concerns about the impact of these products on the environment. Unfavorable state and federal governmental policies could negatively affect nitrogen fertilizer prices and therefore have a material adverse effect on our results of operations, financial condition and cash flows.

        A major factor underlying the current high level of demand for nitrogen-based fertilizer products produced by the nitrogen fertilizer business is the expanding production of ethanol in the United States and the expanded use of corn in ethanol production. Ethanol production in the United States is highly dependent upon a myriad of federal and state legislation and regulations, and is made significantly more competitive by various federal and state incentives, mandated production of ethanol pursuant to federal renewable fuel standards, and permitted increases in ethanol percentages in gasoline blends, such as E15, a gasoline blend with 15% ethanol. However, a number of factors, including a continuing "food versus fuel" debate and studies showing that expanded ethanol production may increase the level of greenhouse gases in the environment, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports and adopt temporary waivers of the current renewable fuel standard levels, any of which could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand. Therefore, ethanol incentive programs may not be renewed, or if renewed, they may be renewed on terms significantly less favorable to ethanol producers than current incentive programs. For example, on December 31, 2011, Congress allowed both the 45 cents per gallon ethanol tax credit and the 54 cents per gallon ethanol import tariff to expire. Similarly, the EPA's waivers partially approving the use of E15 could be revised, rescinded or delayed. These actions could have a material

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adverse effect on ethanol production in the United States, which could have a material adverse effect on our results of operations, financial condition and cash flows.

        Further, most ethanol is currently produced from corn and other raw grains, such as milo or sorghum — especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste and energy crops (plants grown for use to make biofuels or directly exploited for their energy content). If an efficient method of producing ethanol from cellulose-based biomass is developed, the demand for corn may decrease significantly, which could reduce demand for nitrogen fertilizer products and have a material adverse effect on our results of operations, financial condition and cash flows.

        The nitrogen fertilizer business is subject to intense price competition from both U.S. and foreign sources, including competitors operating in the Persian Gulf, the Asia-Pacific region, the Caribbean, Russia and the Ukraine. Fertilizers are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. Furthermore, in recent years the price of nitrogen fertilizer in the United States has been substantially driven by pricing in the global fertilizer market. The nitrogen fertilizer business competes with a number of U.S. producers and producers in other countries, including state-owned and government-subsidized entities. Some competitors have greater total resources and are less dependent on earnings from fertilizer sales, which makes them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. The nitrogen fertilizer business' competitive position could suffer to the extent it is not able to expand its resources either through investments in new or existing operations or through acquisitions, joint ventures or partnerships, or otherwise compete successfully in the global nitrogen fertilizer market. An inability to compete successfully could result in a loss of customers, which could adversely affect the sales, profitability and the cash flows of the nitrogen fertilizer business and therefore have a material adverse effect on our results of operations, financial condition and cash flows.

        The nitrogen fertilizer business is seasonal. Farmers tend to apply nitrogen fertilizer during two short application periods, one in the spring and the other in the fall. The strongest demand for nitrogen fertilizer products typically occurs during the planting season. In contrast, the nitrogen fertilizer business and other nitrogen fertilizer producers generally produce products throughout the year. As a result, the nitrogen fertilizer business and its customers generally build inventories during the low demand periods of the year in order to ensure timely product availability during the peak sales seasons. The seasonality of nitrogen fertilizer demand results in sales volumes and net sales being highest during the North American spring season and working capital requirements typically being highest just prior to the start of the spring season.

        If seasonal demand exceeds projections, the nitrogen fertilizer business will not have enough product and its customers may acquire products from its competitors, which would negatively impact profitability. If seasonal demand is less than expected, the nitrogen fertilizer business will be left with excess inventory and higher working capital and liquidity requirements.

        The degree of seasonality of the nitrogen fertilizer business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of such

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seasonality, it is expected that the distributions we receive from the nitrogen fertilizer business will be volatile and will vary quarterly and annually.

        The nitrogen fertilizer business' sales to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. The nitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. For example, the nitrogen fertilizer business generates greater net sales and operating income in the first half of the year, which is referred to herein as the planting season, compared to the second half of the year. Accordingly, an adverse weather pattern affecting agriculture in these regions or during the planting season could have a negative effect on fertilizer demand, which could, in turn, result in a material decline in the nitrogen fertilizer business' net sales and margins and otherwise have a material adverse effect on our results of operations, financial condition and cash flows. The nitrogen fertilizer business' quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. As a result, it is expected that the nitrogen fertilizer business' distributions to holders of its common units (including us) will be volatile and will vary quarterly and annually.

        The operations of the nitrogen fertilizer business depend in large part on the performance of third party suppliers, including Linde for the supply of oxygen, nitrogen and compressed dry air, and the City of Coffeyville for the supply of electricity. With respect to Linde, operations could be adversely affected if there were a deterioration in Linde's financial condition such that the operation of the air separation plant located adjacent to the nitrogen fertilizer plant was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in gasifier operations. With respect to electricity, the nitrogen fertilizer business recently settled litigation with the City of Coffeyville regarding the price they sought to charge the nitrogen fertilizer business for electricity and entered into an amended and restated electric services agreement which gives the nitrogen fertilizer business an option to extend the term of such agreement through June 30, 2024. Should Linde, the City of Coffeyville or any of its other third party suppliers fail to perform in accordance with existing contractual arrangements, operations could be forced to halt. Alternative sources of supply could be difficult to obtain. Any shutdown of operations at the nitrogen fertilizer plant, even for a limited period, could have a material adverse effect on our results of operations, financial condition and cash flows.

        The profitability of the nitrogen fertilizer business is directly affected by the price and availability of pet coke obtained from our Coffeyville refinery pursuant to a long-term agreement and pet coke purchased from third parties (with respect to which we have no contractual arrangements), both of which vary based on market prices. Pet coke is a key raw material used by the nitrogen fertilizer business in the manufacture of nitrogen fertilizer products. If pet coke costs increase, the nitrogen

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fertilizer business may not be able to increase its prices to recover these increased costs, because market prices for nitrogen fertilizer products are not correlated with pet coke prices.

        The nitrogen fertilizer business may not be able to maintain an adequate supply of pet coke. In addition, it could experience production delays or cost increases if alternative sources of supply prove to be more expensive or difficult to obtain. The nitrogen fertilizer business currently purchases 100% of the pet coke the Coffeyville refinery produces. Accordingly, if the nitrogen fertilizer business increases production, it will be more dependent on pet coke purchases from third party suppliers at open market prices. There is no assurance that the nitrogen fertilizer business would be able to purchase pet coke on comparable terms from third parties or at all.

        The nitrogen fertilizer business relies on railroad and trucking companies to ship finished products to its customers. The nitrogen fertilizer business also leases railcars from railcar owners in order to ship its finished products. These transportation operations, equipment and services are subject to various hazards, including extreme weather conditions, work stoppages, delays, spills, derailments and other accidents and other operating hazards.

        These transportation operations, equipment and services are also subject to environmental, safety and other regulatory oversight. Due to concerns related to terrorism or accidents, local, state and federal governments could implement new regulations affecting the transportation of the nitrogen fertilizer business' finished products. In addition, new regulations could be implemented affecting the equipment used to ship its finished products.

        Any delay in the nitrogen fertilizer business' ability to ship its finished products as a result of these transportation companies' failure to operate properly, the implementation of new and more stringent regulatory requirements affecting transportation operations or equipment, or significant increases in the cost of these services or equipment could have a material adverse effect on our results of operations, financial condition and cash flows.

        The nitrogen fertilizer business' results of operations are highly dependent upon business and economic conditions and governmental policies affecting the agricultural industry, which we cannot control. The agricultural products business can be affected by a number of factors. The most important of these factors in the United States are:

        International market conditions, which are also outside of the nitrogen fertilizer business' control, may also significantly influence its operating results. The international market for nitrogen fertilizers is

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influenced by such factors as the relative value of the U.S. dollar and its impact upon the cost of importing nitrogen fertilizers, foreign agricultural policies, the existence of, or changes in, import or foreign currency exchange barriers in certain foreign markets, changes in the hard currency demands of certain countries and other regulatory policies of foreign governments, as well as the laws and policies of the United States affecting foreign trade and investment.

        The nitrogen fertilizer business manufactures, processes, stores, handles, distributes and transports ammonia, which can be very volatile and extremely hazardous. Major accidents or releases involving ammonia could cause severe damage or injury to property, the environment and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits, fines, penalties and regulatory enforcement proceedings, all of which could lead to significant liabilities. Any damage to persons, equipment or property or other disruption of the ability of the nitrogen fertilizer business to produce or distribute its products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure its assets, which could have a material adverse effect on our results of operations, financial condition and cash flows. The nitrogen fertilizer facility periodically experiences minor releases of ammonia related to leaks from its equipment. It experienced more significant ammonia releases in August 2007 due to the failure of a high-pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. Similar events may occur in the future and could have a material adverse effect on our results of operations, financial condition and cash flows.

        In addition, the nitrogen fertilizer business may incur significant losses or costs relating to the operation of railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially toxic nature of the cargo, in particular ammonia, on board railcars, a railcar accident may result in fires, explosions and pollution. These circumstances may result in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, the nitrogen fertilizer business may be held responsible even if it is not at fault and it complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving ammonia and other products we produce or transport may result in the nitrogen fertilizer business or us being named as a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on our results of operations, financial condition and cash flows.

        Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is most typically transported by pipeline and railcar. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. In addition, in the future, laws may more severely restrict or eliminate the ability of the nitrogen fertilizer business to transport ammonia via railcar. If any railcar design changes are implemented, or if accidents involving hazardous freight increase the insurance and other costs of railcars, freight costs of the nitrogen fertilizer business could significantly increase.

        Future environmental laws and regulations on the end-use and application of fertilizers could cause changes in demand for the nitrogen fertilizer business' products. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit the ability of the nitrogen fertilizer business to market and sell its products to end users. From time to time, various

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state legislatures have proposed bans or other limitations on fertilizer products. In addition, a number of states have adopted or proposed numeric nutrient water quality criteria that could result in decreased demand for fertilizer products in those states. Similarly, a new final rule of the EPA establishing numeric nutrient criteria for certain Florida water bodies may require farmers to implement best management practices, including the reduction of fertilizer use, to reduce the impact of fertilizer on water quality. The rule has been challenged and may be replaced with a state rule imposing similar numeric nutrient criteria. Such laws, regulations or interpretations could have a material adverse effect on our results of operations, financial condition and cash flows.

        The nitrogen fertilizer business has licensed, and may in the future license, a combination of patent, trade secret and other intellectual property rights of third parties for use in its business. In particular, the gasification process it uses to convert pet coke to high purity hydrogen for subsequent conversion to ammonia is licensed from General Electric. The license, which is fully paid, grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions and is integral to the operations of the nitrogen fertilizer facility. If this license or any other license agreements on which the nitrogen fertilizer business' operations rely, were to be terminated, licenses to alternative technology may not be available, or may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently-licensed technology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on our results of operations, financial condition and cash flows.

        Although there are currently no pending claims relating to the infringement of any third party intellectual property rights, in the future the nitrogen fertilizer business may face claims of infringement that could interfere with its ability to use technology that is material to its business operations. Any litigation of this type, whether successful or unsuccessful, could result in substantial costs and diversions of resources, which could have a material adverse effect on our results of operations, financial condition and cash flows. In the event a claim of infringement against the nitrogen fertilizer business is successful, it may be required to pay royalties or license fees for past or continued use of the infringing technology, or it may be prohibited from using the infringing technology altogether. If it is prohibited from using any technology as a result of such a claim, it may not be able to obtain licenses to alternative technology adequate to substitute for the technology it can no longer use, or licenses for such alternative technology may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently licensed technology may require the nitrogen fertilizer business to make substantial changes to its manufacturing processes or equipment or to its products, and could have a material adverse effect on our results of operations, financial condition and cash flows.

        The nitrogen fertilizer plant is located within the U.S. farm belt, where the majority of the end users of its nitrogen fertilizer products grow their crops. Many of its competitors produce fertilizer outside of this region and incur greater costs in transporting their products over longer distances via rail, ships and pipelines. There can be no assurance that competitors' transportation costs will not decline or that additional pipelines will not be built, lowering the price at which competitors can sell their products, which would have a material adverse effect on our results of operations, financial condition and cash flows.

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Risks Related to Our Entire Business

        The global capital and credit markets experienced extreme volatility and disruption in recent years. Our business, financial condition and results of operations could be negatively impacted by difficult conditions and extreme volatility in the capital, credit and commodities markets and in the global economy. These factors, combined with volatile oil prices, declining business and consumer confidence and increased unemployment, precipitated an economic recession in the United States and globally. The difficult conditions in these markets and the overall economy affect us in a number of ways. For example:

        Our operations are subject to significant operating hazards and interruptions. If any of our facilities, including our Coffeyville or Wynnewood refineries or the nitrogen fertilizer plant, experiences a major accident or fire, is damaged by severe weather, flooding or other natural disaster, or is otherwise forced to significantly curtail its operations or shut down, we could incur significant losses which could have a material adverse effect on our results of operations, financial condition and cash flows. Conducting the majority of our refining operations and all of our fertilizer manufacturing at a single location compounds such risks.

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        Operations at either or both of our refineries and the nitrogen fertilizer plant could be curtailed or partially or completely shut down, temporarily or permanently, as the result of a number of circumstances, most of which are not within our control, such as:

        The magnitude of the effect on us of any shutdown will depend on the length of the shutdown and the extent of the plant operations affected by the shutdown. Our refineries require a planned maintenance turnaround every four to five years for each unit, and the nitrogen fertilizer plant requires a planned maintenance turnaround every two years. A major accident, fire, flood, or other event could damage our facilities or the environment and the surrounding community or result in injuries or loss of life. For example, the flood that occurred during the weekend of June 30, 2007 shut down our Coffeyville refinery for seven weeks, shut down the nitrogen fertilizer facility for approximately two weeks and required significant expenditures to repair damaged equipment. In addition, the nitrogen fertilizer business' UAN plant was out of service for approximately six weeks after the rupture of a high pressure vessel in September 2010 which required significant expenditures to repair. Our Coffeyville refinery experienced an equipment malfunction and small fire in connection with its fluid catalytic cracking unit on December 28, 2010, which led to reduced crude oil throughput for approximately one month and required significant expenditures to repair. Similarly, the Wynnewood refinery experienced a small explosion and fire in its hydrocracker process unit due to metal failure in December 2010. Scheduled and unscheduled maintenance could reduce our net income and cash flows during the period of time that any of our units is not operating. Any unscheduled future downtime could have a material adverse effect on our results of operations, financial condition and cash flows.

        If we experience significant property damage, business interruption, environmental claims or other liabilities, our business could be materially adversely affected to the extent the damages or claims exceed the amount of valid and collectible insurance available to us. Our property and business interruption insurance policies (that cover the Coffeyville refinery and nitrogen fertilizer plant) have a $1.0 billion limit, with a $2.5 million deductible for physical damage and a 45- to 60-day waiting period (depending on the insurance carrier) before losses resulting from business interruptions are recoverable. We are fully exposed to all losses in excess of the applicable limits and sub-limits and for losses due to business interruptions of fewer than 45 to 60 days. Our Wynnewood refinery is covered by separate property and business interruption insurance policies with an $800.0 million limit, with a $10.0 million deductible for physical damage and a 75-day waiting period. The policies also contain exclusions and conditions that could have a materially adverse impact on our ability to receive indemnification thereunder, as well as customary sub-limits for particular types of losses. For example, the Company's current property policy for the Coffeyville refinery and nitrogen fertilizer plant contains a specific sub-limit of $150.0 million for damage caused by flooding.

        The energy and nitrogen fertilizer industries are highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry participants, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of premium costs and deductible periods for participants in the energy industry. For example, during 2005, Hurricanes Katrina and Rita caused significant damage to several petroleum refineries along the U.S. Gulf Coast, in addition to numerous oil and gas production facilities and pipelines in that region. As a result of large energy industry insurance claims, insurance companies that

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have historically participated in underwriting energy related facilities could discontinue that practice or demand significantly higher premiums or deductibles to cover these facilities. Although we currently maintain significant amounts of insurance, insurance policies are subject to annual renewal. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost or we might need to significantly increase our retained exposures.

        Our operations are subject to a variety of federal, state and local environmental laws and regulations relating to the protection of the environment, including those governing the emission or discharge of pollutants into the environment, product specifications and the generation, treatment, storage, transportation, disposal and remediation of solid and hazardous waste and materials. Violations of these laws and regulations or permit conditions can result in substantial penalties, injunctive orders compelling installation of additional controls, civil and criminal sanctions, permit revocations and/or facility shutdowns.

        In addition, new environmental laws and regulations, new interpretations of existing laws and regulations, increased governmental enforcement of laws and regulations or other developments could require us to make additional unforeseen expenditures. Many of these laws and regulations are becoming increasingly stringent, and the cost of compliance with these requirements can be expected to increase over time. The requirements to be met, as well as the technology and length of time available to meet those requirements, continue to develop and change. These expenditures or costs for environmental compliance could have a material adverse effect on our results of operations, financial condition and profitability.

        Our facilities operate under a number of federal and state permits, licenses and approvals with terms and conditions containing a significant number of prescriptive limits and performance standards in order to operate. Our facilities are also required to comply with prescriptive limits and meet performance standards specific to refining and/or chemical facilities as well as to general manufacturing facilities. All of these permits, licenses, approvals and standards require a significant amount of monitoring, record keeping and reporting in order to demonstrate compliance with the underlying permit, license, approval or standard. Incomplete documentation of compliance status may result in the imposition of fines, penalties and injunctive relief. Additionally, due to the nature of our manufacturing and refining processes, there may be times when we are unable to meet the standards and terms and conditions of these permits and licenses due to operational upsets or malfunctions, which may lead to the imposition of fines and penalties or operating restrictions that may have a material adverse effect on our ability to operate our facilities and accordingly our financial performance.

        Our businesses are subject to the occurrence of accidental spills, discharges or other releases of petroleum or hazardous substances into the environment. Past or future spills related to any of our current or former operations, including our refineries, pipelines, product terminals, fertilizer plant or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), and similar state statutes for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we

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transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal.

        The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, we may incur liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for cleanup costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.

        In March 2004, Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Terminal, LLC entered into a Consent Decree (the "Coffeyville Consent Decree") with the EPA and the Kansas Department of Health and Environment (the "KDHE") to address certain allegations of Clean Air Act violations by Farmland (the prior owner) at our Coffeyville refinery and now-closed Phillipsburg terminal facility in order to address the alleged violations and eliminate liabilities going forward. The remaining costs of complying with the Coffeyville Consent Decree are expected to be approximately $49 million, which does not include the cleanup obligations for historic contamination at the site that are being addressed pursuant to administrative orders issued under the Resource Conservation and Recovery Act, (the "RCRA"), and described in Item 1 "Business — Environmental Matters — RCRA — Impacts of Past Manufacturing." To date, we have materially complied with the Consent Decree and have not had to pay any stipulated penalties, which are required to be paid for failure to comply with various terms and conditions of the Coffeyville Consent Decree. As described in "Business — Environmental Matters — The Federal Clean Air Act," we and the EPA agreed to extend the refinery's deadline under the Coffeyville Consent Decree to install certain air pollution controls on its FCCU to reduce emissions of sulfur-dioxide and nitrogen oxides due to delays caused by the June/July 2007 flood (the "15-month extension agreement"). Pursuant to the 15-month extension agreement, we agreed to offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe. We have been negotiating with the EPA and KDHE to replace the current Coffeyville Consent Decree, including the fifteen month extension, with a global settlement under the national Petroleum Refining Initiative.

        Under the new Consent Decree we would receive additional time to install controls required under the Coffeyville Consent Decree in consideration for agreeing to pay a civil penalty and install other controls and enhance certain compliance programs. The new Consent Decree is awaiting final EPA approval after which it will be lodged with the court and subject to a public notice and comment period before it is finalized.

        The WRC entered into the Wynnewood Consent Order with the ODEQ in August 2011 addressing some, but not all of the traditional marquee issues under the EPA's National Petroleum Refining Initiative and addressing certain historic Clean Air Act compliance issues that are generally beyond the scope of a traditional global settlement. Under the Wynnewood Consent Order, WRC agreed to pay a civil penalty, install certain controls, enhance certain compliance programs, and undertake additional testing and auditing. The costs of complying with the Wynnewood Consent Order, other than costs associated with a planned turnaround, are expected to be approximately $1.5 million. A number of factors could affect our ability to meet the requirements imposed by either the Coffeyville Consent Decree or the Wynnewood Consent Order and could have a material adverse effect on our results of operations, financial condition and cash flows.

        Three of our facilities, including our Coffeyville refinery, the now-closed Phillipsburg terminal (which operated as a refinery until 1991), and the Wynnewood refinery have environmental

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contamination. We have assumed Farmland's responsibilities under certain RCRA administrative orders related to contamination at or that originated from the Coffeyville refinery (which includes portions of the nitrogen fertilizer plant) and the Phillipsburg terminal. The Wynnewood refinery is required to conduct investigations to address potential off-site migration of contaminants from the west side of the property. Other known areas of contamination at the Wynnewood refinery have been partially addressed but corrective action has not been completed, and portions of the Wynnewood refinery have not yet been investigated to determine whether corrective action is necessary. If significant unknown liabilities are identified at any of our facilities, that liability could have a material adverse effect on our results of operations, financial condition and cash flows and may not be covered by insurance.

        We may incur future costs relating to the off-site disposal of hazardous wastes. Companies that dispose of, or arrange for the transportation or disposal of, hazardous substances at off-site locations may be held jointly and severally liable for the costs of investigation and remediation of contamination at those off-site locations, regardless of fault. We could become involved in litigation or other proceedings involving off-site waste disposal and the damages or costs in any such proceedings could be material.

        We recently received a notice from certain funds affiliated with Carl Icahn disclosing their intent to nominate nine individuals for election to our board of directors. In addition, on February 23, 2012, certain funds affiliated with Carl Icahn commenced a tender offer for control of the Company with the intention, following completion of such tender offer, to seek to sell us to a strategic acquirer.

        We could be adversely affected by these events because, among other things:

        We hold numerous environmental and other governmental permits and approvals authorizing operations at our facilities. Future expansion of our operations is also predicated upon securing the necessary environmental or other permits or approvals. A decision by a government agency to deny or delay issuing a new or renewed material permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on our ability to continue operations and on our financial condition, results of operations and cash flows.

        Various regulatory and legislative measures to address greenhouse gas emissions (including CO2 , methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 "endangerment finding" that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the authority granted to it under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of

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greenhouse gases to inventory and annually report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring our greenhouse gas emissions and have already reported the emissions to the EPA for the year ended 2011. In May 2010, the EPA finalized the "Greenhouse Gas Tailoring Rule," which established new greenhouse gas emissions thresholds that determine when stationary sources, such as the refineries and the nitrogen fertilizer plant, must obtain permits under Prevention of Significant Deterioration ("PSD"), and Title V programs of the federal Clean Air Act. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the facility would need to evaluate and install best available control technology ("BACT"), to control greenhouse gas emissions. A major modification resulting in a significant expansion of production at the nitrogen fertilizer plant that causes a significant increase in greenhouse gas emissions could require the installation of BACT controls. However, we do not believe that our ongoing or anticipated expansion projects would trigger the need to install BACT controls. The EPA's endangerment finding, Greenhouse Gas Tailoring Rule and certain other greenhouse gas emission rules have been challenged and will likely be subject to extensive litigation. In the meantime, in December 2010, the EPA reached a settlement agreement with numerous parties under which it agreed to promulgate final decisions on New Source Performance Standards for petroleum refineries by November 2012.

        At the federal legislative level, Congressional passage of legislation adopting some form of federal mandatory greenhouse gas emission reduction, such as a nationwide cap-and-trade program, does not appear likely at this time, although it could be adopted at a future date. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.

        In addition to potential federal legislation, a number of states have adopted regional greenhouse gas initiatives to reduce CO2 and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas (where our Coffeyville refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control greenhouse gas emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is unclear whether Kansas still intends to do so.

        The implementation of EPA greenhouse gas regulations or potential federal, state or regional programs to reduce greenhouse gas emissions will result in increased costs to (i) operate and maintain our facilities, (ii) install new emission controls on our facilities and (iii) administer and manage any greenhouse gas emissions program. Increased costs associated with compliance with any future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and cash flows.

        In addition, climate change legislation and regulations may result in increased costs not only for our business but also for users of our refined and fertilizer products, thereby potentially decreasing demand for our products. Decreased demand for our products may have a material adverse effect on our results of operations, financial condition and cash flows.

        In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise

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our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.

        We are subject to the requirements of the federal Occupational Safety and Health Act ("OSHA") and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with these requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, may result in significant fines or compliance costs, which could have a material adverse effect on our results of operations, financial condition and cash flows.

        Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and cash flows.

        The petroleum and nitrogen fertilizer businesses both have a high concentration of customers. The five largest customers of the Coffeyville refinery represented 50% of our petroleum sales for the year ended December 31, 2011, and the five largest customers of the Wynnewood refinery represented approximately 37% of GWEC's sales for the year ended December 31, 2011. Further in the aggregate, the top five ammonia customers of the nitrogen fertilizer business represented approximately 61% of its ammonia sales for the year ended December 31, 2011 and the top five UAN customers of the nitrogen fertilizer business represented approximately 49% of its UAN sales for the same period. Several significant petroleum, ammonia and UAN customers each account for more than 10% of sales of petroleum, ammonia and UAN, respectively. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of our customers. The loss of one or several of these significant customers, or a significant reduction in purchase volume by any of them, could have a material adverse effect on our results of operations, financial condition and cash flows.

        Both our petroleum business and the nitrogen fertilizer business will consider pursuing acquisitions and expansion projects in order to continue to grow and increase profitability. However, acquisitions and expansions involve numerous risks and uncertainties, including intense competition for suitable

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acquisition targets, the potential unavailability of financial resources necessary to consummate acquisitions and expansions, difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms and the need to obtain regulatory or other governmental approvals that may be necessary to complete acquisitions and expansions. In addition, any future acquisitions and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business.

        The nitrogen fertilizer business is in the process of expanding its nitrogen fertilizer plant, which is expected to allow it the flexibility to upgrade all of its ammonia production to UAN. This expansion is premised in large part on the historically higher margin that UAN has received compared to ammonia. If the premium that UAN currently earns over ammonia decreases, this expansion project may not yield the economic benefits and accretive effects that are currently anticipated.

        In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:

        In addition, in connection with any potential acquisition or expansion project involving the nitrogen fertilizer business, the nitrogen fertilizer business will need to consider whether the business it intends to acquire or expansion project it intends to pursue could affect the nitrogen fertilizer business' tax treatment as a partnership for federal income tax purposes. If the nitrogen fertilizer business is otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect the Partnership's treatment as a partnership for federal income tax purposes, the nitrogen fertilizer business may elect to seek a ruling from the Internal Revenue Service ("IRS"). Seeking such a ruling could be costly or, in the case of competitive acquisitions, place the nitrogen fertilizer business in a competitive disadvantage compared to other potential acquirers who do not seek such a ruling. If the nitrogen fertilizer business is unable to conclude that an activity would not affect its treatment as a partnership for federal income tax purposes, and is unable or unwilling to obtain an IRS ruling, the nitrogen fertilizer business may choose to acquire such business or develop such expansion project in a corporate subsidiary, which would subject the income related to such activity to entity-level taxation, which would reduce the amount of cash available for distribution to the unitholders and would likely cause a substantial reduction in the value of the nitrogen fertilizer business common units.

        Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and cash flows. There can be no assurance that

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we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.

        We are a holding company, and our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay dividends or make other distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, distributions, tax sharing payments or otherwise. In addition, CRLLC, our indirect subsidiary, which is the primary obligor under our ABL credit facility and the issuer of our first lien and second lien secured notes, is a holding company, and its ability to meet its debt service obligations depends on the cash flow of its subsidiaries (including the distributions the Partnership makes on its common units, 70% of which are owned directly by CRLLC). The ability of our subsidiaries (including the Partnership) to make any payments to us will depend on their earnings, the terms of their indebtedness, tax considerations and legal restrictions. In particular, the Partnership's credit facility requires that, before the Partnership can make distributions to us, it must be in compliance with leverage ratio and interest coverage ratio tests.

        If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations. As of December 31, 2011, we had cash and cash equivalents of $388.3 million and $313.9 million available under our ABL Credit Facility (net of $86.1 million of outstanding letters of credit). Crude oil price volatility can significantly impact working capital on a week-to-week and month-to-month basis.

        As of December 31, 2011, approximately 56% of the employees at the Coffeyville refinery and 65% of the employees at the Wynnewood refinery were represented by labor unions under collective bargaining agreements. At Coffeyville, the collective bargaining agreement with six Metal Trades Unions (which covers union members who work directly at the Coffeyville refinery) is effective through March 2013, and the collective bargaining agreement with United Steelworkers (which covers the balance of the Company's unionized employees, who work in the terminalling and related operations) is effective through March 2012, and automatically renews on an annual basis thereafter unless a written notice is received sixty days in advance of the relevant expiration date. The collective bargaining agreement with the International Union of Operating Engineers with respect to the Wynnewood refinery expires in June 2012. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations, financial condition and cash flows.

        Our future success depends to a large extent on the services of our key senior executives and key senior employees. Our business depends on our continuing ability to recruit, train and retain highly

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qualified employees in all areas of our operations, including accounting, business operations, finance and other key back-office and mid-office personnel. Furthermore, our operations require skilled and experienced employees with proficiency in multiple tasks. In particular, the nitrogen fertilizer facility relies on gasification technology that requires special expertise to operate efficiently and effectively. The competition for these employees is intense, and the loss of these executives or employees could harm our business. If any of these executives or other key personnel resign or become unable to continue in their present roles and are not adequately replaced, our business operations could be materially adversely affected. We do not maintain any "key man" life insurance for any executives.

        The costs of complying with future regulations relating to the transportation of hazardous chemicals and security associated with the refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and cash flows. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and cash flows.

        Shareholders of the Company may from time to time engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over the Company. Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting the Company's operations and diverting the attention of the Company's Board of Directors and senior management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect the Company's results of operations, financial condition and cash flows.

        We are subject to extensive tax liabilities, including United States and state income taxes and transactional taxes such as excise, sales/use, payroll, franchise and withholding taxes. New tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future.

        As of December 31, 2011, we had outstanding $447.1 million of first lien notes, $222.8 million of second lien notes, and $86.1 million of issued but undrawn letters of credit (leaving borrowing availability of $313.9 million under the ABL Credit Facility), and the Partnership, our consolidated subsidiary that operates the nitrogen fertilizer plant, had $125.0 million in outstanding term loan borrowings and borrowing availability of $25.0 million under its revolving credit facility.

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        We and our subsidiaries may be able to incur significant additional indebtedness in the future. If new indebtedness is added to our current indebtedness, the risks described below could increase. Our indebtedness could have important consequences, such as:

        In addition, borrowings under the ABL Credit Facility and the Partnership's credit facility bear interest at variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect our cash flow.

        Furthermore, changes in our credit ratings may affect the way crude oil and feedstock suppliers view our ability to make payments and may induce them to shorten the payment terms of their invoices. Given the large dollar amounts and volume of our feedstock purchases, a change in payment terms may have a material adverse effect on the amount of our liabilities and our ability to make payments to our suppliers.

        In addition to our debt service obligations, our operations require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors.

        In addition, we are and will be subject to covenants contained in agreements governing our present and future indebtedness. These covenants include, and will likely include, restrictions on certain payments, the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under the indentures governing our secured notes, ABL Credit Facility and the Partnership's credit facility. Upon a default, unless waived, the holders of our notes and the lenders under the ABL Credit Facility and the Partnership's credit facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our or our

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subsidiaries' assets, and force us and our subsidiaries into bankruptcy or liquidation, subject to the intercreditor agreements. In addition, any defaults could trigger cross defaults under other or future credit agreements or indentures. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.

        Our ability to satisfy our debt obligations will depend upon, among other things:

        We cannot offer any assurance that our businesses will generate sufficient cash flow from operations, or that we will be able to draw under the ABL Credit Facility, or that the Partnership will be able to draw under its revolving credit facility, or from other sources of financing, in an amount sufficient to fund our liquidity needs. In addition, our board of directors may in the future elect to pay a special or regular dividend, engage in share repurchases or pursue other strategic options including acquisitions of other business or asset purchases, which would reduce cash available to service our debt obligations.

        If our cash flows and capital resources are insufficient to service our indebtedness, we may be forced to reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations, and the terms of existing or future debt agreements may restrict us from adopting some of these alternatives. In addition, in the absence of adequate cash flows or capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations, or sell equity, in order to meet our debt service and other obligations. We may not be able to consummate those dispositions for fair market value or at all. The ABL Credit Facility, the Partnership's credit facility and the indentures governing our notes may restrict, or market or business conditions may limit, our ability to avail ourselves of some or all of these options. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations when due. Neither the Company's shareholders nor any of their respective affiliates has any continuing obligation to provide us with debt or equity financing.

        The borrowings under the ABL Credit Facility and the Partnership's credit facility bear interest at variable rates and other debt we incur could likewise be variable-rate debt. If market interest rates increase, variable-rate debt will create higher debt service requirements, which could adversely affect our cash flow. While we may enter into agreements limiting our exposure to higher interest rates, any such agreements may not offer complete protection from this risk.

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        The ABL Credit Facility and the indentures governing our other debt contain, and any instruments governing future indebtedness of ours would likely contain, a number of covenants that will impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries' ability to, among other things:

        Any of these restrictions could limit our ability to plan for or react to market conditions and could otherwise restrict corporate activities. Any failure to comply with these covenants could result in a default under the ABL Credit Facility the Partnership's credit facility and the indentures governing the notes. Upon a default, unless waived, the holders of our notes and the lenders under the ABL Credit Facility and the Partnership's credit facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our assets, and force us into bankruptcy or liquidation, subject to the intercreditor agreements. In addition, a default under the ABL Credit Facility or the indentures governing the notes would trigger a cross default under our other agreements and could trigger a cross default under the agreements governing our future indebtedness. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.

        We and the Partnership may be able to incur substantially more debt in the future, including secured indebtedness. Although the ABL Credit Facility and the indentures governing our other debt contain restrictions on our incurrence of additional indebtedness, and the Partnership's credit facility contains restrictions on its incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. In particular, we can incur additional indebtedness so long as our fixed charge coverage ratio (as defined in the indentures) exceeds 2:1. Also, these restrictions may not prevent us from incurring obligations that do not constitute indebtedness. To the extent such new debt or new obligations are added to our existing indebtedness, the risks described above could substantially increase.

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        Under our ABL Credit Facility, a change of control would be triggered if a third party became the beneficial owner of 35.0% or more of our voting stock, and may result upon certain changes in the composition of our board (including if the majority of our board of directors were to consist of individuals who were not (i) members of our board in February 2011 or (ii) nominated for election by directors the majority of whom were directors in February 2011 or whose election or nomination was previously approved by a majority of such directors). A change in control would result in an event of default under our ABL Credit Facility, which would allow our lenders to accelerate indebtedness owed to them.

        Under the indentures governing our notes, in the event of a change in control (which would be triggered if a third party became the beneficial owner of 50.0% or more of our voting stock and may be triggered on the first day where a majority of the board does not consist of directors who were directors in April 2010 or nominated for election or elected by directors the majority of whom were directors in April 2010 or whose election or nomination was previously approved by a majority of such directors), we may be required to offer to purchase all of our outstanding notes at 101% of their original aggregate principal amount, plus accrued interest to the date of repurchase.

        If a specified change in control occurs and the lenders under our debt instruments accelerate these obligations, we may not have sufficient liquid assets to repay amounts outstanding under these agreements.


Risks Related to Our Common Stock

        Various provisions of our certificate of incorporation and bylaws and of Delaware corporate law may discourage, delay or prevent a change in control or takeover attempt of our company by a third party that our management and board of directors determines is not in the best interest of our Company and its stockholders. Public stockholders who might desire to participate in such a transaction may not have the opportunity to do so. These anti-takeover provisions could substantially impede the ability of public stockholders to benefit from a change of control or change in our management and board of directors. These provisions include:

        We have also approved a stockholders' rights agreement (the "Rights Agreement") between the Company and American Stock Transfer & Trust Company, LLC, as Rights Agent. Pursuant to the Rights Agreement, holders of our common stock are entitled to purchase one one-thousandth (1/1,000) of a share (a "Unit") of Series A Preferred Stock at a price of $100.00 per Unit upon certain events. The purchase price is subject to appropriate adjustment for stock splits and other similar events. Generally, in the event a person or entity acquires, or initiates a tender offer to acquire, at least 15%

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of the Company's then-outstanding common stock, the Rights will become exercisable for common stock having a value equal to two times the exercise price of the Right, or effectively at one-half of the Company's then-current stock price. The existence of the Rights Plan may discourage, delay or prevent a change of control or takeover attempt of our company by a third party that our management and board of directors determines is not in the best interest of our Company and its stockholders.

        We believe that it is necessary to maintain a sufficient number of available authorized shares of our Common Stock and Preferred Stock in order to provide us with the flexibility to issue Common Stock or Preferred Stock for business purposes that may arise as deemed advisable by our board of directors. These purposes could include, among other things, (i) to declare future stock dividends or stock splits, which may increase the liquidity of our shares; (ii) the sale of stock to obtain additional capital or to acquire other companies or businesses, which could enhance our growth strategy or allow us to reduce debt if needed; (iii) for use in additional stock incentive programs and (iv) for other bona fide purposes. Our board of directors may issue the available authorized shares of Common Stock or Preferred Stock without notice to, or further action by, our stockholders, unless stockholder approval is required by law or the rules of the New York Stock Exchange. The issuance of additional shares of Common Stock or Preferred Stock may significantly dilute the equity ownership of the current holders of our Common Stock.


Risks Related to the Limited Partnership Structure Through Which
We Currently Hold Our Interest in the Nitrogen Fertilizer Business

        The current policy of the board of directors of the Partnership's general partner is to distribute all of the available cash the Partnership generates on a quarterly basis to its unitholders. As a result, the Partnership's general partner will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund acquisitions and expansion capital expenditures at the nitrogen fertilizer business. As a result, to the extent it is unable to finance growth externally, the Partnership's cash distribution policy will significantly impair its ability to grow. As of December 31, 2011, we owned approximately 70% of the Partnership's outstanding common units, and public unitholders owned the remaining 30% of the Partnership's common units.

        In addition, because the current policy of the board of directors of the Partnership's general partner is to distribute all of the available cash the Partnership generates each quarter, growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent the Partnership issues additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units will decrease the amount the Partnership distributes on each outstanding unit. There are no limitations in the partnership agreement on the Partnership's ability to issue additional units, including units ranking senior to the common units that we own. The incurrence of additional commercial borrowings or other debt to finance the Partnership's growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that the Partnership has to distribute to unitholders, including us.

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        The Partnership may not have sufficient available cash each quarter to pay any distributions to its common unitholders, including us. Furthermore, the partnership agreement does not require it to pay distributions on a quarterly basis or otherwise. Although the current policy of the board of directors of the Partnership's general partner is to distribute all available cash the Partnership generates each quarter, the board may at any time, for any reason, change this policy or decide not to make any distribution. The amount of cash the Partnership will be able to distribute on its common units principally depends on the amount of cash it generates from operations, which is directly dependent upon operating margins, which have been volatile historically. Operating margins at the nitrogen fertilizer business are significantly affected by the market-driven UAN and ammonia prices it is able to charge customers and pet coke-based gasification production costs, as well as seasonality, weather conditions, governmental regulation, unplanned maintenance or downtime at the nitrogen fertilizer plant and global and domestic demand for nitrogen fertilizer products, among other factors. In addition:

        During 2011, and in each taxable year thereafter, current law requires the Partnership to derive at least 90% of its annual gross income from certain specified activities in order to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. The Partnership may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement. If the Partnership were to be treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on all of its taxable income at the corporate tax rate, which is currently a maximum of 35%, it would likely pay additional state and local income taxes at varying rates, and distributions to the Partnership's common unitholders, including to us, would generally be taxed as corporate distributions.

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        In addition, current U.S. federal income tax treatment of publicly traded partnerships, including the Partnership, may be modified at any time by legislation, administrative rulings or judicial authority. Any such change may cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject the Partnership to entity-level taxation. For example, members of Congress have considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for the Partnership to be treated as a partnership for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted.

        If the Partnership were to be treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if the Partnership were otherwise subject to entity-level taxation, the Partnership's cash available for distribution to its common unitholders, including to us, and the value of the Partnership's common units, including the common units held by us, could be substantially reduced.

        We expect that the price of the Partnership's common units will be impacted by the level of the Partnership's quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in the Partnership's common units, and a rising interest rate environment could have a material adverse impact on the price of the Partnership's common units (and therefore the value of our investment in the Partnership) as well as the Partnership's ability to issue additional equity to make acquisitions or to incur debt.

        Under certain circumstances, we may, as a holder of common units in the Partnership, have to repay amounts wrongfully returned or distributed to us. Under the Delaware Revised Uniform Limited Partnership Act, the Partnership may not make a distribution to unitholders if the distribution would cause its liabilities to exceed the fair value of its assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the company for the distribution amount.

        As a result of the Partnership IPO, public investors own approximately 30% of the Partnership's common units. We are no longer entitled to receive all of the cash generated by the nitrogen fertilizer business or freely borrow money from the nitrogen fertilizer business to finance operations at the refinery, as we have in the past. Furthermore, although we own the Partnership's general partner and continue to own the majority of the Partnership's common units, the Partnership's general partner is subject to certain fiduciary duties, which may require the general partner to manage the nitrogen fertilizer business in a way that may differ from our best interests.

        On February 13, 2012, we announced our intention to sell a portion of our investment in the Partnership and use the proceeds to pay a special dividend to holders of our common stock. There can be no assurance as to the terms, conditions, amount or timing of such sale or dividend, or whether such

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sale or dividend will take place at all. This announcement does not constitute an offer of any securities for sale and is being made in accordance with Rule 135 under the Securities Act.

        The Company and the Partnership have entered into an agreement in order to clarify and structure the division of corporate opportunities. Under this agreement, the Company has agreed not to engage in the production, transportation or distribution, on a wholesale basis, of fertilizers in the contiguous United States, subject to limited exceptions (fertilizer restricted business) without the consent of the Partnership's general partner.

        The Partnership is managed by the executive officers of its general partner, some of whom are employed by and serve as part of the senior management team of the Company. Furthermore, although the Partnership has entered into a services agreement with the Company under which it compensates the Company for the services of its management, the Company's management is not required to devote any specific amount of time to the nitrogen fertilizer business and may devote a substantial majority of their time to the business of the Company. Moreover, after April 13, 2012, the Company will be able to terminate the services agreement at any time, subject to a 180-day notice period. In addition, key executive officers of the Company, including its chief operating officer, chief financial officer and general counsel, will face conflicts of interest if decisions arise in which the Partnership and the Company have conflicting points of view or interests.

        The Partnership's partnership agreement contains provisions that restrict the remedies available to its unitholders, including the Company, for actions that might otherwise constitute breaches of fiduciary duty. For example, the partnership agreement:

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        With respect to the common units that we own, we have agreed to become bound by the provisions in our partnership agreement, including the provisions discussed above.

        Under the Partnership's partnership agreement, the Partnership is authorized to issue an unlimited number of additional interests without a vote of the unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

        In addition, the Partnership's partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units that we own.

        The nitrogen fertilizer business is in the process of evaluating its internal controls systems to allow management to report on, and our independent auditors to audit, its internal control over financial reporting. It will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, and under current rules will be required to comply with Section 404 for the year ended December 31, 2012. Upon completion of this process, the nitrogen fertilizer business may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board ("PCAOB") rules and regulations that remain unremediated. Although the nitrogen fertilizer business produces financial statements in accordance with U.S. Generally Accepted Accounting Principles ("GAAP"), internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. As a publicly traded partnership, it will be required to report, among other things, control deficiencies that constitute a "material weakness" or changes in internal controls that, or that are reasonably likely to, materially affect internal control over financial reporting. A "material weakness" is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

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        If the nitrogen fertilizer business fails to implement the requirements of Section 404 in a timely manner, it might be subject to sanctions or investigation by regulatory authorities such as the SEC. If it does not implement improvements to its disclosure controls and procedures or to its internal controls in a timely manner, its independent registered public accounting firm may not be able to certify as to the effectiveness of its internal control over financial reporting pursuant to an audit of its internal control over financial reporting. This may subject the nitrogen fertilizer business to adverse regulatory consequences or a loss of confidence in the reliability of its financial statements. It could also suffer a loss of confidence in the reliability of its financial statements if its independent registered public accounting firm reports a material weakness in its internal controls, if it does not develop and maintain effective controls and procedures or if it is otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of its financial statements or other negative reaction to its failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of its common units, which would reduce the value of our investment in the nitrogen fertilizer business. In addition, if the nitrogen fertilizer business fails to remedy any material weakness, its financial statements may be inaccurate, it may face restricted access to the capital markets and the price of its common units may be adversely affected, which would reduce the value of our investment in the nitrogen fertilizer business.


Risks Related to the Wynnewood Acquisition

        As a result of the Wynnewood Acquisition, we doubled our number of refineries from one to two and increased our refining throughput capacity by over 50%. The ultimate success of the Wynnewood Acquisition will depend, in large part, on our ability to successfully expand the scale and geographic scope of our operations across state lines and to realize the anticipated benefits, including synergies, cost savings, innovation and operational efficiencies, from combining the businesses of the Company and GWEC. To realize these anticipated benefits, the business of GWEC must be successfully integrated into the Company. This integration will be complex and time-consuming.

        The failure to integrate successfully and to manage successfully the challenges presented by the integration process may result in the combined company not achieving the anticipated benefits of the merger. Potential difficulties that may be encountered in the integration process include the following:

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        Even if the Company is able to successfully integrate the business operations of GWEC, there can be no assurance that this integration will result in the realization of the full benefits of the expected synergies, cost savings, innovation and operational efficiencies or that these benefits will be achieved within the anticipated time frame.

        Following the Wynnewood Acquisition, the size of the Company's business increased significantly and our existing management and operational infrastructure is responsible for operating two refineries located in different states. The combined company's future success depends, in part, upon its ability to manage this expanded business, which will pose substantial challenges for management, including challenges related to the management and monitoring of new operations and associated increased costs and complexity. There can be no assurances that the combined company will be successful or that it will realize the expected operating efficiencies, cost savings, revenue enhancements and other benefits currently anticipated from the Wynnewood Acquisition.

        The Company has incurred and is expected to continue to incur substantial expenses in connection with the Wynnewood Acquisition and the integration of GWEC. There are a large number of processes, policies, procedures, operations, technologies and systems that must be integrated, including purchasing, accounting and finance, sales, billing, payroll, pricing, revenue management, maintenance, marketing and benefits. While the Company has assumed that a certain level of expenses would be incurred, there are many factors beyond its control that could affect the total amount or the timing of the integration expenses. Moreover, many of the expenses that will be incurred are, by their nature, difficult to estimate accurately. These expenses could, particularly in the near term, exceed the savings that the combined company expects to achieve from the elimination of duplicative expenses and the realization of economies of scale and cost savings. These integration expenses likely will result in the combined company taking significant charges against earnings following the completion of the Wynnewood Acquisition, and the amount and timing of such charges are uncertain at present.

        The Company and GWEC are dependent on the experience and industry knowledge of their officers and other key employees to execute their business plans. The combined company's success after the merger depends in part upon the ability of the Company and GWEC to retain key management personnel and other key employees. Current and prospective employees of the Company and GWEC employees may experience uncertainty about their roles within the combined company following the Wynnewood Acquisition, which may have an adverse effect on the ability of each of the Company and GWEC to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees of the Company and GWEC to the same extent that the Company and GWEC previously were able to attract or retain their own employees.

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        Since 1996, GWEC has been party to a contract (renewed annually) with the United States government to sell jet fuel to Mid-Continent Air Force bases. This contract accounted for 3% of GWEC's fuel sales in 2011. U.S. government contracts contain provisions and are subject to laws and regulations that provide the government with rights and remedies not typically found in commercial contracts. In the event that GWEC is found to have violated certain laws or regulations, GWEC could be subject to penalties and sanctions, including, in the most serious cases, potential suspension or debarment from conducting future business with the U.S. government. As a result of the need to comply with these laws and regulations, GWEC could also be subject to increased risks of governmental investigations, civil fraud actions, criminal prosecutions, whistleblower law suits and other enforcement actions. By way of example, civil False Claims Act actions could subject us to treble penalties, and we could be subject to fines of up to $12,000 for each claim submitted to the U.S. government.

        U.S. government contracts are subject to modification, curtailment or termination by the U.S. government with little notice, either for convenience or for default as a result of GWEC's failure to perform under the applicable contract. If the U.S. government terminates this contract as a result of GWEC's default, GWEC could be liable for additional costs the U.S. government incurs in acquiring undelivered goods or services from another source and any other damages it suffers. [Additionally, GWEC cannot assign prime U.S. government contracts without the prior consent of the U.S. government contracting officer, and GWEC is required to register with the Central Contractor Registration Database.

        There can be no assurance that we will maintain this jet fuel contract with the United States Government in the future.

        The Wynnewood refinery may have unexpected deficiencies and/or we may become responsible for unexpected liabilities that we failed or were unable to discover in the course of performing due diligence in connection with the Wynnewood Acquisition. The acquisition agreement entered into in connection with the Wynnewood Acquisition requires the seller to indemnify us under certain circumstances. However our rights to indemnification are limited and we cannot assure you that the indemnification, even if obtained, will be enforceable, collectible or sufficient in amount, scope or duration to fully cover a valid claim and/or offset the possible liabilities associated with the business or property acquired. The indemnification provisions in the acquisition agreement related to the Wynnewood Acquisition may also be difficult to enforce. Any of these liabilities, individually or in the aggregate, could have a material adverse effect on our business, financial condition and results of operations.

Item 1B.    Unresolved Staff Comments

        None.

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Item 2.    Properties

        The following table contains certain information regarding our principal properties:

Location
  Acres   Own/Lease   Use

Coffeyville, KS

     440   Own   Coffeyville Resources: oil refinery and office buildings
Partnership: fertilizer plant

Wynnewood, OK

     400   Own   Oil refinery, office buildings, refined oil storage

Phillipsburg, KS

     200   Own   UAN storage

Montgomery County, KS (Coffeyville Station)

     20   Own   Crude oil storage

Montgomery County, KS (Broome Station)

     20   Own   Crude oil storage

Bartlesville, OK

     25   Own   Truck storage and office buildings

Winfield, KS

     5   Own   Truck storage

Cowley County, KS (Hooser Station)

     80   Own   Crude oil storage

Holdrege, NE

     7   Own   Crude oil storage

Stockton, KS

     6   Own   Crude oil storage

        We also lease property for our executive office which is located at 2277 Plaza Drive in Sugar Land, Texas. Additionally, other corporate office space is leased in Kansas City, Kansas and Oklahoma City, Oklahoma.

        As of December 31, 2011, we had crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our Coffeyville refinery, 0.5 million barrels of crude oil storage at Wynnewood, Oklahoma and lease an additional 3.3 million barrels of storage capacity located at Cushing, Oklahoma and other locations (with an additional 1.0 million barrels of company-owned storage tanks in Cushing under construction, which are expected to be completed in the first quarter of 2012). In addition to crude oil storage, we own approximately 4.5 million barrels of combined refinery related storage capacity.

Item 3.    Legal Proceedings

        We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described under "Business — Environmental Matters." We also incorporate by reference into this Part I, Item 3, the information regarding the lawsuits and proceedings described and referenced in Note 17, "Commitments and Contingencies" to our Consolidated Financial Statements as set forth in Part II, Item 7. In accordance with U.S. GAAP, we record a liability when it is both probable that a liability has been incurred and the amount of the loss 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. Although we cannot predict with certainty the ultimate resolution of lawsuits, investigations or claims asserted against us, we do not believe that any currently pending legal proceeding or proceedings to which we are a party will have a material adverse effect on our business, financial condition or results of operations.

        The nitrogen fertilizer plant received a ten year property tax abatement from Montgomery County, Kansas in connection with its construction that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed the nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment has resulted in an increase to annual property tax liability for the plant by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, and approximately $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. The Partnership does not agree with the county's classification of the nitrogen fertilizer plant and is currently disputing it before the Kansas Court of Tax Appeals ("COTA").

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However, the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008 have been fully accrued and paid. The first payment in respect of the 2011 property taxes was paid in December 2011 and the second payment will be made in May 2012. This property tax expense is reflected as a direct operating expense in the nitrogen fertilizer business' financial results. In January 2012, COTA issued a ruling indicating that the assessment in 2008 of the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. We disagree with the ruling and filed a petition for reconsideration with COTA (which was denied) and plan to file an appeal to the Kansas Court of Appeals. We are also protesting the valuation of the nitrogen fertilizer plant for tax years 2009 - 2011, which cases remain pending before COTA. If we are successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid expenses would be refunded, which could have a material positive effect on our results of operations. If we are not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then we expect to continue to pay property taxes at elevated rates.

Item 4.    Mine Safety Disclosures

        None.

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PART II

Item 5.    Market For Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

Market Information

        Our common stock is listed on the NYSE under the symbol "CVI" and commenced trading on October 23, 2007. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common stock:

2011:
  High   Low  

First Quarter

   $ 23.18   $ 14.55  

Second Quarter

     25.03     18.30  

Third Quarter

     29.61     19.20  

Fourth Quarter

     27.95     16.62  

 

2010:
  High   Low  

First Quarter

   $ 9.60   $ 7.10  

Second Quarter

     9.41     6.89  

Third Quarter

     8.34     6.71  

Fourth Quarter

     15.35     7.89  

Holders of Record

        As of February 22, 2012, there were 349 stockholders of record of our common stock. Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

Dividend Policy

        On February 13, 2012, we announced that our board of directors approved a regular quarterly cash dividend of $0.08 per common share. We will pay our first dividend following the end of the first quarter of 2012 on a date to be set by our board of directors. Our board of directors also announced its intention to sell a portion of our investment in the Partnership with the proceeds to be used to pay for a special dividend to our shareholders as well as to strengthen our balance sheet. There can be no assurance as to the terms, conditions, amount or timing of such sale or dividend, or whether such sale or dividend will take place at all. This announcement does not constitute an offer of any securities for sale and is being made in accordance with Rule 135 under the Securities Act.

        The covenants contained in the Indentures governing the Notes and our ABL credit facility limit the ability of our subsidiaries to pay dividends to us, which limits our ability to pay dividends to our stockholders, including any amounts received from the Partnership in the form of quarterly distributions. Our ability to pay dividends also may be limited by covenants contained in the instruments governing indebtedness that we or our subsidiaries may incur in the future.

        The Partnership's credit facility also requires pro forma compliance with certain financial covenants before it can make distributions to holders of its units, including us. In addition, the partnership agreement which governs the Partnership includes restrictions on the Partnership's ability to make distributions to us.

Partnership Cash Distribution Policy

        The current policy of the board of directors of the Partnership's general partner is to distribute all available cash the Partnership generates each quarter. Available cash for each quarter is determined by

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the board of directors of the general partner following the end of such quarter. The Partnership expects that available cash for each quarter will generally equal the cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of the general partner deems necessary or appropriate. Additionally, the Partnership also retains the cash on hand associated with prepaid sales at each quarter end, which is recorded on the balance sheet as deferred revenue, for future distributions to common unitholders as it is recognized into income. The Partnership does not intend to maintain excess distribution coverage for the purpose of maintaining stability or growth in its quarterly distribution or otherwise to reserve cash for distributions, nor does the Partnership intend to incur debt to pay quarterly distributions. As of the dates of this Report, we own approximately 70% of the Partnership's common units, and are entitled to a pro rata percentage of the Partnership's distributions in respect of its common units. On February 13, 2012, we announced our intention to sell a portion of our investment in the Partnership and use the proceeds to pay a special dividend to holders of our common stock and to strengthen our balance sheet. There can be no assurance as to the terms, conditions, amount or timing of such sale or dividend, or whether such sale or dividend will take place at all. This announcement does not constitute an offer of any securities for sale and is being made in accordance with Rule 135 under the Securities Act.

        The Partnership intends to pay the distributions on or about the 15th day of each February, May, August and November to holders of record on or about the 1st day of each such month.

        On August 12, 2011, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on August 5, 2011 for the second quarter of 2011 (calculated for the period beginning April 13, 2011 through June 30, 2011) in the amount of $0.407 per unit or $29.7 million in aggregate. We received $20.7 million in respect of our common units.

        On November 14, 2011, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on November 7, 2011 for the third quarter of 2011 in the amount of $0.572 per unit or $41.8 million in aggregate. We received $29.1 million in respect of our common units.

        On February 14, 2012, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on February 7, 2012 for the fourth quarter of 2011 in the amount of $0.588 per unit, or $42.9 million in aggregate. We received $29.9 million in respect of our common units.

        There were no cash distributions paid in 2010 and 2009 as the Partnership IPO did not occur until 2011.

Stock Performance Graph

        The following graph sets forth the cumulative return on our common stock between October 23, 2007, the date on which our stock commenced trading on the NYSE, and December 31, 2011, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Alon USA Energy, Inc., Delek US Holdings, Inc., HollyFrontier Corporation, Tesoro Corporation, Valero Energy Corporation and Western Refining, Inc. The graph assumes an investment of $100 on October 23, 2007 in our common stock, the Russell 2000 Index and the industry peer group, and assumes the reinvestment of dividends where applicable. The closing market price for our common

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stock on December 30, 2011 was $18.73. The stock price performance shown on the graph is not intended to forecast and does not necessarily indicate future price performance.


COMPARISON OF CUMULATIVE TOTAL RETURN
BETWEEN OCTOBER 23, 2007 AND DECEMBER 31, 2011
among CVR Energy, Inc., Russell 2000 Index and a peer group

CHART

        This performance graph shall not be deemed "filed" for purposes of Section 18 of the Exchange Act or otherwise subject to the liabilities under that Section, and shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended (the "Securities Act"), or the Exchange Act.

 
   Oct '07   Dec '07   Mar '08   Jun '08   Sep '08   Dec '08   Mar '09   Jun '09   Sep '09   Dec '09  

CVR Energy, Inc. 

     100.00     123.16     113.73     95.06     42.07     19.75     27.36     36.20     61.43     33.88  

Russell 2000 Index

     100.00     93.59     84.05     84.26     83.02     61.02     51.65     62.10     73.83     76.40  

Peer Group

     100.00     85.40     56.42     44.78     38.96     26.84     34.98     28.32     31.59     26.91  

 

 
   Mar '10   Jun '10   Sep '10   Dec '10   Mar '11   Jun '11   Sep '11   Dec '11    
    
  

CVR Energy, Inc. 

     43.21     37.14     40.74     74.96     114.37     121.58     104.40     92.49              

Russell 2000 Index

     82.91     74.46     82.60     95.74     103.06     101.09     78.70     90.52              

Peer Group

     29.48     27.38     28.06     37.79     60.10     61.30     44.46     47.04              

Purchases of Equity Securities by the Issuer

        The table below sets forth information regarding repurchases of our common stock during the fiscal quarter ended December 31, 2011. The shares repurchased represent shares of our common stock that employees and directors elected to surrender to the Company to satisfy certain minimum tax withholding and other tax obligations upon the vesting of shares of non-vested stock. The repurchased shares are now held by us as treasury stock or have been issued out of treasury stock for purposes of

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delivering shares to recipients of share-based compensation awards that have vested. The Company does not consider this to be a share buyback program.

Period
  Total Number of
Shares Purchased 		  Average Price
Paid per Share 		  Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs 		  Maximum Number (or
Approximate Dollar
Value) of Shares that
May Yet Be Purchased
Under the
Plans or Programs 		 

October 1, 2011 to October 31, 2011

     —     —     —     —  

November 1, 2011 to November 30, 2011

     662   $ 25.75     —     —  

December 1, 2011 to December 31, 2011

     94,459   $ 18.64     —     —  
                   

Total

     95,121   $ 18.69     —     —  
                   

Equity Compensation Plans

        The table below contains information about securities authorized for issuance under our long-term incentive plan as of December 31, 2011. This plan was approved by our stockholders in October 2007.

Equity Compensation Plan Information  
Plan Category
  Number of
Securities to be
Issued Upon
Exercise of
Outstanding Options
Warrants and Rights(a) 		  Weighted-Average
Exercise Price of
Outstanding Options
Warrants and Rights(b) 		  Number of
Securities
Remaining Available
for Future Issuance
Under Equity
Compensation Plans
(Excluding Securities
Reflected in (a)) (c) 		 

Equity compensation plans approved by security holders:

                    

CVR Energy, Inc. Long-Term Incentive Plan

                 5,176,087 (4)

Stock Options

     22,900 (1) $ 18.03        

Common stock

     1,634,154 (2)    — (3)      

Equity compensation plans not approved by security holders:

                    

None

     —     —     —  
               

Total

     1,657,054   $ 18.03     5,176,087  
(1)
Represents shares of common stock to be issued upon the exercise of outstanding options granted pursuant to the CVR Energy, Inc. 2007 Long-Term Incentive Plan.

(2)
Represents shares of common stock awarded under the CVR Energy, Inc. 2007 Long-Term Incentive Plan that are payable in stock.

(3)
Common stock awards do not have an exercise price. Payout is based on completing a specified period of employment.

(4)
Represents shares of common stock that remain available for future issuance pursuant to the CVR Energy, Inc. 2007 Long-Term Incentive Plan in connection with awards of stock options, non-vested common stock, stock appreciation rights, dividend equivalent rights, share awards and performance awards. As of December 31, 2011, 2,409,154 shares of non-vested common stock had been granted under this plan, of which 9,531 shares have been forfeited and 1,634,154 remain unvested.

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Item 6.    Selected Financial Data

        You should read the selected historical consolidated financial data presented below in conjunction with "Management's Discussion and Analysis of Financial Condition and Results of Operations" and our consolidated financial statements and the related notes included elsewhere in this Report.

        The selected consolidated financial information presented below under the caption "Statements of Operations Data" for the years ended December 31, 2011, 2010 and 2009 and the selected consolidated financial information presented below under the caption "Balance Sheet Data" as of December 31, 2011 and 2010 has been derived from our audited consolidated financial statements included elsewhere in this Report, which financial statements have been audited by KPMG LLP, our independent registered public accounting firm. The consolidated financial information presented below under the caption "Statements of Operations Data" for the years ended December 31, 2008 and 2007 and the consolidated financial information presented below under the caption "Balance Sheet Data" at December 31, 2009, 2008 and 2007, is derived from our audited consolidated financial statements that are not included in this Report.

        We calculated earnings per share in 2007 on a pro forma basis. This calculation gave effect to the issuance of 23 million shares in our initial public offering, the merger of two subsidiaries of CALLC with two of our direct wholly-owned subsidiaries, the 628,667.20 for 1 stock split, the issuance of 247,471 shares of our common stock to our chief executive officer in exchange for his shares in two of our subsidiaries, the issuance of 27,100 shares of our common stock to our employees and the issuance of 17,500 non-vested shares of our common stock to two of our directors.

 
   Year Ended December 31,  
 
   2011(1)   2010   2009   2008   2007  
 
   (in millions, except share data)
  

Statements of Operations Data:

                                

Net sales

   $ 5,029.1   $ 4,079.8   $ 3,136.3   $ 5,016.1   $ 2,966.9  

Cost of product sold(2)

     3,943.5     3,568.1     2,547.7     4,461.8     2,308.8  

Direct operating expenses(2)

     334.1     239.8     226.6     245.4     317.6  

Insurance recovery-business interruption

     (3.4 )   —     —     —     —  

Selling, general and administrative expenses(2)

     98.0     92.0     68.9     35.2     93.1  

Depreciation and amortization

     90.3     86.8     84.9     82.2     60.8  

Goodwill impairment(3)

     —     —     —     42.8     —  
                       

Operating income

   $ 566.6   $ 93.1   $ 208.2   $ 148.7   $ 186.6  

Other income (expense), net(4)

     (0.8 )   (13.2 )   (0.1 )   (5.9 )   0.2  

Interest expense

     (55.8 )   (50.3 )   (44.2 )   (40.3 )   (61.1 )

Gain (loss) on derivatives, net

     78.1     (1.5 )   (65.3 )   125.3     (282.0 )
                       

Income (loss) before income taxes and noncontrolling interest

   $ 588.1   $ 28.1   $ 98.6   $ 227.8   $ (156.3 )

Income tax (expense) benefit

     (209.5 )   (13.8 )   (29.2 )   (63.9 )   88.5  

Noncontrolling interest

     (32.8 )   —     —     —     0.2  
                       

Net income (loss) attributable to CVR Energy stockholders(5)

   $ 345.8   $ 14.3   $ 69.4   $ 163.9   $ (67.6 )

Basic earnings (loss) per share(6)

   $ 4.00   $ 0.17   $ 0.80   $ 1.90   $ (0.78 )

Diluted earnings (loss) per share(6)

   $ 3.94   $ 0.16   $ 0.80   $ 1.90   $ (0.78 )

Weighted-average common shares outstanding(6):

                                

Basic

     86,493,735     86,340,342     86,248,205     86,145,543     86,141,291  

Diluted

     87,766,573     86,789,179     86,342,433     86,224,209     86,141,291  

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   Year Ended December 31,  
 
   2011(1)   2010   2009   2008   2007  
 
   (in millions)
  

Balance Sheet Data:

                                

Cash and cash equivalents

   $ 388.3   $ 200.0   $ 36.9   $ 8.9   $ 30.5  

Working capital

     769.2     333.6     235.4     128.5     10.7  

Total assets

     3,119.3     1,740.2     1,614.5     1,610.5     1,868.4  

Total debt, including current portion

     863.8     477.0     491.3     495.9     500.8  

Noncontrolling interest(7)

     148.1     10.6     10.6     10.6     10.6  

Total CVR stockholders' equity/members' equity

     1,151.6     689.6     653.8     579.5     432.7  

Cash Flow Data:

                                

Net cash flow provided by (used in):

                                

Operating activities

     278.6     225.4     85.3     83.2     145.9  

Investing activities

     (674.4 )   (31.3 )   (48.3 )   (86.5 )   (268.6 )

Financing activities

     584.1     (31.0 )   (9.0 )   (18.3 )   111.3  

Other Financial Data:

                                

Capital expenditures for property, plant and equipment

     91.2     32.4     48.8     86.5     268.6  
(1)
We acquired GWEC on December 15, 2011 and its results of operations are included from the date of acquisition. In addition, we incurred approximately $5.2 million of transaction and integration costs related to the acquisition in fiscal year 2011. These transactions impact the comparability of the Selected Financial Data.

(2)
Amounts are shown exclusive of depreciation and amortization.

(3)
Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that the goodwill in the petroleum segment was impaired, which resulted in a goodwill impairment loss of $42.8 million. This represented a write-off of the entire balance of the petroleum segment's goodwill.

(4)
During the years ended December 31, 2011, 2010, 2009, 2008 and 2007, we recognized a loss of $2.1 million, $16.6 million, $2.1 million, $10.0 million and $1.3 million, respectively, on early extinguishment of debt.

(5)
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:

 
   Year Ended December 31  
 
   2011   2010   2009   2008   2007  
 
   (in millions)
  

Loss on extinguishment of debt(a)

   $ 2.1   $ 16.6   $ 2.1   $ 10.0   $ 1.3  

Letter of credit expense and interest rate swap not included in interest expense(b)

     1.5     4.7     13.4     7.4     1.8  

Major scheduled turnaround expense(c)

     66.4     4.8     —     3.3     76.4  

Unrealized (gain) loss on derivatives

     (85.3 )   2.2     42.8     (253.8 )   104.6  

Share-based compensation(d)

     27.2     37.2     8.8     (42.5 )   44.1  

Goodwill impairment(e)

     —     —     —     42.8     —  

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(6)
Earnings per share and weighted-average shares outstanding are shown on a pro forma basis for 2007.

(7)
The noncontrolling interest at December 31, 2010, 2009, 2008 and 2007 reflects CALLC III's ownership of the managing general partner interest and the IDRs of the Partnership prior to the Partnership IPO. In our 2008 and 2007 Annual Report on Form 10-K, our noncontrolling interest was previously referred to as "minority interest." As a result of the adoption of Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") ASC Topic 810 — Consolidation, the term "minority interest" has been updated accordingly for all periods presented. Noncontrolling interest at December 31, 2011 reflects common units sold into the public markets as a result of the Partnership IPO.

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Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        You should read the following discussion and analysis of our financial condition and results of operations in conjunction with our financial statements and related notes included elsewhere in this Report.


 Forward-Looking Statements

        This Annual Report on Form 10-K, including, without limitation, the sections captioned "Business" and "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 Annual Report on Form 10-K 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 that 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 under the section captioned "Risk Factors" and contained elsewhere in this Report.

        All forward-looking statements contained in this Report only speak as of the date of this Report. We undertake no obligation to publicly update or revise 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.


Overview and Executive Summary

        We are an independent petroleum refiner and marketer of high value transportation fuels in the mid-continental United States. In addition, we own the general partner and approximately 70% of the common units of CVR Partners, LP, a publicly-traded limited partnership that is an independent producer and marketer of upgraded nitrogen fertilizers in the form of ammonia and urea ammonia nitrate, or UAN.

        We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2011, 2010 and 2009, we generated consolidated net sales of $5.0 billion, $4.1 billion and $3.1 billion, respectively, and operating income of $566.6 million, $93.1 million and $208.2 million, respectively. Our petroleum business generated net sales of $4.8 billion, $3.9 billion and $2.9 billion, and the nitrogen fertilizer business generated net sales of $302.9 million, $180.5 million and $208.4 million in each case for the years ended December 31, 2011, 2010 and 2009, respectively. Our petroleum business generated operating income of $465.7 million, $104.6 million and $170.2 million in each case, for the years ended December 31, 2011, 2010 and 2009, respectively. The

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nitrogen fertilizer business generated operating income of $136.2 million, $20.4 million and $48.9 million in each case for the years ended December 31, 2011, 2010 and 2009, respectively.

        Petroleum business.    Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas and, as of December 15, 2011, a 70,000 bpd crude oil unit refinery in Wynnewood, Oklahoma. In addition, our supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 38,000 bpd serving Kansas, Oklahoma, western Missouri and southwestern Nebraska, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville, Kansas and at throughput terminals on Magellan and NuStar's refined 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 our 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) an additional 3.3 barrels of leased storage capacity located in Cushing, Oklahoma and other locations and (6) approximately 4.5 million barrels of combined refinery related storage capacity.

        Our 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 our Wynnewood refinery is approximately 130 miles southwest. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.

        Crude oil is supplied to our Coffeyville refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead and Keystone pipelines (as discussed more fully in Note 17 to the financial statements) from Canada and have access to foreign and deepwater domestic crude oil via the Seaway Pipeline system from the U.S. Gulf Coast to Cushing. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our Coffeyville refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics and from time-to-time a variety of South American, North Sea, Middle East and West African imported grades. Our Wynnewood refinery is capable of processing a variety of crudes, including West Texas sour, West Texas Intermediate, sweet and sour Canadian and U.S. Gulf Coast crudes. The access to a variety of crude oils coupled with the complexity of our refineries allows us to purchase crude oil at a discount to WTI. Our consumed crude oil cost discount to WTI for 2011 was $3.98 per barrel compared to $3.39 per barrel in 2010 and $4.65 per barrel in 2009.

        Nitrogen fertilizer business.    The nitrogen fertilizer business consists of our interest in the Partnership. We own the general partner and approximately 70% of the common units of the 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 2,025 ton-per-day UAN unit and a gasifier complex having a capacity of 84 million standard cubic feet per day. The gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving reliability. In 2011, the nitrogen fertilizer business produced 411,189 tons of ammonia, of which approximately 72% was upgraded into 714,130 tons of UAN.

        The Partnership is expanding the nitrogen fertilizer business' existing asset base to execute its growth strategy. The Partnership's growth strategy includes expanding production of UAN and

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acquiring additional infrastructure and production assets. The Partnership is moving forward with a significant two-year plant expansion designed to increase our UAN production capacity by 400,000 tons, or approximately 50%, per year.

        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 significantly less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. By using pet coke as the primary raw material feedstock instead of natural gas, the nitrogen fertilizer business has historically been the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from CVR Energy pursuant to a long-term agreement having an initial term that ends in 2027, 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 CVR Energy's crude oil refinery in Coffeyville.


Major Influences on Results of Operations

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

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

        In order to assess our operating performance, we compare our net sales, less cost of product sold, or our refining margin, against an industry refining margin benchmark. The industry refining margin 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

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

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

        Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2011, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $3.0 million.

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

        Consistent, safe, and reliable operations at our refineries are key to our financial performance and results of operations. Unplanned downtime at our refineries may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin

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environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. Our 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. Our Coffeyville refinery is in the process of completing the first phase of a two phase turnaround that began during the fourth quarter of 2011. The second phase began during the first quarter of 2012. The next turnaround for the Wynnewood refinery is scheduled for fourth quarter 2012.

        Our Coffeyville refinery experienced an equipment malfunction and small fire in connection with its FCCU on December 28, 2010, which led to reduced crude oil throughput and repair cost approximately $2.2 million net of insurance receivable for the year ended 2011. We used the resulting downtime to perform certain turnaround activities which had otherwise been scheduled for later in 2011, along with opportunistic maintenance, which cost approximately $4 million in total. The refinery returned to full operations on January 26, 2011. This interruption adversely impacted the production of refined products for the petroleum business in the first quarter of 2011. We estimate that approximately 1.9 million barrels of crude oil processing were lost in the first quarter of 2011 due to this incident.

        Our Coffeyville refinery also experienced a small fire at its CCR in May 2011, which led to reduced crude oil throughput for the second quarter of 2011. Repair costs, net of the insurance receivable, recorded for the year ended December 31, 2011 approximated $2.5 million. The interruption adversely impacted the production of refined products for the second quarter of 2011. Similarly, the Wynnewood refinery experienced a small explosion and fire in its hydrocracker process unit due to metal failure in December 2010.

        In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. As a result, volatile swings in natural gas prices have a minimal impact on its results of operations. Instead, our adjacent 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.

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

        Natural gas is the most significant raw material required in our competitors' production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price

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volatility. This pricing and volatility has a direct impact on our competitors' cost of producing nitrogen fertilizer.

        In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of 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 2011, approximately 56% of the corn planted in the United States was grown within a $40/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 location on Union Pacific's main line increases our transportation cost advantage by lowering the costs of bringing our products to customers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad, and we do not currently incur any intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $25 per ton over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

        The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2011, the nitrogen fertilizer business upgraded approximately 72% of its ammonia production into UAN, a product that presently generates greater profit than ammonia. During 2010, the nitrogen fertilizer business upgraded approximately 60% of its ammonia production into UAN. UAN production is a major contributor to our profitability.

        The nitrogen fertilizer business' largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. In the years ended December 31, 2011, 2010 and 2009, the nitrogen fertilizer business spent approximately $16.8 million, $7.4 million and $12.8 million, respectively, for pet coke, which equaled an average cost per ton of $33, $17 and $27, respectively.

        The high fixed cost of the nitrogen fertilizer business' direct operating expense structure also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs averaged approximately 87% of direct operating expenses over the 24 months ended December 31, 2011. The average annual operating costs over the 24 months ended December 31, 2011 have approximated $86 million, of which substantially all are fixed in nature.

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

        Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital

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investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2010, at a cost of approximately $3.5 million. The next turnaround is currently scheduled for the fourth quarter of 2012. In connection with the 2010 biennial turnaround, the nitrogen fertilizer business wrote off approximately $1.4 million of fixed assets.

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

        For the years ended December 31, 2011, 2010 and 2009, the nitrogen fertilizer segment was charged $10.2 million, $10.6 million and $12.1 million, respectively, for management services.


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.

        The financial results of GWEC, which was acquired on December 15, 2011, have been included in the results of our petroleum business since the date of the Wynnewood Acquisition. The Wynnewood Acquisition enhances the petroleum business by expanding our process capacity and diversifying our asset base. Results for the year ended December 31, 2011 included net sales of approximately $115.7 million and a net loss of $2.3 million related to GWEC for the period from December 16, 2011 through December 31, 2011. Future periods' results of operations will include a full year of GWEC's financial results.

        ABL Credit Facility.    On February 22, 2011, we entered into a $250.0 million asset-backed revolving credit agreement ("ABL credit facility"). The ABL credit facility replaced the first priority credit facility described below, which was terminated. As a result of the termination of the first priority credit facility, we expensed a portion of our previously deferred financing costs of approximately $1.9 million. This

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expense is reflected on the Consolidated Statement of Operations as a loss on extinguishment of debt for the year ended December 31, 2011. On December 15, 2011, we entered into an incremental commitment agreement to increase availability under the ABL credit facility by an additional $150.0 million. In connection with [entering into and then expanding] the ABL credit facility, we incurred approximately $9.9 million of fees that were deferred and are to be amortized over the term of the credit facility on a straight-line basis.

        Notes.    In April 2010, we 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 "Notes"). We used the proceeds from the sale of the Notes to pay off the $453.0 million of term loans as described below.

        In December 2010, we made a voluntary unscheduled payment of $27.5 million on our First Lien Notes, resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling approximately $1.6 million, which was recognized as a loss on extinguishment of debt in our Consolidated Statements of Operations.

        On December 15, 2011, we issued an additional $200.0 million of our First Lien Notes to partially fund the Wynnewood Acquisition. Financing and other third party costs incurred at the time of $6.0 million were deferred and are amortized over the remaining term of the First Lien Notes. We entered into a commitment for a one year bridge loan in November 2011, which remained undrawn and was terminated as a result of the issuance of the First Lien Notes. Fees and other third party costs related to the bridge loan totaling $3.9 million were expensed in December 2011.

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

        First Priority Credit Facility.    The First Priority Credit Facility was repaid in full in connection with the issuance of the Notes in April 2010.

        During June 2009, CRLLC successfully reduced the first priority funded letter of credit issued under its first priority credit facility from $150.0 million to $60.0 million. This funded letter of credit was issued in support of our Cash Flow Swap. As a result of the third amendment, CRLLC terminated the Cash Flow Swap in advance of its original expiration of June 30, 2010. As a result of the reduction of the first priority funded letter of credit and eventual termination of the remaining $60.0 million first priority funded letter of credit facility on October 15, 2009, previously deferred financing costs totaling approximately $2.1 million were written off. This amount is reflected on our Consolidated Statements of Operations as a loss on extinguishment of debt.

        On October 2, 2009, CRLLC entered into a third amendment to its first priority credit facility. In connection with the third amendment, CRLLC incurred lender fees of approximately $2.6 million. These fees were recorded as deferred financing costs in the fourth quarter of 2009. In addition, CRLLC incurred third party costs of approximately $1.4 million primarily consisting of administrative and legal costs. Of the third party costs incurred, we expensed approximately $0.9 million in 2009. The remaining $0.5 million was recorded as additional deferred financing costs.

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        In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing our D term loans' outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. We used the proceeds from the issuance of our Notes in April 2010 to pay off the remaining $453.0 million term loans.

        On March 12, 2010, CRLLC entered into a fourth amendment to its first priority credit facility. In connection with the fourth amendment, CRLLC incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, CRLLC incurred third party costs of approximately $1.5 million primarily consisting of administrative and legal costs. Of the third party costs incurred we expensed $1.1 million in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs.

        In April 2010, upon issuance of the Notes and repayment of the first priority credit facility, previously deferred financing costs totaling approximately $5.4 million associated with the first priority credit facility term debt were written off at that time. In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million.

        Until October 8, 2009, CRLLC had been a party to the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. On October 8, 2009, the Cash Flow Swap was terminated and all remaining obligations were settled in advance. We determined that the Cash Flow Swap did not qualify as a hedge for hedge accounting treatment under FASB ASC Topic 815, Derivatives and Hedging. As a result, the Consolidated Statements of Operations reflects all the realized and unrealized gains and losses from this swap which created significant fluctuations in our results of operations between periods. As a result of the termination of the Cash Flow Swap in the fourth quarter of 2009, there was no impact to the Consolidated Statements of Operations for the years ended December 31, 2011 and 2010. For the year ended December 31, 2009, we recorded a net realized loss of $14.3 million with respect to the Cash Flow Swap. In addition, for the year ended December 31, 2009, we recorded a net unrealized loss of $40.9 million.

        Through the Company's Long-Term Incentive Plan, 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. Restricted shares, when granted, are 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. For the years ended December 31, 2011, 2010 and 2009, we incurred compensation expense of $9.8 million, $2.4 million and $0.8 million, respectively, related to non-vested share-based compensation awards.

        Through the CVR Partners, LP Long-Term Incentive Plan, shares of non-vested common units may be awarded to the employees, officers, consultants, and directors of the Partnership, the general partner, and their respective subsidiaries and parents. Non-vested units, when granted, are valued at the closing market price of CVR Partners common units at the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the years ended December 31, 2011, 2010 and 2009, we incurred compensation expense of $1.2 million, $0.0 million and $0.0 million, respectively, related to non-vested share-based compensation awards.

        Through a wholly-owned subsidiary, we had the two Phantom Unit Appreciation Plans (the "Phantom Unit Plans"), whereby directors, employees, and service providers historically could be

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awarded phantom points at the discretion of the board of directors or the compensation committee. We accounted for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC Topic 718, Compensation — Stock Compensation, the expense associated with these awards was based on the current fair value of the awards which was derived from a probability-weighted expected return method.

        Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to recipients other than employees for acquiring or in conjunction with selling goods or services. In accordance with this accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived under the same methodology as the Phantom Unit Plans, as remeasured at each reporting date until the awards vest. Certain override units became fully vested during the second quarter of 2010. As such, there was no additional expense incurred, subsequent to vesting, with respect to these share-based compensation awards. For the years ended December 31, 2011, 2010 and 2009, we increased compensation expense by $16.2 million, $34.8 million and $7.9 million, respectively, as a result of the phantom and override unit share-based compensation awards. Due to the divestiture of all ownership of CVR Energy by CALLC and CALLC II in 2011, there will be no further share-based compensation expense associated with override units subsequent to 2011. In association with the divestiture of ownership and the distributions to the override unitholders of CALLC and CALLC II, the holders of phantom units received the associated payments in 2011. As a result, there will be no further share-based compensation expense recorded for the Phantom Unit Plans subsequent to 2011.

        Prior to the Partnership IPO, the noncontrolling interests represented the incentive distribution rights ("IDRs") of CVR GP, LLC. In April 2011, in connection with the Partnership IPO, the IDRs were purchased by the Partnership and were subsequently extinguished, eliminating the associated noncontrolling interest related to the IDRs. As a result of the Partnership IPO, CVR Energy recorded a noncontrolling interest for the common units sold into the public market, which represented an approximately 30% interest in the net book value of the Partnership at the time of the Partnership IPO. Effective with the Partnership IPO, CVR Energy's noncontrolling interest reflected on the consolidated balance sheet will be impacted by approximately 30% of the net income of the Partnership and related distributions for each future reporting period. The revenue and expenses from the Partnership will continue to be consolidated with CVR Energy's statement of operations based upon the fact that the general partner is owned by CRLLC, a wholly-owned subsidiary of CVR Energy, and therefore has the ability to control the activities of the Partnership. However, the percentage of ownership held by the public unitholders will be reflected as net income attributable to noncontrolling interest in our consolidated statement of operations and will reduce consolidated net income to derive net income attributable to CVR Energy.

        Our general and administrative expenses have increased due to the costs of the Partnership operating as a publicly traded company, including costs associated with SEC reporting requirements (including annual and quarterly reports to 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

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personnel costs, approximate $5.5 million per year, excluding the costs associated with the initial implementation of the Partnership's Sarbanes-Oxley Section 404 internal controls review and testing. These increased costs will be paid by the Partnership. Our historical consolidated financial statements do not reflect the impact of these expenses, which affects the comparability of the post- Partnership IPO results with our financial statements from periods prior to the completion of the Partnership IPO.

September 2010 UAN Vessel Rupture

        On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. The nitrogen fertilizer facility had previously scheduled a major turnaround to begin on October 5, 2010. To minimize disruption and impact to the production schedule, the turnaround was accelerated. The turnaround was completed on October 29, 2010 with the gasification and ammonia units in operation. The fertilizer facility restarted production of UAN on November 16, 2010.

        Total gross costs recorded as of December 31, 2011 due to the incident were approximately $11.4 million for repairs and maintenance and other associated costs. As of December 31, 2011, approximately $7.0 million of insurance proceeds have been received related to the property damage insurance claim. Of the costs incurred, approximately $4.6 million were capitalized. We also recognized income of approximately $3.4 million during 2011 from insurance proceeds received related to our business interruption insurance policy.

Fertilizer Plant Property Taxes

        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 reassessed CRNF's nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment 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 December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county's classification of its nitrogen fertilizer plant and has been disputing it before the Kansas Court of Tax Appeals ("COTA"). However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008, and has fully accrued such amounts for the year ended December 31, 2011. The first payment in respect of CRNF's 2011 property taxes was paid in December 2011 and the second payment will be made in May 2012. This property tax expense is reflected as a direct operating expense in our financial results. In January 2012 COTA issued a ruling indicating that the assessment in 2008 of CRNF's fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling and filed a petition for reconsideration with COTA (which was denied) and plans to file an appeal to the Kansas Court of Appeals. CRNF is also protesting the valuation of the nitrogen fertilizer plant for tax years 2009 through 2011, which cases remain pending before COTA. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on CRNF's and the Company's results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then we expect that it will continue to pay property taxes at elevated rates currently in effect.

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Distributions to Unitholders

        The current policy of the board of directors of the Partnership's general partner is to distribute all of the available cash the Partnership generates each quarter. Available cash for each quarter will be determined by the board of directors of the Partnership's general partner following the end of such quarter. Available cash for each quarter will generally equal the Partnership's cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of its general partner deems necessary or appropriate. Additionally, the Partnership retains cash on hand associated with prepaid sales at each quarter end for future distributions to common unitholders based upon the recognition into income of the prepaid sales. The board of directors of the Partnership may modify the cash distribution policy at any time, and the partnership agreement does not require the Partnership to make distributions at all.

        On August 12, 2011, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on August 5, 2011 for the second quarter of 2011 (calculated for the period beginning April 13, 2011 through June 30, 2011) in the amount of $0.407 per unit or $29.7 million in aggregate. We received $20.7 million in respect of our common units.

        On November 14, 2011, the Partnership paid out a cash distribution to the Partnership's unitholders of record at the close of business on November 7, 2011 for the third quarter of 2011 in the amount of $0.572 per unit or $41.8 million in aggregate. We received $29.1 million in respect of our common units.

        On January 26, 2012, the board of directors of the Partnership's general partner declared a quarterly cash distribution to the Partnership's unitholders of $0.588 per unit or $42.9 million in aggregate. We received $29.9 million in respect of our common units. The cash distribution was paid on February 14, 2012, to unitholders of record at the close of business on February 7, 2012. This distribution was for the fourth quarter of 2011.

        There were no cash distributions paid in 2010 and 2009 as the Partnership IPO did not occur until 2011.

Partnership Credit Facility

        On April 13, 2011 in conjunction with the completion of the Partnership IPO, the Partnership entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the credit facility matures April 2016. The credit facility used to finance ongoing working capital, capital projects, letter of credit issuances and general needs of the Partnership.

        Borrowings under the credit facility bear interest based on a pricing grid determined by a trailing four quarter leverage ratio. The initial pricing for borrowings 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 Partnership. CRNF is the borrower under the credit facility. All obligations under the credit facility are unconditionally guaranteed by the Partnership and substantially all of the Partnership's future, direct and indirect, domestic subsidiaries.

        The credit facility requires CRNF to maintain (i) a minimum interest coverage ratio (ratio of Consolidated Adjusted EBITDA to interest) as of any fiscal quarter of 3.0 to 1.0 and (ii) a maximum leverage ratio (ratio of debt to Consolidated Adjusted EBITDA) of (a) as of any fiscal quarter ended

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

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

Partnership Interest Rate Swap

        Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates.

        On June 30 and July 1, 2011, CRNF entered into two Interest Rate Swap agreements with J. Aron. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. These Interest Rate Swap agreements commenced on August 12, 2011. The impact recorded for the year ended December 31, 2011 is $0.4 million in interest expense. For the year ended December 31, 2011, the Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $2.4 million, which is unrealized in accumulated other comprehensive income.

Commodity Swaps - Petroleum Segment

        Beginning in September 2011, we entered into commodity swap contracts with effective periods beginning in January 2012. 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 Consolidated Balance Sheets with changes in fair value currently recognized in the Consolidated Statements of Operations. At December 31, 2011, we had open commodity hedging instruments consisting of 13.0 million barrels of crack spreads primarily to fix the margin on a portion of our future gasoline and distillate production with effective periods beginning in 2012 and 2013. 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.

Turnaround Projects

        The Coffeyville refinery completed the first phase of a two-phase planned turnaround project during the fourth quarter of 2011. The second phase is scheduled to begin in the first quarter of 2012. The petroleum business has incurred costs of approximately $66.4 million and $1.3 million for the years ended December 31, 2011 and 2010, respectively, associated with the 2011/2012 turnaround. The Wynnewood refinery is scheduled to begin a turnaround in the fourth quarter of 2012. Costs associated with turnaround projects are recorded in direct operating expense (exclusive of depreciation and

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amortization) on the Consolidated Statements of Operations. During the fourth quarter of 2010, the nitrogen fertilizer business completed a planned biennial turnaround of the nitrogen fertilizer plant at a total cost of approximately $3.5 million, the majority of which was expensed in the fourth quarter of 2010. In connection with the nitrogen fertilizer plant's biennial turnaround, we also wrote off approximately $1.4 million of fixed assets for the year ended December 31, 2010. No major maintenance activities occurred in 2009.


Industry Factors

Petroleum Business

        Earnings for our petroleum business depend largely on our refining margins, which have been and continue to be volatile. Refining margins are impacted primarily by the relationship between crude oil and refined product prices which are influenced by factors beyond our control. Our marketing region continues to be undersupplied and is a net importer of transportation fuels.

        Crude oil discounts also contribute to our petroleum business earnings. Discounts for sour and heavy sour crude oil compared to sweet crude oil continue to fluctuate widely. The worldwide production of sour and heavy sour crude oil, continuing demand for light sweet crude oil, and the increasing volumes of Canadian sour crude oil to the mid-continent will continue to cause wide swings in discounts. As a result of our expansion project, we increased our ability to process higher volumes of heavy sour crude oil, primarily Canadian crude oil, and this ability provides us the flexibility to reduce our dependence on typically more expensive light sweet crude oil.

        Additionally, the relationship between current spot prices and future prices can impact our profitability. As such, we believe that our 3.3 million barrels of crude oil storage in Cushing, Oklahoma and other locations allows us to take advantage of the contango market when such conditions exist. Contango markets are generally characterized by prices for future delivery that are higher than the current or spot price, of a commodity. This condition provides economic incentive to hold or carry a commodity in inventory.

        Global demand for fertilizers is driven primarily by population growth, dietary changes in the developing world and increased consumption of bio-fuels. According to the International Fertilizer Industry Association, from 1972 to 2010, global fertilizer demand grew 2.1% annually. Fertilizer use is projected to increase by 45% between 2005 and 2030 to meet global food demand according to a study funded by the Food and Agricultural Organization of the United Nations. Currently, the developed world uses fertilizer more intensively than the developing world, but sustained economic growth in emerging markets is increasing food demand and fertilizer use. As an example, China's grain production increased 46% between 2001 and 2011, but still failed to keep pace with increases in demand, prompting China to double its grain imports over the same period, according to the United States Department of Agriculture.

        World grain demand has increased 8.7% over the last five years leading to a tight grain supply environment and significant increases in grain prices, which is highly supportive of fertilizer prices. During the last five years, corn prices in Illinois have averaged $4.60 per bushel, an increase of 92.6% above the average price of $2.41 per bushel during the preceding five years. Recently, this trend has continued as U.S. 30-day corn and wheat futures increased 56% and 44%, respectively, from 2010 to 2011. During this same time period, Southern Plains ammonia prices increased 42% from $433 per ton to $613 per ton and corn belt UAN prices increased 41% from $266 per ton to $375 per ton. Nitrogen fertilizer prices have decoupled from their historical correlation with natural gas prices and are now

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driven primarily by demand dynamics. At existing grain prices and prices implied by futures markets, farmers are expected to generate substantial profits, leading to relatively inelastic demand for fertilizers.

        The United States is the world's largest exporter of coarse grains, accounting for 37% of world exports and 28% of total world production, according to the USDA. The United States is also the world's third largest consumer of nitrogen fertilizer and historically the world's largest importer of nitrogen fertilizer, importing approximately 38% of its nitrogen fertilizer needs. North American producers have a significant and sustainable cost advantage over European producers that export to the U.S. market. Over the last decade, the North American nitrogen fertilizer market has experienced significant consolidation through plant closures and corporate consolidation.

        Unlike ammonia and urea, UAN can be applied throughout the growing season and can be applied in tandem with pesticides and fungicides, providing farmers with flexibility and cost savings. UAN is not widely traded globally because it is costly to transport (it is approximately 65% water); therefore there is little risk to U.S. UAN producers of an influx of UAN from foreign imports. As a result of these factors, UAN commands a premium price to urea and ammonia, on a nitrogen equivalent basis.


Results of Operations

        In this "Results of Operations" section, we first review our business on a consolidated basis, and then separately review the results of operations of each of our petroleum and nitrogen fertilizer businesses on a standalone basis.

        The period to period comparisons of our results of operations have been prepared using the historical periods included in our financial statements. This "Results of Operations" section compares the year ended December 31, 2011 with the year ended December 31, 2010 and the year ended December 31, 2010 with the year ended December 31, 2009.

        Net sales consist principally of sales of refined fuel and nitrogen fertilizer products. For the petroleum business, net sales are mainly affected by crude oil and refined product prices, changes to the input mix and volume changes caused by operations. Product mix refers to the percentage of production represented by higher value light products, such as gasoline, rather than lower value finished products, such as pet coke. In the nitrogen fertilizer business, net sales are primarily impacted by manufactured tons and nitrogen fertilizer prices.

        Industry-wide petroleum results are driven and measured by the relationship, or margin, between refined products and the prices for crude oil referred to as crack spreads. See " — Major Influences on Results of Operations." We discuss our results of petroleum operations in the context of per barrel consumed crack spreads and the relationship between net sales and cost of product sold.

        Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore do not equal the sum of the operating results of the petroleum and nitrogen fertilizer businesses.

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        The following table provides an overview of our results of operations during the past three fiscal years:

 
   Year Ended December 31,  
Consolidated Financial Results
  2011   2010   2009  
 
   (in millions)
  

Net sales

   $ 5,029.1   $ 4,079.8   $ 3,136.3  

Cost of product sold (exclusive of depreciation and amortization)

     3,943.5     3,568.1     2,547.7  

Direct operating expenses (exclusive of depreciation and amortization)

     334.1     239.8     226.6  

Insurance recovery — business interruption

     (3.4 )   —     —  

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

     98.0     92.0     68.9  

Depreciation and amortization(1)

     90.3     86.8     84.9  
               

Operating income

   $ 566.6   $ 93.1   $ 208.2  

Net income(2)

     378.6     14.3     69.4  

Less: Net income attributable to noncontrolling interest

     32.8     —     —  
               

Net income attributable to CVR Energy Stockholders

   $ 345.8   $ 14.3   $ 69.4  
(1)
Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expense and selling, general and administrative expense:

 
   Year Ended December 31,  
Consolidated Financial Results
  2011   2010   2009  
 
   (in millions)
  

Depreciation and amortization excluded from cost of product sold

   $ 2.5   $ 2.8   $ 2.9  

Depreciation and amortization excluded from direct operating expenses

     86.0     81.9     80.0  

Depreciation and amortization excluded from selling, general and administrative expense

     1.8     2.1     2.0  
               

Total depreciation and amortization

   $ 90.3   $ 86.8   $ 84.9  
               
(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

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   Year Ended December 31,  
Consolidated Financial Results
  2011   2010   2009  
 
   (in millions)
  

Loss on extinguishment of debt

   $ 2.1   $ 16.6   $ 2.1  

Letter of credit & interest rate swap expense included in selling, general and administrative expenses(a)

     1.5     4.7     13.4  

Major scheduled turnaround expense

     66.4     4.8     —  

Unrealized (gain) loss on derivatives, net

     (85.3 )   2.2     40.9  

Share-based compensation expense

     27.2     37.2     8.8  

Acquisition and integration expenses—Gary-Williams(b)

     9.1     —     —  
(a)
Consists of fees which are expensed to selling, general and administrative expense in connection with our letters of credit outstanding and our first priority funded letter of credit facility issued in support of the Cash Flow Swap until it was terminated effective October 15, 2009. As noted above, the Cash Flow Swap was terminated effective October 8, 2009 and the related first priority funded letter of credit facility was terminated effective October 15, 2009.

(b)
On December 15, 2011, the Company acquired the stock of Gary-Williams Energy Corporation and its wholly-owned subsidiaries which included a 70,000 barrel per day refinery in Wynnewood, Oklahoma. The Company incurred costs that are referred to herein as acquisition costs. Included in the acquisition costs are legal and other professional fees associated with the acquisition and certain costs incurred beginning in 2011 associated with the preliminary integration of the acquired business. In conjunction with the acquisition, the Company also incurred approximately $3.9 million of costs associated with a bridge loan that was committed but undrawn. The costs were immediately expensed and not deferred.

        Net Sales.    Consolidated net sales were $5,029.1 million for the year ended December 31, 2011 compared to $4,079.8 million for the year ended December 31, 2010. The increase of $949.3 million was primarily due to an increase in petroleum net sales of $848.0 million that resulted from higher product prices which were partially offset by lower overall sales volumes. Our average sales price per gallon for the year ended December 31, 2011 of $2.82 for gasoline and $3.03 for distillates increased by 33.9% and 38.0% respectively, as compared to the year ended December 31, 2011. Overall sales volumes of refined fuels and propane for the year ended December 31, 2011 decreased by 11.5% as compared to the year ended December 31, 2010. The lower overall sales volumes were primarily the result of the major maintenance turnaround at our Coffeyville refinery in the fall of 2011. Nitrogen fertilizer segment net sales increased by $122.4 million as the result of higher UAN sales volumes coupled with increased ammonia and UAN plant gate prices, partially offset by lower ammonia sales volumes.

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,943.5 million for the year ended December 31, 2011, as compared to $3,568.1 million for the year ended December 31, 2010. The increase of $375.4 million primarily resulted from a significant increase in crude oil prices. On a year-over-year basis, our consumed crude oil prices increased approximately 21.0% from an average price of $76.13 per barrel in 2010 to an average price of $92.09 per barrel in 2011. The increase in crude oil prices was partially offset by an 8.5% decrease in crude oil throughput in 2011 compared to 2010. Our total increase included the increase in cost of product sold (exclusive of depreciation and amortization) by

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the nitrogen fertilizer business. This increase was primarily the result of higher costs of transactions with affiliates totaling $5.9 million and external parties totaling $2.3 million. These increased costs were partially offset by a decrease in costs associated with lower ammonia sales and a decrease in hydrogen costs.

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Consolidated direct operating expenses (exclusive of depreciation and amortization) were $334.1 million for the year ended December 31, 2011, as compared to $239.8 million for the year ended December 31, 2010. The increase of $94.3 million was due primarily to increased petroleum segment expenses for the turnaround, environmental compliance, repairs and maintenance and other expenses.

        Insurance Recovery—Business Interruption.    During the year ended December 31, 2011, we recorded and received business interruption proceeds of $3.4 million related to the September 30, 2010 UAN vessel rupture.

        Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).    Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $98.0 million for the year ended December 31, 2011, as compared to $92.0 million for the year ended December 31, 2010. This $6.0 million increase was primarily the result of higher payroll-related costs due to growth in staff and integration costs related to GWEC, offset in part by lower share-based compensation expenses resulting from the change in the composition of our long-term incentive plans.

        Operating Income.    Consolidated operating income was $566.6 million for the year ended December 31, 2011, as compared to operating income of $93.1 million for the year ended December 31, 2010, an increase of $473.5 million. Petroleum segment operating income increased $361.1 million primarily as a result of an increase in refining margin, partially offset by an increase of direct operating expenses. Nitrogen fertilizer segment operating income increased $115.8 million primarily as a result of the increase in nitrogen fertilizer margin.

        Interest Expense.    Consolidated interest expense for the year ended December 31, 2011 was $55.8 million as compared to $50.3 million for the year ended December 31, 2010. This $5.5 million increase resulted primarily from higher interest cost by having a full year of interest on the $500.0 million of Notes issued in April 2010 along with increased amortization to interest expense for deferred financing costs and original issue discount associated with the Notes.

        Gain (Loss) on Derivatives, Net.    For the year ended December 31, 2011, we recorded a $78.1 million net gain on derivatives. This compares to a $1.5 million net loss on derivatives for the year ended December 31, 2010. The change in gain (loss) on derivatives was primarily attributable to the realized and unrealized gains on our commodity swaps in the Petroleum segment.

        Loss on Extinguishment of Debt.    For the year ended December 31, 2011, we incurred a $2.1 million loss on extinguishment of debt compared to $16.6 million for the year ended December 31, 2010. The decrease in the loss on the extinguishment of debt was primarily the result of a 2.0% premium paid in connection with unscheduled prepayments and payoff of our tranche D term loan in 2010, which contributed $9.6 million of the loss on extinguishment. Additionally, $5.4 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs associated with the payoff of the tranche D term loan. Concurrent with the issuance of the Notes, $0.1 million of third-party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our Notes resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling $1.6 million.

        Income Tax Expense.    Income tax expense for the year ended December 31, 2011, was $209.6 million or 35.6% of income before income taxes, as compared to an income tax expense for the

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year ended December 31, 2010 of $13.8 million or 49.1% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.4% for 2011 and 39.7% for 2010. Our effective tax rate decreased primarily due to a reduction in non-deductible share-based compensation expense in conjunction with higher pre-tax income, as well as the reduction of income subject to tax associated with our noncontrolling ownership interest in CVR Partners beginning April 13, 2011. We also recognized a state income tax benefit net of federal expense, of approximately $2.8 million in 2011 related to a reduction to our overall state effective tax rate. In addition, state income tax credits, net of federal expense, approximating $3.2 million were earned and recorded in 2011 that related to Kansas HPIP credits, compared to $2.4 million earned and recorded in 2010.

        Net Income Attributable to Noncontrolling Interest.    Amounts reported as net income attributable to noncontrolling interest include our approximately 30% interest of the publicly held common units of the Partnership.

        Net Income Attributable to CVR Stockholders.    For the year ended December 31, 2011, net income attributable to CVR stockholders increased to $345.8 million, as compared to net income of $14.3 million for the year ended December 31, 2010.

        Net Sales.    Consolidated net sales were $4,079.8 million for the year ended December 31, 2010 compared to $3,136.3 million for the year ended December 31, 2009. The increase of $943.5 million was primarily due to an increase in petroleum net sales of $968.9 million that resulted from higher product prices for both gasoline and distillate, coupled with higher overall sales volume. Sales volume for gasoline increased nominally; however, distillate sales volumes increased by approximately 10% on a year-over-year basis. The increase in distillate sales volume was a result of increased demand. As such, the refinery increased distillate production in order to take advantage of the favorable market dynamics, which included a correlated increase in distillate prices. The increase in petroleum net sales for the year ended December 31, 2010 compared to the year ended December 31, 2009 was partially offset by lower nitrogen fertilizer net sales which decreased by approximately by $27.9 million on a year-over-year basis. The decrease in nitrogen fertilizer net sales was the result of a decline in average UAN plant gate prices coupled with a decrease in UAN sales volumes. Average plant gate prices for UAN for the year ended December 31, 2010, as compared to the year ended December 31, 2009 were adversely impacted by a significant pricing cycle that began in 2008 that led to higher UAN prices for the first half of 2009 before declining through the last half of 2009 and the first half of 2010. The nitrogen fertilizer business was adversely impacted by the downtime associated with the nitrogen fertilizer plant's biennial turnaround as well as the extended downtime associated with the rupture of a high-pressure UAN vessel. The vessel rupture occurred on the evening of September 30, 2010 and the resumption of UAN production did not commence until November 16, 2010.

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Consolidated cost of product sold (exclusive of depreciation and amortization) was $3,568.1 million for the year ended December 31, 2010, as compared to $2,547.7 million for the year ended December 31, 2009. The increase of $1,020.4 million primarily resulted from a significant increase in crude oil prices. On a year-over-year basis, our consumed crude oil prices increased approximately 32% from an average price of $57.64 per barrel in 2009 compared to an average price of consumed crude oil of $76.13 per barrel in 2010. The increase in crude oil prices was coupled with an approximately 5% increase in crude oil throughput in 2010 compared to 2009. Partially offsetting the increase in cost of product sold (exclusive of depreciation and amortization) was a decline in cost of product sold by the nitrogen fertilizer business. This decrease was primarily the result of reduced sales volume of ammonia and UAN due to downtime associated with the biennial turnaround and the rupture of a high-pressure UAN vessel.

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        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Consolidated direct operating expenses (exclusive of depreciation and amortization) were $240.8 million for the year ended December 31, 2010, as compared to $226.0 million for the year ended December 31, 2009. This increase of $14.8 million was due to increases in the petroleum business and nitrogen fertilizer business direct operating expenses of $12.5 and $2.2 million, respectively. This increase was partially attributable to the increase in repairs and maintenance expenses ($6.5 million) of which approximately $1.5 million was related to the rupture of a high-pressure UAN vessel. The overall expenses incurred related to the rupture of the high-pressure UAN vessel were impacted by the capitalization of certain associated costs and by the receipt of insurance proceeds. Additionally, we incurred increased expenses associated with labor ($7.8 million), turnaround ($3.5 million), property taxes ($2.2 million) and other direct operating expenses ($1.1 million). The increased labor costs were the result of additional contract labor maintenance personnel and the increase in full-time equivalents in the petroleum business, coupled with an increase in share-based compensation expense impacted primarily by the increase in our stock price. The increase in turnaround costs was the result of the nitrogen fertilizer business' biennial turnaround that occurred in the fourth quarter of 2010 and not in 2009. The increase in property taxes for the year ended December 31, 2010 was the result of an increased valuation assessment on the nitrogen fertilizer plant as well as the expiration of a tax abatement for the Linde air separation unit for which we pay taxes in accordance with our agreement with Linde. These increases were partially offset by a decrease in production chemicals ($2.2 million), insurance ($1.9 million), energy and utilities ($1.4 million) and catalyst ($1.1 million). The decrease in production chemicals and catalyst costs were the result of reduced consumption. The reduction in insurance costs was the result of lower premiums on a year-over-year basis. The majority of the decrease in energy and utilities expenses was due to a $4.8 million settlement of an electric rate case with the City of Coffeyville by the nitrogen fertilizer business in the third quarter of 2010, partially offset by an increase in the petroleum business' natural gas and electricity prices and consumption. The rate settlement with respect to the electric rate case was a one-time event.

        Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).    Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $92.0 million for the year ended December 31, 2010, as compared to $68.9 million for the year ended December 31, 2009. This $23.1 million increase in selling, general and administrative expenses over the comparable period was primarily the result of increases in share-based compensation ($27.4 million), loss on disposition of assets ($3.1 million) and other selling, general and administrative costs ($0.5 million). The increase in our share-based compensation expense was primarily the result of the increase in our stock price. The increase in the loss on disposition of assets was the result of a write-off of a capital project in the second quarter of 2010 and the write-off of certain fixed assets associated with the nitrogen fertilizer business' biennial turnaround. These increases were partially offset by a decrease in bank charges ($5.0 million), bad debt expense ($1.3 million), insurance ($1.1 million), and payroll ($0.5 million). The decrease in bank charges was the result of the termination of the first priority funded letter of credit facility in 2009. The funded letter of credit was issued in support of our Cash Flow Swap that was also terminated in 2009.

        Operating Income.    Consolidated operating income was $93.1 million for the year ended December 31, 2010, as compared to operating income of $208.2 million for the year ended December 31, 2009, a decrease of $115.1 million. For the year ended December 31, 2010, as compared to the year ended December 31, 2009, petroleum operating income decreased $65.6 million primarily as a result of a decline in refining margin ($54.8 million) and an increase of direct operating expenses ($12.5 million). Nitrogen operating income decreased $28.5 million primarily as a result of the decrease in nitrogen fertilizer margin ($20.0 million) coupled with an increase in selling, general and administrative expenses ($6.4 million) and direct operating expenses ($2.2 million).

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        Interest Expense.    Consolidated interest expense for the year ended December 31, 2010 was $50.3 million as compared to interest expense of $44.2 million for the year ended December 31, 2009. This $6.1 million increase resulted primarily from the issuance of the Notes on April 6, 2010 in an aggregate principal amount of $500.0 million. We paid off our outstanding tranche D term debt totaling $453.3 million in April 2010 as a result of the issuance of the Notes. The Notes were issued under a first and second lien arrangement. The $275.0 million of First Lien Notes accrue interest at 9.0% and the $225.0 million of Second Lien Notes accrue interest at 10.875%. This compares to an average 2009 long-term debt balance of $481.3 million which accrued interest at a weighted-average interest rate of approximately 8.64%. Also impacting our interest expense was the increased amortization of deferred financing costs and original issue discount associated with the Notes. Additionally, a portion of the increase in amortization for the year ended December 31, 2010 was the result of costs incurred in connection with the third and fourth amendments to our first priority credit facility completed in the fourth quarter of 2009 and first quarter of 2010, respectively. For the year ended December 31, 2010, we incurred amortization of deferred financing costs associated with the first priority tranche D loans and revolving credit facility totaling $1.6 million compared to $1.0 million for the year ended December 31, 2009. The incremental impact to our interest expense, as a result of the amortization of the deferred financing costs and original issue discount associated with the issuance of the Notes in April 2010, was an increase of approximately $2.1 million for the year ended December 31, 2010.

        Gain (Loss) on Derivatives, Net.    For the year ended December 31, 2010, we incurred a $1.5 million net loss on derivatives. This compares to a $65.3 million net loss on derivatives for the year ended December 31, 2009. The change in gain (loss) on derivatives was primarily attributable to the realized and unrealized losses on our Cash Flow Swap. For the year ended December 31, 2010, there was no impact to the consolidated financial statements as the Cash Flow Swap was terminated in the fourth quarter of 2009. This compared to net losses associated with the Cash Flow Swap of $55.2 million for the year ended December 31, 2009. For the year ended December 31, 2010, we recognized a net loss on our other derivative agreements totaling approximately $1.5 million, compared to a net loss on our other derivative agreements of $8.5 million for the year ended December 31, 2009. The remaining year-over-year difference was attributable to our interest rate swap. The interest rate swap terminated on June 30, 2010 and resulted in a nominal loss for the year ended December 31, 2010 compared to a net loss of approximately $1.6 million for the year ended December 31, 2009.

        Loss on Extinguishment of Debt.    For the year ended December 31, 2010, we incurred a $16.6 million loss on extinguishment of debt compared to $2.1 million for the year ended December 31, 2009. The increase in the loss on the extinguishment of debt was primarily the result of a 2.0% premium paid in connection with unscheduled prepayments and payoff of our tranche D term loan, which contributed $9.6 million of the loss on extinguishment. Additionally, $5.4 million of the loss on extinguishment of debt was attributable to the write-off of previously deferred financing costs associated with the payoff of the tranche D term loan. Concurrent with the issuance of the Notes, $0.1 million of third party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our Notes resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs and unamortized original issue discount totaling $1.6 million. This compares to a write-off of $2.1 million of previously deferred financing costs in connection with the reduction and eventual termination of the first priority funded letter of credit facility in the fourth quarter of 2009.

        Income Tax Expense.    Income tax expense for the year ended December 31, 2010, was $13.8 million or 49.1% of income before incomes taxes, as compared to an income tax expense for the year ended December 31, 2009 of $29.2 million or 29.7% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.7% for 2010 and 2009. Our effective tax rate increased in the year ended December 31, 2010, as compared to the year ended December 31, 2009, primarily due to higher non — deductible share-based compensation expense in

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conjunction with lower pre-tax income. We also recognized a federal income tax benefit of approximately $4.8 million in 2009, on a credit of approximately $7.4 million related to the production of ultra-low sulfur diesel. In addition, state income tax credits, net of federal expense, approximating $2.4 million were earned and recorded in 2010 that related to Kansas HPIP credits, compared to $3.2 million earned and recorded in 2009.

        Net Income.    For the year ended December 31, 2010, net income decreased to $14.3 million, as compared to net income of $69.4 million for the year ended December 31, 2009.

        Our petroleum operations include the operations of both the Coffeyville and Wynnewood refineries. The Wynnewood results are included for the post acquisition period of December 16, 2011 through December 31, 2011.

        Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refineries' performance as a general indication of the amount above our cost of product sold (exclusive of depreciation and amortization) that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold exclusive of depreciation and amortization) can be taken directly from our Statement of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table shows selected information about our petroleum business including refining margin:

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (in millions)
  

Consolidated Petroleum Business Financial Results

                    

Net sales

   $ 4,751.8   $ 3,903.8   $ 2,934.9  

Cost of product sold (exclusive of depreciation and amortization)

     3,926.6     3,538.0     2,514.3  

Direct operating expenses (exclusive of depreciation and amortization)(1)

     247.7     153.1     142.2  

Depreciation and amortization

     69.9     66.4     64.4  
               

Gross profit(2)

   $ 507.6   $ 146.3   $ 214.0  

Plus direct operating expenses (exclusive of depreciation and amortization)

     247.7     153.1     142.2  

Plus depreciation and amortization

     69.9     66.4     64.4  
               

Refining margin(3)

   $ 825.2   $ 365.8   $ 420.6  

Operating income

   $ 465.7   $ 104.6   $ 170.2  

Adjusted Petroleum EBITDA(4)

   $ 580.9   $ 154.7   $ 142.3  

 

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (dollars per barrel)
  

Key Operating Statistics

                    

Per crude oil throughput barrel:

                    

Refining margin(3)

   $ 21.80   $ 8.84   $ 10.65  

Gross profit(2)

     13.41     3.54     5.42  

Direct operating expenses (exclusive of depreciation and amortization)(1)

     6.54     3.70     3.60  

Direct operating expenses per barrel sold(5)

     6.38     3.30     3.22  

Barrels sold (barrels per day)(5)

     106,397     127,142     125,005  

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   Year Ended December 31,  
 
   2011   2010   2009  
 
    
   %    
   %    
   %  

Refining Throughput and Production Data (bpd)

                                      

Throughput:

                                      

Sweet

     83,538     76.7     89,746     72.5     82,598     68.7  

Light/medium sour

     1,704     1.6     8,180     6.6     15,602     13.0  

Heavy sour

     18,460     16.9     15,439     12.5     10,026     8.3  
                           

Total crude oil throughput

     103,702     95.2     113,365     91.6     108,226     90.0  

All other feedstocks and blendstocks

     5,231     4.8     10,350     8.4     12,013     10.0  
                           

Total throughput

     108,933     100.0     123,715     100.0     120,239     100.0  

Production:

                                      

Gasoline

     48,486     44.3     61,136     49.1     62,309     51.6  

Distillate

     45,535     41.6     50,439     40.5     46,909     38.8  

Other (excluding internally produced fuel)

     15,385     14.1     12,978     10.4     11,549     9.6  
                           

Total refining production (excluding internally produced fuel)

     109,406     100.0     124,553     100.0     120,767     100.0  

Average product sale price (dollars per gallon):

                                      

Gasoline

         $ 2.82         $ 2.10         $ 1.68  

Distillate

         $ 3.03         $ 2.20         $ 1.68  

 

 
   Year Ended December 31,  
 
   2011   2010   2009  

Market Indicators (dollars per barrel)

                    

West Texas Intermediate (WTI) NYMEX

   $ 95.11   $ 79.61   $ 62.09  

Crude Oil Differentials:

                    

WTI less WTS (light/medium sour)

     2.06     2.15     1.53  

WTI less WCS (heavy sour)

     16.54     15.07     9.57  

NYMEX Crack Spreads:

                    

Gasoline

     23.54     9.62     9.05  

Heating Oil

     29.12     10.53     8.03  

NYMEX 2-1-1 Crack Spread

     26.33     10.07     8.54  

PADD II Group 3 Basis:

                    

Gasoline

     (1.09 )   (1.49 )   (1.25 )

Ultra-Low Sulfur Diesel

     1.98     1.35     0.03  

PADD II Group 3 Product Crack:

                    

Gasoline

     22.44     8.13     7.81  

Ultra-Low Sulfur Diesel

     31.10     11.88     8.06  

PADD II Group 3 2-1-1

     26.77     10.01     7.93  
(1)
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 the total direct operating expenses, which does not include depreciation or amortization expense, and divide by the applicable number of crude oil throughput barrels for the period.

(2)
In order to derive the gross profit per crude oil throughput barrel, we utilize the total dollar figures for gross profit as derived above and divide by the applicable number of crude oil throughput barrels for the period.

(3)
Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refineries' performance as a

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(4)
Adjusted Petroleum EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, net loss on disposition of fixed assets, major scheduled turnaround expenses, realized gain (loss) on derivatives, depreciation and amortization and other income (expense). Adjusted EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to adjusted EBITDA for the petroleum segment for the years ended December 31, 2011, 2010 and 2009:

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (unaudited)
  

Petroleum:

                    

Petroleum operating income

   $ 465.7   $ 104.6   $ 170.2  

FIFO impacts (favorable), unfavorable (a)

     (25.6 )   (31.7 )   (67.9 )

Share-based compensation

     8.7     11.5     (3.7 )

Loss on disposition of assets (b)

     2.5     1.3     —  

Major scheduled turnaround expenses (c)

     66.4     1.2     —  

Realized gain (loss) on derivatives, net

     (7.2 )   0.7     (21.0 )

Depreciation and amortization

     69.9     66.4     64.4  

Other income (expense)

     0.5     0.7     0.3  
               

Adjusted Petroleum EBITDA

   $ 580.9   $ 154.7   $ 142.3  

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(5)
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.

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (in millions)
  

Coffeyville Refinery Financial Results

                    

Net sales

   $ 4,643.9   $ 3,901.5   $ 2,932.5  

Cost of product sold (exclusive of depreciation and amortization)

     3,823.5     3,538.4     2,515.0  

Direct operating expenses (exclusive of depreciation and amortization)

     243.5     153.1     142.2  

Depreciation and amortization

     66.0     63.6     61.5  
               

Gross profit

   $ 510.9   $ 146.4   $ 213.8  

Plus direct operating expenses (exclusive of depreciation and amortization)

     243.5     153.1     142.2  

Plus depreciation and amortization

     66.0     63.6     61.5  
               

Refining margin

   $ 820.4   $ 363.1   $ 417.5  

Operating income

   $ 471.7   $ 104.8   $ 367.3  

Adjusted Coffeyville Refinery EBITDA

   $ 581.7   $ 152.4   $ 139.6  

 

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (dollars per barrel)
  

Coffeyville Refinery Key Operating Statistics

                    

Per crude oil throughput barrel:

                    

Refining margin

   $ 22.34   $ 8.78   $ 10.57  

Gross profit

     13.91     3.54     5.41  

Direct operating expenses (exclusive of depreciation and amortization)

     6.63     3.70     3.60  

Direct operating expenses per barrel sold

     6.45     3.30     3.22  

Barrels sold (barrels per day)

     103,430     127,142     125,005  

 

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   Year Ended December 31,  
 
   2011   2010   2009  
 
    
   %    
   %    
   %  

Coffeyville Refinery Throughput and Production Data (bpd)

                                      

Throughput:

                                      

Sweet

     80,835     76.6     89,746     72.5     82,598     68.7  

Light/medium sour

     1,323     1.3     8,180     6.6     15,602     13.0  

Heavy sour

     18,460     17.4     15,439     12.5     10,026     8.3  
                           

Total crude oil throughput

     100,618     95.3     113,365     91.6     108,226     90.0  

All other feedstocks and blendstocks

     4,921     4.7     10,350     8.4     12,013     10.0  
                           

Total throughput

     105,539     100.0     123,715     100.0     120,239     100.0  

Production:

                                      

Gasoline

     46,707     44.0     61,136     49.1     62,309     51.6  

Distillate

     44,414     41.9     50,439     40.5     46,909     38.8  

Other (excluding internally produced fuel)

     15,000     14.1     12,978     10.4     11,549     9.6  
                           

Total refining production (excluding internally produced fuel)

     106,121     100.0     124,553     100.0     120,767     100.0  

Average product sale price (dollars per gallon):

                                      

Gasoline

         $ 2.83         $ 2.10         $ 1.68  

Distillate

         $ 3.03         $ 2.20         $ 1.68  

        Net Sales.    Petroleum net sales were $4,751.8 million for the year ended December 31, 2011, compared to $3,903.8 million for the year ended December 31, 2010. The increase of $848.0 million was primarily the result of higher product prices which were partially offset by lower overall sales volumes. Overall sales volumes of refined fuels and propane decreased 11.5%. The lower overall sales volumes were primarily the result of the major maintenance turnaround at our Coffeyville refinery in the fall of 2011. Our average sales price per gallon of $2.82 for gasoline and $3.03 for distillates increased by 33.9% and 38.0% respectively.

 
    
    
    
   Year Ended December 31, 2010    
    
    
    
  
 
   Year Ended December 31, 2011   Total Variance    
    
  
 
    
   $ per barrel    
   Volume
Variance 		  Price
Variance 		 
 
   Volume(1)   $ per barrel   Sales $(2)   Volume(1)   Sales $(2)   Volume(1)   Sales $(2)  
 
    
    
    
    
    
    
    
    
   (in millions)
  

Gasoline

     19.7   $ 118.35   $ 2,337.2     23.1   $ 88.38   $ 2,038.2     (3.4 ) $ 299.0   $ 690.9   $ (391.9 )

Distillate

     16.6   $ 127.25   $ 2,114.8     18.6   $ 92.22   $ 1,718.3     (2.0 ) $ 396.5   $ 652.6   $ (256.1 )
(1)
Barrels in millions

(2)
Sales dollars in millions

        Cost of Products Sold (Exclusive of Depreciation and Amortization).    Cost of products sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of products sold (exclusive of depreciation and amortization) was $3,926.6 million for the year ended December 31, 2011, compared to $3,538.0 million for the year ended December 31, 2010. The increase of $388.6 million was primarily the result of a significant increase in crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2011 was $92.09, compared to $76.13 for the year ended December 31, 2010, an increase of approximately 21.0%. Partially offsetting the rise in crude oil consumed cost was the decrease of sales of refined fuels by approximately 11.5%. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the

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inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. For the year ended December 31, 2011, we had a favorable FIFO impact of $25.6 million compared to a favorable FIFO impact of $31.7 million for the year ended December 31, 2010.

        Refining margin per barrel of crude oil throughput increased from $8.84 for the year ended December 31, 2010 to $21.80 for the year ended December 31, 2011. Refining margin adjusted for FIFO impact was $21.12 per barrel of crude oil throughput for the year ended December 31, 2011, as compared to $8.07 per crude oil throughput barrel for the year ended December 31, 2010. Gross profit per barrel increased to $13.41 for the year ended December 31, 2011, as compared to gross profit per barrel of $3.54 in the equivalent period in 2010. The increase in our refining margin per barrel is due to an increase in the average sales prices of our produced gasoline and distillates, partially offset by an increase in our cost of consumed crude oil. Our average sales price for gasoline increased approximately 33.9% and our average sales price for distillates increased approximately 38.0%. Consumed crude oil costs rose due to a 19.5% increase in WTI for the year ended December 31, 2011 over the year ended December 31, 2010.

        Effective January 1, 2011, our Coffeyville refinery became subject to the provisions of the Renewable Fuel Standards, which mandates the use of renewable fuels. To meet this mandate, we must either blend renewable fuels into gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs) in lieu of blending. As a result of this mandate, we incurred an additional $19.0 million of expense for the year ended December 31, 2011 which is reflected in our cost of products sold (exclusive of depreciation and amortization).

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refineries, such as energy and utility costs, property taxes, catalyst and chemicals, repairs and maintenance, turnaround maintenance, labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $247.7 million for the year ended December 31, 2011, compared to direct operating expenses of $153.1 million for the year ended December 31, 2010. The increase of $94.6 million was the result of increases in expenses primarily related with turnaround maintenance ($65.2 million), environmental compliance ($7.8 million), repairs and maintenance ($6.4 million), labor ($6.2 million), outside services ($2.5 million), catalyst and chemicals ($2.4 million), operating supplies ($2.2 million), rent ($1.3 million) and other direct operating expenses ($0.6 million). On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2011 increased to $6.54 per barrel as compared to $3.70 per barrel for the year ended December 31, 2010, principally due to the net dollar increase in expenses from year to year as detailed above.

        Operating Income.    Petroleum operating income was $465.7 million for the year ended December 31, 2011 as compared to operating income of $104.6 million for the year ended December 31, 2010. This increase of $361.1 million was primarily the result of an increase in refining margin ($459.4 million). The increase in refining margin was partially offset by an increase in direct operating expenses ($94.6 million), an increase in depreciation and amortization ($3.5 million) and an increase in selling, general and administrative expense ($0.2 million).

        Net Sales.    Petroleum net sales were $3,903.8 million for the year ended December 31, 2010, compared to $2,934.9 million for the year ended December 31, 2009. The increase of $968.9 million was primarily the result of higher product prices and overall higher sales volumes. Overall sales

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volumes of refined fuels and propane for the year ended December 31, 2010 increased 5%, as compared to the year ended December 31, 2009. Our average sales price per gallon for the year ended December 31, 2010 for gasoline of $2.10 and distillate of $2.20 increased by 25% and 31%, respectively, as compared to the year ended December 31, 2009. The refinery operated at 99% of its capacity during 2010 despite 16 days of unplanned outage of its FCCU that reduced crude oil runs in the second and fourth quarters and a planned eight day turnaround of one of its crude oil units in the first quarter.

 
   Year Ended December 31, 2010   Year Ended December 31, 2009    
    
    
    
  
 
   Total Variance    
    
  
 
    
   $ per barrel    
    
   $ per barrel    
   Volume
Variance 		  Price
Variance 		 
 
   Volume(1)   Sales $(2)   Volume(1)   Sales $(2)   Volume(1)   Sales $(2)  
 
    
    
    
    
    
    
    
    
   (in millions)
  

Gasoline

     23.1   $ 88.38   $ 2,038.2     22.9   $ 70.40   $ 1,614.6     0.2   $ 423.6   $ 11.0   $ 412.6  

Distillate

     18.6   $ 92.22   $ 1,718.3     17.0   $ 70.74   $ 1,200.4     1.6   $ 517.9   $ 153.4   $ 364.5  
(3)
Barrels in millions

(4)
Sales dollars in millions

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $3,538.0 million for the year ended December 31, 2010, compared to $2,514.3 million for the year ended December 31, 2009. The increase of $1,023.7 million was primarily the result of a significant increase in crude oil prices. Our average cost per barrel of crude oil consumed for the year ended December 31, 2010 was $76.13, compared to $57.46 for the year ended December 31, 2009, an increase of approximately 32%. Sales volumes of refined fuels increased approximately 5%. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in a favorable FIFO impact when crude oil prices increase and an unfavorable FIFO impact when crude oil prices decrease. For the year ended December 31, 2010, we had a favorable FIFO impact of $31.7 million compared to a favorable FIFO impact of $67.9 million for the year ended December 31, 2009.

        Refining margin per barrel of crude oil throughput decreased from $10.65 for the year ended December 31, 2009 to $8.84 for the year ended December 31, 2010. Refining margin adjusted for FIFO impact was $8.07 per crude oil throughput barrel for the year ended December 31, 2010, as compared to $8.93 per crude oil throughput barrel for the year ended December 31, 2009. Gross profit per barrel decreased to $3.54 for the year ended December 31, 2010 as compared to gross profit per barrel of $5.42 in the equivalent period in 2009. The decline of our refining margin per barrel is due to an increase in our cost of consumed crude oil, partially offset by an increase in the average sales prices of our produced gasoline and distillates. Consumed crude oil costs rose due to a 28% increase in WTI and a 27% decrease in our consumed crude oil discount to WTI as a result of our refinery processing a sweeter crude oil slate for the year ended December 31, 2010 over the year ended December 31, 2009 and a weakening of the Contango in the U.S. crude oil market. Our average sales price of gasoline increased approximately 25% and our average sales price for distillates increased approximately 31% for the year ended December 31, 2010 over the comparable period of 2009.

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Direct operating expenses (exclusive of depreciation and amortization) for our petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, property taxes, catalyst and production chemicals costs, repairs and maintenance (turnaround), labor and environmental compliance costs. Petroleum direct operating expenses (exclusive of depreciation and amortization) were $153.1 million for the year ended December 31, 2010, compared to direct operating expenses of $142.2 million for the year ended December 31, 2009. The increase of $10.9 million was the result of increases in expenses primarily associated with direct labor ($6.4 million), repairs and maintenance

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($4.8 million), utilities and energy ($4.6 million) and rent ($1.5 million). The increase in labor costs over 2009 was the result of increased contract labor maintenance personnel and the increase in full-time equivalents, coupled with an increase in share-based compensation expense. The increase in repairs and maintenance was the result of costs incurred with work associated with various refinery units, expenses incurred for the pre-planning associated with the 2011/2012 major scheduled turnaround and opportunistic maintenance costs. The increase in utilities and energy was primarily driven by increased natural gas and electricity prices coupled with an increase in energy consumption. The increases were partially offset by decreases in expenses associated with production chemicals ($2.7 million), flood-related costs ($1.6 million), insurance ($1.2 million) and other direct operating expenses ($0.9 million). The decrease in production chemicals expense was the result of a decrease in consumption. On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2010 increased to $3.70 per barrel, as compared to $3.60 per barrel for the year ended December 31, 2009, principally due to the net dollar increase in expenses from year to year as detailed above.

        Operating Income.    Petroleum operating income was $104.6 million for the year ended December 31, 2010 as compared to operating income of $170.2 million for the year ended December 31, 2009. This decrease of $65.6 million was primarily the result of a decline in the refining margin ($54.8 million), an increase in direct operating expenses ($12.5 million) and an increase in depreciation and amortization ($2.0 million). The decrease in refining margin and increases in direct operating expenses and depreciation and amortization were partially offset by a decrease in flood related costs ($1.6 million) and in selling, general and administrative expenses ($2.1 million).

        The tables below provide an overview of the nitrogen fertilizer business' results of operations, relevant market indicators and its key operating statistics during the past three years:

 
   Year Ended December 31,  
Nitrogen Fertilizer Business Financial Results
  2011   2010   2009  
 
   (in millions)
  

Net sales

   $ 302.9   $ 180.5   $ 208.4  

Cost of product sold (exclusive of depreciation and amortization)

     42.5     34.3     42.2  

Direct operating expenses (exclusive of depreciation and amortization)

     86.5     86.7     84.5  

Insurance recovery — business interruption

     (3.4 )   —     —  

Depreciation and amortization

     18.9     18.5     18.7  

Operating income

     136.2     20.4     48.9  

Adjusted Nitrogen Fertilizer (EBITDA)(1)

     162.6     52.6     70.8  

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   Year Ended December 31,  
Key Operating Statistics
  2011   2010   2009  

Production (thousand tons):

                    

Ammonia (gross produced)(2)

     411.2     392.7     435.2  

Ammonia (net available for sale)(2)

     116.8     155.6     156.6  

UAN

     714.1     578.3     677.7  

Pet coke consumed (thousand tons)

     517.3     436.3     483.5  

Pet coke (cost per ton)

   $ 33   $ 17   $ 27  

Sales (thousand tons)(3):

                    

Ammonia

     112.8     164.7     159.9  

UAN

     709.3     580.7     686.0  
               

Total sales

     822.1     745.4     845.9  

Product pricing (plant gate) (dollars per ton)(3):

                    

Ammonia

   $ 579   $ 361   $ 314  

UAN

   $ 284   $ 179   $ 198  

On-stream factor(4):

                    

Gasification

     99.0 %   89.0 %   97.4 %

Ammonia

     97.7 %   87.7 %   96.5 %

UAN

     95.5 %   80.8 %   94.1 %

Reconciliation to net sales (dollars in millions):

                    

Freight in revenue

   $ 22.1   $ 17.0   $ 21.3  

Hydrogen revenue

     14.2     0.1     0.8  

Sales net plant gate

     266.6     163.4     186.3  
               

Total net sales

   $ 302.9   $ 180.5   $ 208.4  

 

 
   Year Ended December 31,  
Market Indicators
  2011   2010   2009  

Natural gas NYMEX (dollars per MMBtu)

   $ 4.03   $ 4.38   $ 4.16  

Ammonia — Southern Plains (dollars per ton)

   $ 619   $ 437   $ 306  

UAN — Mid Cornbelt (dollars per ton)

   $ 379   $ 266   $ 218  
(1)
Adjusted Nitrogen Fertilizer EBITDA represents operating income adjusted for share-based compensation, loss on disposition of assets, major scheduled turnaround expenses, depreciation and amortization and other income (expense). Adjusted Nitrogen Fertilizer EBITDA by operating segment results from operating income by segment adjusted for items that we believe are needed in order to evaluate results in a more comparative analysis from period to period. Adjusted Nitrogen Fertilizer EBITDA by operating segment is not a recognized term under GAAP and should not be substituted for operating income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that Adjusted Nitrogen Fertilizer EBITDA by operating segment provides relevant and useful information that enables investors to better understand and evaluate our ongoing operating results and allows for greater transparency in the reviewing of our overall financial, operational and economic performance. Below is a reconciliation of operating income to Adjusted Nitrogen

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   Year Ended December 31,  
 
   2011   2010   2009  
 
   (unaudited)
  

Nitrogen Fertilizer:

                    

Nitrogen fertilizer operating income

   $ 136.2   $ 20.4   $ 48.9  

Share-based compensation

     7.3     9.0     3.2  

Loss on disposition of assets(a)

     —     1.4     —  

Major scheduled turnaround expenses(b)

     —     3.5     —  

Depreciation and amortization

     18.9     18.5     18.7  

Other income (expense)

     0.2     (0.2 )   —  
               

Adjusted Nitrogen Fertilizer EBITDA

   $ 162.6   $ 52.6   $ 70.8  
(2)
The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN.

(3)
Plant gate sales per ton represent net sales less freight costs and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.

(4)
On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of major scheduled turnaround, the Linde air separation unit outage and the UAN vessel rupture, (i) the on-stream factors in 2011 adjusted for these events would have been 99.2% for gasifier, 98.0% for ammonia and 95.7% for UAN, (ii) the on-stream factors in 2010 adjusted for the Linde air separation unit outage would have been 97.6% for gasifier, 96.8% for ammonia and 96.1% for UAN, and (iii) the on-stream factors in 2009 adjusted for major scheduled turnaround would have been 99.3% for gasifier, 98.4% for ammonia and 96.1% for UAN.

        Net Sales.    Nitrogen fertilizer net sales were $302.9 million for the year ended December 31, 2011, compared to $180.5 million for the year ended December 31, 2010, an increase of $122.4 million. For the year ended December 31, 2011, ammonia, UAN and hydrogen made up $67.2 million, $221.5 million and $14.2 million of the nitrogen fertilizer business' net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $63.0 million, $117.4 million and $0.1 million for the year ended December 31, 2010, respectively. The increase of $122.4 million was the result of higher UAN sales volumes coupled with increased ammonia and UAN plant gate prices. This increase was partially offset by lower ammonia sales volumes. Both UAN and ammonia sales for the year ended December 31, 2010 were negatively impacted by the downtime associated with the major scheduled turnaround; however, UAN production and sales were impacted additionally by the downtime

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associated with the September 30, 2010 rupture of a high-pressure UAN vessel. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia, UAN and hydrogen.

 
   Year Ended December 31, 2011   Year Ended December 31, 2010    
    
    
    
  
 
   Total Variance    
    
  
 
    
   $ per ton(2)    
    
   $ per ton(2)    
   Price
Variance 		  Volume
Variance 		 
 
   Volume(1)   Sales $(3)   Volume(1)   Sales $(3)   Volume(1)   Sales $(3)  
 
   (in millions)
  

Ammonia

     112,775   $ 596   $ 67.2     164,668   $ 382   $ 63.0     (51,894 ) $ 4.2   $ 35.2   $ (31.0 )

UAN

     709,280   $ 312   $ 221.5     580,684   $ 202   $ 117.4     128,595   $ 104.1   $ 63.9   $ 40.2  

Hydrogen

     1,389,796   $ 10   $ 14.2     20,583   $ 7   $ 0.1     1,369,213   $ 14.1   $ 0.1   $ 14.0  
(1)
Sales volume in tons.

(2)
Includes freight charges.

(3)
Sales dollars in millions.

        In regard to product sales volumes for the year ended December 31, 2011, the nitrogen fertilizer operations experienced a decrease of 31.5% in ammonia sales unit volumes and an increase of 22.1% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2011 compared to 2010 were higher for all units of the nitrogen fertilizer operations, primarily due to the 2010 major scheduled turnaround, the rupture of a high pressure UAN vessel and unscheduled downtime associated with the Linde air separation unit outage. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.

        Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer's designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the year ended December 31, 2011 for ammonia were higher than plant gate prices for the year ended December 31, 2010 by approximately 60.3% and plant gate prices for UAN were approximately 58.6% higher during the year ended December 31, 2011 than the plant gate prices for the year ended December 31, 2010.

        Insurance Recovery — Business Interruption.    During the year ended December 31, 2011, we recorded and received insurance proceeds under insurance coverage for interruption of business of $3.4 million related to the September 30, 2010 UAN vessel rupture

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2011 was $42.5 million, compared to $34.3 million for the year ended December 31, 2010. Of this $8.2 million increase, $5.9 million resulted from higher costs from transactions with affiliates and $2.3 million from higher costs from third parties. Besides increased costs associated with higher UAN sales volumes and $4.8 million of increased freight expenses, we experienced an increase in pet coke costs of $9.5 million ($6.7 million from transactions with affiliates). These increased costs were partially offset by a decrease in costs associated with lower ammonia sales and a decrease in hydrogen costs ($0.8 million).

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and

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environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2011 were $86.5 million, as compared to $86.7 million for the year ended December 31, 2010. The decrease of $0.2 million was due to a $1.1 million decrease in costs from transactions with affiliates, coupled with a $0.9 million increased direct operating costs from third parties. The $0.2 million net decrease was primarily the result of decreases in expenses associated with the turnaround ($3.5 million), net UAN reactor repairs and maintenance expense ($3.4 million), equipment rent ($0.5 million), labor ($0.4 million) and increased reimbursed expenses ($1.5 million). The turnaround expenses for 2010 are the result of the nitrogen fertilizers business' biennial turnaround. These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ($5.4 million), repairs and maintenance ($3.1 million), catalyst ($0.3 million) and environmental ($0.3 million).

        Operating Income.    Nitrogen fertilizer operating income was $136.2 million for the year ended December 31, 2011, as compared to operating income of $20.4 million for the year ended December 31, 2010. The increase of $115.8 million was the result of the increase in nitrogen fertilizer margins ($114.3 million) coupled with business interruption recoveries recorded ($3.4 million) and decreased direct operating costs ($0.2 million). These favorable increases were partially offset by an increase in selling, general and administrative expenses (exclusive of depreciation and amortization) ($1.6 million) and depreciation and amortization ($0.4 million).

        Net Sales.    Nitrogen fertilizer net sales were $180.5 million for the year ended December 31, 2010, compared to $208.4 million for the year ended December 31, 2009. For the year ended December 31, 2010, ammonia, UAN and hydrogen made up $63.0 million, $117.4 million and $0.1 million of the nitrogen fertilizer business' net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $54.6 million, $153.0 million and $0.8 million for the year ended December 31, 2009, respectively. The decrease of $27.9 million was the result of a decline in average UAN plant gate prices coupled with a decline in UAN sales volumes. This decrease was partially offset by higher ammonia sales volumes coupled with higher ammonia prices on a year-over-year basis. Both UAN and ammonia sales were impacted by the downtime associated with the major scheduled turnaround, however, UAN production and sales were impacted additionally by the downtime associated with the rupture of a high-pressure UAN vessel. The UAN vessel ruptured on September 30, 2010 and production of UAN did not commence until November 16, 2010. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia and UAN for the year ended December 31, 2010 compared to the year ended December 31, 2009.

 
   Year Ended December 31, 2010   Year Ended December 31, 2009   Total Variance    
    
  
 
   Volume
Variance 		  Price
Variance 		 
 
   Volume(1)   $ per ton   Sales $(2)   Volume(1)   $ per ton   Sales $(2)   Volume(1)   Sales $(2)  
 
    
    
    
    
    
    
    
    
   (in millions)
  

Ammonia

     164,668   $ 382   $ 63.0     159,860   $ 342   $ 54.6     4,808   $ 8.4   $ 1.9   $ 6.5  

UAN

     580,684   $ 202   $ 117.4     686,009   $ 223   $ 153.0     (105,325 ) $ (35.6 ) $ (21.4 ) $ (14.2 )
(1)
Sales volume in tons.

(2)
Sales dollars in millions.

        In regard to product sales volumes for the year ended December 31, 2010, the nitrogen fertilizer operations experienced an increase of 3% in ammonia sales unit volumes and a decrease of 15% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2010 compared to 2009 were lower for all units of the nitrogen fertilizer operations, primarily due to unscheduled downtime associated with the Linde air separation unit

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outage, the UAN vessel rupture and the completion of the biennial scheduled turnaround for the nitrogen fertilizer plant completed in the fourth quarter of 2010. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.

        Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer's designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the year ended December 31, 2010 for ammonia were greater than plant gate prices for the year ended December 31, 2009 by approximately 15%. Conversely, UAN plant gate prices for UAN were approximately 10% lower during the year ended December 31, 2010 than the plant gate prices for the year ended December 31, 2009. The fertilizer industry experienced an unprecedented pricing cycle starting in 2008. Significant increases in average plant gate prices for 2008 prices had a carryover affect on 2009 average UAN prices primarily for the first half of 2009, before they began to decrease in the last half of 2009 and into the first half of 2010. Average ammonia plant gate prices for 2009 were negatively impacted by the lack of a fall planting season and rebounded in 2010 due to increased fall planting season demand.

        Cost of Product Sold (Exclusive of Depreciation and Amortization).    Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of petroleum coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2010 was $34.3 million, compared to $42.2 million for the year ended December 31, 2009. The decrease of $7.9 million was primarily the result of a decrease in pet coke costs of $5.5 million and the remaining decrease of $2.4 million was primarily attributable to lower UAN sales volume (105,325 tons) driven by downtime associated with the major scheduled turnaround and the September 2010 UAN vessel rupture.

        Direct Operating Expenses (Exclusive of Depreciation and Amortization).    Direct operating expenses (exclusive of depreciation and amortization) for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2010 were $86.7 million, as compared to $84.5 million for the year ended December 31, 2009. The increase of $2.2 million was primarily the result of increases in expenses associated with the turnaround ($3.5 million), property taxes ($2.5 million), net UAN reactor repairs and maintenance expense ($1.5 million), labor ($1.4 million) and refractory brick amortization ($0.7 million). The turnaround expenses for 2010 are the result of the nitrogen fertilizers business' biennial turnaround. The increase in property taxes for the year ended December 31, 2010 was the result of an increased valuation assessment on the nitrogen fertilizer plant as well as the expiration of a tax abatement for the Linde air separation unit for which we pay taxes in accordance with our agreement with Linde. These increases in direct operating expenses were partially offset by decreases in expenses associated with energy and utilities ($6.0 million), catalyst ($1.1 million) and insurance ($0.7 million). The majority of the decrease in energy and utilities expenses reflects a $4.8 million settlement of an electric rate case with the City of Coffeyville in the third quarter of 2010. This $4.8 million refund of amounts paid between August 2008 through July 2010 is a one-time event.

        Operating Income.    Nitrogen fertilizer operating income was $20.4 million for the year ended December 31, 2010, or 11% of net sales, as compared to $48.9 million for the year ended December 31, 2009, or 23% of net sales. This decrease of $28.5 million was the result of a decline in the nitrogen fertilizer margin ($20.0 million), increases in selling, general and administrative expenses

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($6.4 million), primarily attributable to an increase in share-based compensation expense, and an increase in direct operating expenses (exclusive of depreciation and amortization) ($2.2 million).


Liquidity and Capital Resources

        Although results are consolidated for financial reporting, we and the Partnership operate with independent capital structures. Since the Partnership's IPO in April 2011, with the exception of cash distributions paid to us by the Partnership, the cash needs of each entity have been met independently with a combination of existing cash and cash equivalent balances, cash generated from operating activities and credit facility borrowings. We expect that our cash needs and the cash needs of the Partnership will continue to be met independently of each other with a combination of these funding sources. Our and the Partnership's ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.

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

        As of December 31, 2011, we had consolidated cash and cash equivalents of $388.3 million. Of that amount, $151.3 million was cash and cash equivalents of ours, and $237.0 million was cash and cash equivalents of the Partnership. During 2011, our consolidated cash position increased approximately $188.3 million primarily as a result of increased operating and financing cash flows at the Partnership. In addition, we acquired $6.3 million in cash as a result of the Wynnewood Acquisition. As discussed below, the first priority credit facility was terminated on February 22, 2011 and was replaced with an asset-backed revolving credit facility. Our availability under the credit facility is reduced by outstanding letters of credit. As of February 24, 2012, we had $368.2 million available under the ABL credit facility and had consolidated cash and cash equivalents of approximately $314.2 million.

        On February 22, 2011, CRLLC and certain subsidiaries entered into a $250.0 million asset-backed revolving credit agreement ("ABL credit facility") with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. On December 15, 2011, in connection with the Wynnewood Acquisition, CRLLC and the other borrowers under the ABL credit facility entered into a $150.0 million incremental commitment agreement with a group of lenders including Deutsche Bank Trust Company Americas pursuant to which the commitments under the ABL credit facility were increased to $400.0 million. The ABL credit facility is scheduled to mature in August 2015. The ABL credit facility is used to finance ongoing working capital, capital expenditures, letters of credit issuance and general needs of the Company and includes among other things, a letter of credit sublimit equal to 90% of the total facility commitment and a feature which permits an increase in borrowings of up to an additional $250.0 million (in the aggregate), subject to additional lender commitments.

        On April 6, 2010, CRLLC and its wholly-owned subsidiary, Coffeyville Finance Inc. (together the "Issuers"), completed the private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due April 1, 2015 (the "First Lien Notes") and $225.0 million aggregate

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principal amount of 10.875% Second Lien Senior Secured Notes due April 1, 2017 (the "Second Lien Notes" and together with the First Lien Notes, the "Notes"). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, we made a voluntary unscheduled principal payment of $27.5 million on our First Lien Notes. As a result of this payment, we were required to pay a 3.0% premium totaling approximately $0.8 million. Additionally, an adjustment was made to our previously deferred financing costs, underwriting discount and original issue discount of approximately $0.8 million. The premium payment and write-off of previously deferred financing costs, underwriting discount and original issue discount were recognized as a loss on extinguishment of debt. On May 16, 2011, we repurchased $2.7 million of the Notes at a purchase price of 103% of the outstanding principal amount, as discussed below in further detail. On December 15, 2011, we issued an additional $200.0 million of our 9% First Lien Senior Secured Notes to partially fund the Wynnewood Acquisition. The New Notes were issued at 105% of their principal amount. As of December 31, 2011, the Notes had an aggregate principal balance of $669.8 million and a net carrying value of $676.6 million.

        The First Lien Notes were issued pursuant to an indenture (the "First Lien Notes Indenture"), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the "First Lien Notes Trustee"). The Second Lien Notes were issued pursuant to an indenture (the "Second Lien Notes Indenture" and together with the First Lien Notes Indenture, the "Indentures"), dated April 6, 2010, among the Issuers, the guarantors party thereto and Wells Fargo Bank, National Association, as trustee (the "Second Lien Notes Trustee" and in reference to the Indentures, the "Trustee"). The Notes are fully and unconditionally guaranteed by each of the Company's subsidiaries that also guarantee the first priority credit facility (the "Guarantors" and, together with the Issuers, the "Credit Parties").

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

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

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

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

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

        The Indentures also allowed the Company to sell, spin-off or complete an initial public offering of the Partnership, as long as the Issuers offer to buy back a percentage of the Notes as described in the Indentures. In April 2011, the Partnership completed an initial public offering of common units. This offering triggered a Fertilizer Business Event (as defined in the Indentures). As a result, the Issuers were required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103.0% of the principal amount plus accrued and unpaid interest. A Fertilizer Business Event Offer (as defined in the Indentures) was made on April 14, 2011 to purchase up to $100.0 million of the First Lien Notes and the Second Lien Notes. Holders of $2.7 million of the Notes tendered their Notes to the Company. The Company repurchased the Notes in accordance with the terms of the tender offer.

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

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pursuit of other available remedies. We were in compliance with the covenants as of December 31, 2011.

        The obligations of the Credit Parties under the Notes and the guarantees are secured by liens on substantially all of the Credit Parties' assets. The First Lien Notes are secured by first-priority liens on our fixed assets and a second priority lien on our inventory. The liens granted in connection with the Second Lien Notes rank junior to the liens in respect of the First Lien Notes.

        CRLLC entered into a $250.0 million ABL credit facility on February 22, 2011, which was expanded to a $400.0 million ABL Credit Facility on December 15, 2011 in connection with the Wynnewood Acquisition. The ABL Credit Facility provides for borrowings, letter of credit issuances and a feature that permits an increase of borrowings up to an additional $100.0 million (in the aggregate) subject to additional lender commitments. The ABL credit facility is scheduled to mature in August 2015 and will be used to finance ongoing working capital, capital expenditures, letter of credit issuances and general needs of the Company and includes, among other things, a letter of credit sublimit equal to 90% of the total commitment.

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

        Under its terms, the lenders under the ABL credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in the ABL Priority Collateral (as defined in the ABL Intercreditor Agreement) and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).

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

Partnership Credit Facility

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

        Borrowings under the Partnership 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 Partnership credit facility is the Eurodollar rate plus a margin of 3.50%, or for base rate loans, or the

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prime rate plus 2.50%. Under its terms, the lenders under the Partnership credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CRNF and the Partnership and all of the capital stock of CRNF and each domestic subsidiary owned by the Partnership or CRNF. CRNF is the borrower under the Partnership credit facility. All obligations under the Partnership credit facility are unconditionally guaranteed by the Partnership and substantially all of its future, direct and indirect, domestic subsidiaries. Borrowings under the credit facility are non-recourse to the Company and its direct subsidiaries.

        As of December 31, 2011, no amounts were drawn under the Partnership's $25.0 million revolving credit facility.

Partnership Interest Rate Swap

        Our and the Partnership's profitability and cash flows are affected by changes in interest rates on our credit facility borrowings, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our and the Partnership's exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates we pay on our borrowings from a floating rate to a fixed interest rate.

        On June 30 and July 1, 2011, the Partnership's CRNF subsidiary entered into two Interest Rate Swap agreements with J. Aron. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. These Interest Rate Swap agreements commenced on August 12, 2011. The impact recorded for the year ended December 31, 2011 is $0.4 million in interest expense. For the year ended December 31, 2011, the Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $2.4 million, which is unrealized in accumulated other comprehensive income.

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

        The following table summarizes our and the Partnership's total actual capital expenditures for 2011 and current estimated capital expenditures in 2012 by operating segment and major category. These

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estimates may change as a result of unforeseen circumstances or a change in our plans, and amounts may not be spent in the manner allocated below:

 
   Year Ended December 31,  
 
   2011 Actual   2012 Estimate  
 
   (in millions)
  

Petroleum Business:

              

Coffeyville refinery:

              

Maintenance

     49.5     70.3  

Growth

     6.8     2.5  
           

Coffeyville refinery total capital excluding turnaround expenditures

     56.3     72.8  

Wynnewood refinery:(1)

              

Maintenance

     0.5     58.7  

Growth

     —     7.6  
           

Wynnewood refinery total capital excluding turnaround expenditures

     0.5     66.3  

Other Petroleum:

              

Maintenance

     0.4     10.9  

Growth

     11.4     14.6  
           

Other petroleum total capital excluding turnaround expenditures

     11.8     25.5  
           

Petroleum business total capital excluding turnaround expenditures

     68.6     164.6  
           

Nitrogen Fertilizer Business (the Partnership):

              

Maintenance

     6.2     9.7  

Growth

     12.9     100.1  
           

Nitrogen fertilizer business total capital excluding turnaround expenditures

     19.1     109.8  
           

Corporate

     3.5     3.9  
           

Total capital spending

   $ 91.2   $ 278.3  
           

        During the fourth quarter of 2011, we completed the first phase of a planned two-phase turnaround of the Coffeyville refinery. In connection with this turnaround, we incurred approximately $66.4 million and $1.2 million of expense in 2011 and 2010, respectively. In connection with the turnaround, we also expensed approximately $1.0 million of fixed assets. We expect to incur approximately $31.7 million of expenses during 2012 related to the second phase of the Coffeyville turnaround, which is scheduled to begin during the first quarter of 2012. In addition, the Wynnewood refinery is scheduled to begin turnaround maintenance in the fourth quarter of 2012. We expect to incur approximately $85.0 million of expenses during 2012 related to the Wynnewood turnaround.

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        Included in the above 2012 estimated capital expenditures is $8.0 million to complete the construction of an additional one million barrels of crude oil storage capacity in Cushing, Oklahoma. Owning our own storage facilities will provide us additional operational flexibility.

        Compliance with the Tier II Motor Vehicle Emission Standards Final Rule required us to spend approximately $0.9 million in 2011.

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

        With the closing of its IPO on April 13, 2011, the Partnership's nitrogen fertilizer business has moved forward with the planned UAN expansion. Inclusive of capital spent prior to the IPO, we anticipate that the total capital spend associated with the UAN expansion will approximate $135.0 million. As of December 31, 2011, approximately $43.6 million had been spent, including $12.6 million which was spent during the year ended December 31, 2011. The continuation of the UAN expansion is being funded by proceeds of the Partnership IPO and term loan borrowings made by the Partnership. It is anticipated that the UAN expansion will be completed in the first quarter of 2013.

        In October 2011, the board of directors of the Partnership's general partner approved a UAN terminal project, which will include the construction of a two million gallon UAN storage tank and related truck and rail car load-out facilities, to enable the Partnership to distribute up to approximately 20,000 tons of UAN fertilizer annually. The property that this terminal will be constructed on, located in Phillipsburg, Kansas and is owned by a subsidiary of CVR Energy, who will also operate the terminal. The expected cost of this project is approximately $2.0 million.


Cash Flows

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

 
   Year Ended December 31,  
 
   2011   2010   2009  
 
   (in millions)
  

Net cash provided by (used in):

                    

Operating activities

   $ 278.6   $ 225.4   $ 85.3  

Investing activities

     (674.4 )   (31.3 )   (48.3 )

Financing activities

     584.1     (31.0 )   (9.0 )
               

Net increase (decrease) in cash and cash equivalents

   $ 188.3   $ 163.1   $ 28.0  
               

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

        Net cash flows provided by operating activities for the year ended December 31, 2011 were $278.6 million. The positive cash flow from operating activities generated over this period was primarily driven by $378.6 million of net income before noncontrolling interest. This positive net income was primarily due to the operating margins for the period. The positive operating cash flow for the period was offset by unfavorable changes in trade working capital. Trade working capital for the year ended

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December 31, 2011 resulted in a reduction of cash flows of $114.3 million which was primarily attributable to the increase in inventories ($175.5 million) and an increase in accounts receivable ($55.4 million), both of which were partially offset by an increase in accounts payable of $5.8 million. Other working capital activities resulted in net cash outflow of $85.0 million and are primarily related to an increase in accrued income taxes ($35.8 million) and other current liabilities ($27.3 million). Significant uses of cash for the year ended December 31, 2011 included payments of income tax of approximately $182.6 million. In addition, we received insurance proceeds of approximately $10.1 million related to the UAN reactor rupture and refinery incidents. Approximately $7.4 million is included in cash flows from operating activities and the remaining balance is included in cash flows from investing activities.

        Net cash flows provided by operating activities for the year ended December 31, 2010 were $225.4 million. The positive cash flow from operating activities generated over this period was partially driven by $14.3 million of net income, favorable changes in trade working capital and other working capital. Trade working capital for the year ended December 31, 2010 resulted in a cash inflow of $41.6 million, primarily attributable to a decrease in inventory of $27.7 million, and an increase in accounts payable of $47.9 million, partially offset by an increase in accounts receivable of $34.0 million. Other working capital activities resulted in a net cash inflow of $23.8 million. This inflow was primarily driven by an increase in other accrued income taxes of $28.8 million, increased deferred revenue of $8.4 million associated with the nitrogen fertilizer business' prepaid sales orders and the receipt of income tax refunds and related interest of approximately $21.5 million. Additionally we received insurance proceeds of approximately $4.3 million related to the repairs, maintenance and other associated costs of the UAN vessel rupture, of which approximately $3.2 million is included in cash flows from operating activities and the remaining balance is included in cash flows from investing activities. These increases were offset by an outflow for monthly payments totaling $9.4 million related to our insurance premium financing arrangement. Also impacting other working capital is the decrease in prepaid assets and other current assets of $13.0 million.

        Net cash flows from operating activities for the year ended December 31, 2009 were $85.3 million. The positive cash flow from operating activities generated over this period was primarily driven by $69.4 million of net income, favorable changes in other working capital and other assets and liabilities offset by unfavorable changes in trade working capital over the period. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. For the year ended December 31, 2009, our net income was adversely impacted by both realized and unrealized losses of $55.2 million. Significant uses of cash for 2009 included the pay down of the J. Aron deferral totaling $62.4 million and the payment of $21.1 million for realized losses on the Cash Flow Swap. Partially offsetting the payments related to realized losses on the Cash Flow Swap was a cash receipt of $3.9 million related to the early termination of the Cash Flow Swap on October, 8, 2009 as well as additional insurance proceeds of $11.8 million. Other significant changes in working capital included a decrease of $12.1 million related to prepaid and other current assets and a decrease of $20.0 million of accrued income taxes. Trade working capital for the year-ended December 31, 2009 resulted in a use of cash of $133.9 million. This use of cash was the result of an inventory increase of $126.4 million, increased accounts receivable of $13.1 million, an increase in accounts payable by $0.7 million and the accrual of construction in progress of $5.0 million.

        Net cash used in investing activities for the year ended December 31, 2011 was $674.4 million compared to $31.3 million for the year ended December 31, 2010. The increase in investing activities was primarily the result of $586.0 million cash consideration paid for the acquisition of Gary-Williams Company. In addition, capital expenditures increased by $58.8 million primarily related to the

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petroleum business. For the year ended December 31, 2011, capital expenditures associated with the petroleum business totaled $68.6 million compared to $19.8 million for the year ended December 31, 2010. This $48.8 million increase was coupled with a $9.0 million increase in the nitrogen fertilizer business from $10.1 million for the year ended December 31, 2010 to $19.1 million for the year ended December 31, 2011. Significant capital expenditures for the year ended December 31, 2011 included expenditures for the expansion of the nitrogen fertilizers UAN plant, construction of crude oil storage in Cushing, Oklahoma and repairs and maintenance performed on various units at the Coffeyville refinery.

        Net cash used in investing activities for the year ended December 31, 2010 was $31.3 million compared to $48.3 million for the year ended December 31, 2009. The decrease in investing activities was the result of decreased capital expenditures primarily related to the petroleum business. For the year ended December 31, 2010, capital expenditures associated with the nitrogen fertilizer business totaled $10.1 million compared to $13.4 million for the year ended December 31, 2009. This decrease was coupled with a decrease of $14.2 million in petroleum capital expenditures for the comparable period. For the year ended December 31, 2010, petroleum capital expenditures totaled approximately $19.8 million compared to $34.0 million for the year ended December 31, 2009. Significant capital expenditures for the year ended December 31, 2010, included expenditures for the petroleum business' ultra-low sulfur gasoline unit and the nitrogen fertilizers business' UAN secondary reactor. Capital expenditures were partially offset by approximately $1.1 million of insurance proceeds received in connection with the rupture of the high-pressure UAN vessel.

        Net cash used in investing activities for the year ended December 31, 2009 was $48.3 million compared to $86.5 million for the year ended December 31, 2008. Significant capital expenditures for the year ended December 31, 2009, included expenditures for the petroleum business' ultra-low sulfur gasoline unit and the nitrogen fertilizers business' preliminary expenditures related to the UAN expansion. The decrease in investing activities for the year ended December 31, 2009 as compared to the year ended December 31, 2008 was primarily the result of reduced capital expenditures associated with various completed capital projects in our petroleum business in 2008.

        Net cash provided by financing activities for the year ended December 30, 2011 was approximately $584.1 million as compared to net cash used in financing activities of $31.0 million for the year ended December 31, 2010. The net cash provided by financing activities for the year ended December 31, 2011 was primarily attributable to the net proceeds received of $324.8 million from the Partnership IPO. Additionally, $125.0 million of proceeds was received by the Partnership from the issuance of long-term debt and $206.0 million was received upon issuance of additional notes. These proceeds were partially offset by cash outflows of $26.0 million by the Partnership to purchase CVR GP, LLC's incentive distribution rights. Financing costs of approximately $15.1 million paid during the period were primarily associated with the ABL credit facility, the credit facility of CRNF and the issuance of the additional notes. We repurchased $2.7 million of our Notes in accordance with the terms of a tender offer associated with the Partnership IPO. Additionally, we paid approximately $4.9 million toward our capital lease obligations primarily related to exercising our purchase option related to a corporate asset.

        For the year ended December 31, 2011, there were no borrowings or repayments under our first priority credit facility or ABL credit facility. As of December 31, 2011, there were no short-term borrowings outstanding under the ABL credit facility.

        Net cash used in financing activities for the year ended December 31, 2010, was $31.0 million as compared to net cash used in financing activities of $9.0 million for the year ended December 31, 2009. For the year ended December 31, 2010, we paid a $1.2 million scheduled principal payment in January 2010 on long-term debt and then made two voluntary unscheduled principal payments totaling

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$25.0 million in the first quarter of 2010 related to our long-term debt. On April 6, 2010, we paid off the remaining $453.3 million balance of our outstanding long-term debt under our first priority credit facility. This payoff was made possible by the issuances of Notes that resulted in net proceeds of $485.7 million. In addition, we paid $8.8 million of financing costs in connection with the fourth amendment to our first priority credit facility and issuance of the Notes. In connection with the Partnership IPO, $0.7 million of deferred costs were paid. In December 2010, we made a principal payment on our First Lien Notes of $27.5 million. The primary uses of cash for the year ended December 31, 2009 were $4.8 million of scheduled principal payments in long-term debt and $4.0 million for the payment of financing costs associated with the amendment to our outstanding first priority credit facility.

        For the year ended December 31, 2010, we borrowed and repaid $60.0 million in short-term borrowings. These borrowings were made from our first priority revolving credit facility and were for the purpose of facilitating our working capital needs. There were no short-term borrowings made in the fourth quarter of 2010. As of December 31, 2010, we had no short-term borrowings outstanding.

        Net cash used in financing activities for the year ended December 31, 2009 was $9.0 million as compared to net cash used by financing activities of $18.3 million for the year ended December 31, 2008. The primary uses of cash for the year ended December 31, 2009 were $4.8 million of scheduled principal payments in long-term debt and $4.0 million for the payment of financing costs associated with the amendment to our outstanding first priority credit facility. The primary uses of cash for the year ended December 31, 2008 were an $8.5 million payment for financing costs, $4.8 million of scheduled principal payments on our long-term debt and $4.0 million related to deferred costs associated with an abandoned initial public offering of the Partnership and CVR's proposed convertible debt offering.

        For the year ended December 31, 2009, we also utilized the first priority revolving credit facility to facilitate our working capital needs. The Company borrowed and repaid $87.2 million in short-term borrowings. Of these borrowings, $15.0 million was borrowed and repaid in the fourth quarter of 2009. As of December 31, 2009, we had no short-term borrowings outstanding.


Capital and Commercial Commitments

        In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 2011 relating to the Notes, the Partnership term loan, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following December 31, 2011 and thereafter. As of December 31, 2011, there were no amounts

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outstanding under the ABL credit facility. The following table assumes no borrowings are made under the first priority revolving credit facility.

 
   Payments Due by Period  
 
   Total   2012   2013   2014   2015   2016   Thereafter  
 
   (in millions)
  

Contractual Obligations

                                            

Long-term debt(1)

   $ 794.8   $ —   $ —   $ —   $ 447.1   $ 125.0   $ 222.7  

Operating leases(2)

     39.6     8.8     8.0     6.1     4.6     3.8     8.3  

Capital lease obligations(3)

     53.2     1.1     1.1     1.2     1.4     1.6     46.8  

Unconditional purchase obligations(4)

     904.0     102.2     101.2     101.2     93.8     94.2     411.4  

Environmental liabilities(5)

     2.2     0.5     0.2     0.2     0.2     0.1     1.0  

Interest payments(6)

     286.3     69.4     69.4     69.4     39.8     32.0     6.3  
                               

Total

   $ 2,080.1   $ 182.0   $ 179.9   $ 178.1   $ 586.9   $ 256.7   $ 696.5  

Other Commercial Commitments