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EX-31.1 - EX-31.1 - CVR ENERGY INCy90110exv31w1.htm
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EX-32.1 - EX-32.1 - CVR ENERGY INCy90110exv32w1.htm
EX-31.2 - EX-31.2 - CVR ENERGY INCy90110exv31w2.htm
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, 2010
    OR
o
  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
    For the transition period from          to          
 
Commission file number: 001-33492
 
CVR Energy, Inc.
(Exact name of registrant as specified in its charter)
     
Delaware   61-1512186
(State or Other Jurisdiction of
Incorporation or Organization)
  (I.R.S. Employer
Identification No.)
2277 Plaza Drive, Suite 500
Sugar Land, Texas
(Address of Principal Executive Offices)
  77479
(Zip Code)
 
Registrant’s telephone number, including area code:
(281) 207-3200
 
 
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   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 o     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.  o
 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer o Accelerated filer þ Non-accelerated filer o Smaller reporting company o
(Do not check if a smaller reporting company)
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes o     No þ
 
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant computed based on the New York Stock Exchange closing price on June 30, 2010 (the last day of the registrant’s second fiscal quarter) was $228,528,000.
 
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 March 2, 2011
 
Common Stock, par value $0.01 per share   86,413,781 shares
 
Documents Incorporated By Reference
 
     
Document
 
Parts Incorporated
 
Proxy Statement for the 2011 Annual Meeting of Stockholders to be held May 18, 2011   Items 10, 11, 12, 13 and 14 of Part III


 

 
TABLE OF CONTENTS
 
                 
        Page
 
PART I
 
Item 1.
    Business     3  
 
Item 1A.
    Risk Factors     17  
 
Item 1B.
    Unresolved Staff Comments     40  
 
Item 2.
    Properties     40  
 
Item 3.
    Legal Proceedings     40  
 
Item 4.
    (Removed and Reserved)     40  
 
PART II
 
Item 5.
    Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     41  
 
Item 6.
    Selected Financial Data     44  
 
Item 7.
    Management’s Discussion and Analysis of Financial Condition and Results of Operations     46  
 
Item 7A.
    Quantitative and Qualitative Disclosures About Market Risk     89  
 
Item 8.
    Financial Statements and Supplementary Data     91  
 
Item 9.
    Changes in and Disagreements With Accountants on Accounting and Financial Disclosure     143  
 
Item 9A.
    Controls and Procedures     143  
 
Item 9B.
    Other Information     143  
 
PART III
 
Item 10.
    Directors, Executive Officers and Corporate Governance     143  
 
Item 11.
    Executive Compensation     144  
 
Item 12.
    Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     144  
 
Item 13.
    Certain Relationships and Related Transactions, and Director Independence     144  
 
Item 14.
    Principal Accounting Fees and Services     144  
 
PART IV
 
Item 15.
    Exhibits, Financial Statement Schedules     144  


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GLOSSARY OF SELECTED TERMS
 
The following are definitions of certain industry 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.
 
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.
 
common units — The class of interests issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies.
 
contango market — Market situation in which prices for future delivery are higher than the current or spot market price of the commodity. The opposite of backwardation.
 
corn belt — The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin.
 
crack spread — A simplified calculation that measures the difference between the price for light products and crude oil. For example, the 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of distillate.
 
distillates — Primarily diesel fuel, kerosene and jet fuel.
 
ethanol — A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate.
 
farm belt — Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.


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feedstocks — Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
 
heavy crude oil — A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel.
 
independent petroleum refiner — A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties.
 
light crude oil — A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel.
 
Magellan — Magellan Midstream Partners L.P., a publicly traded company whose business is the transportation, storage and distribution of refined petroleum products.
 
MMBtu — One million British thermal units or Btu:  a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit.
 
natural gas liquids — Natural gas liquids, often referred to as NGLs, are both feedstocks used in the manufacture of refined fuels and are products of the refining process. Common NGLs used include propane, isobutane, normal butane and natural gasoline.
 
PADD II — Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.
 
plant gate price — the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excluding shipment costs.
 
petroleum coke (pet coke) — A coal-like substance that is produced during the refining process.
 
refined products — Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery.
 
sour crude oil — A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil.
 
spot market — A market in which commodities are bought and sold for cash and delivered immediately.
 
sweet crude oil — A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil.
 
throughput — The volume processed through a unit or a refinery or transported on a pipeline.
 
turnaround — A periodically required standard procedure to inspect, refurbish, repair and maintain the refinery or nitrogen fertilizer plant assets. This process involves the shutdown and inspection of major processing units and occurs every four to five years for the refinery and every two years for the nitrogen fertilizer plant.
 
UAN — An aqueous solution of urea and ammonium nitrate used as a fertilizer.
 
wheat belt — The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas.
 
WTI — West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an American Petroleum Institute gravity, or API gravity, between 39 and 41 degrees and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.
 
WTS — West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of between 30 and 32 degrees and a sulfur content of approximately 2.0 weight percent.
 
yield — The percentage of refined products that is produced from crude oil and other feedstocks.


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PART I
 
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 currently own all of the interests (other than the managing general partner interest and associated incentive distribution rights (the “IDRs”)) in CVR Partners, LP (the “Partnership”), a limited partnership which produces nitrogen fertilizers in the form of ammonia and UAN.
 
Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. In addition to the refinery, we own and operate supporting businesses that include:
 
  •  a crude oil gathering system with a gathering capacity of approximately 35,000 bpd serving Kansas, Oklahoma, western Missouri, and southwestern Nebraska which is supported by approximately 300 miles of Company owned and leased pipeline;
 
  •  a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg, Kansas and to customers at throughput terminals on Magellan and NuStar Energy, LP’s (“NuStar”) refined products distribution systems;
 
  •  a 145,000 bpd pipeline system that transports crude oil to our refinery with 1.2 million barrels of associated company-owned storage tanks and an additional 2.7 million barrels of leased storage capacity located at Cushing, Oklahoma; and
 
  •  storage and terminal facilities for refined fuels and asphalt in Phillipsburg, Kansas.
 
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 (based on data provided by Blue Johnson & Associates, Inc., “Blue Johnson”). 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, 2010, 2009 and 2008, we generated consolidated net sales of $4.1 billion, $3.1 billion and $5.0 billion, respectively, and operating income of $93.1 million, $208.2 million and $148.7 million, respectively. Our petroleum business generated $3.9 billion, $2.9 billion and $4.8 billion of net sales, for the years ended December 31, 2010, 2009 and 2008, respectively. Our nitrogen fertilizer business generated $180.5 million, $208.4 million and $263.0 million of net sales for the years ended December 31, 2010, 2009 and 2008, respectively. Our petroleum business generated operating income of $104.6 million, $170.2 million and $31.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Our nitrogen fertilizer business generated operating income of $20.4 million, $48.9 million and $116.8 million for the years ended December 31, 2010, 2009 and 2008, 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.
 
Our History
 
Our 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


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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:
 
  •  CALLC transferred all of its businesses to CVR Energy in exchange for all of CVR Energy’s common stock;
 
  •  CALLC was effectively split into two entities, with the Kelso Funds controlling CALLC and the Goldman Sachs Funds controlling Coffeyville Acquisition II LLC (“CALLC II”) and CVR Energy’s senior management receiving an equivalent position in each of the two entities;
 
  •  we transferred our nitrogen fertilizer business to the Partnership in exchange for all of the partnership interests in the Partnership; and
 
  •  we sold all of the interests of the managing general partner of the Partnership to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by our controlling stockholders, at that time, and senior management at fair market value on the date of the transfer.
 
CVR Energy consummated its initial public offering on October 26, 2007. CVR is subject to the rules and regulations of the New York Stock Exchange (“NYSE”) where its shares are traded under the symbol “CVI.” At December 31, 2010, approximately 40% of CVR’s outstanding shares were beneficially owned by the Goldman Sachs Funds (17%) and Kelso Funds (23%). Subsequent to December 31, 2010, the Goldman Sachs Funds and Kelso Funds completed a sale of shares pursuant to a registered public offering. As a result of this offering, the Goldman Sachs Funds are no longer shareholders of the Company and the Kelso Funds beneficially own approximately 9% of the Company as of the date of this Report.
 
On December 20, 2010, the Partnership filed a registration statement on Form S-1 (File No. 333-171270) (the “Registration Statement”) to effect an initial public offering of its common units representing limited partner interests. The number of common units to be sold in the offering has not yet been determined. The initial public offering is subject to numerous conditions, including, without limitation, market conditions, pricing, regulatory approvals (including clearance from the Securities and Exchange Commission (“SEC”)), compliance with contractual obligations, and reaching agreements with underwriters and lenders. Accordingly, the initial public offering may not occur on the terms described in the Registration Statement or at all. The Registration Statement is not effective and is currently under review by the SEC. Any comments issued by the SEC could be material and could require the Partnership to make material changes to the disclosures contained in the Registration Statement and this Form 10-K. We are not making any offers to sell, or soliciting any offers to buy, common units of the Partnership.


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Organizational Structure and Related Ownership as of March 1, 2011
 
The following chart illustrates our organizational structure and the organizational structure of the Partnership:
 
(ORGANISATION CHART)
 
 
* CVR GP, LLC, which we refer to as Fertilizer GP, is the managing general partner of CVR Partners, LP. As managing general partner, Fertilizer GP holds incentive distributions rights, or IDRs, which entitle it to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases its distributions above an amount specified in the limited partnership agreement.


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Petroleum Business
 
We operate a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. Our refinery’s production capacity represents approximately 15% of our region’s output. The facility is situated on approximately 440 acres in southeast Kansas, approximately 100 miles from Cushing, Oklahoma, a major crude oil trading and storage hub.
 
For the year ended December 31, 2010, our refinery’s product yield included gasoline (mainly regular unleaded) (49%), diesel fuel (primarily ultra low sulfur diesel) (41%), and pet coke and other refined products such as NGC (propane, butane), slurry, sulfur and gas oil (10%).
 
Our petroleum business also includes the following auxiliary operating assets:
 
  •  Crude Oil Gathering System.  We own and operate a crude oil gathering system serving Kansas, Oklahoma, western Missouri and southwestern Nebraska. The system has field offices in Bartlesville, Oklahoma and Plainville and Winfield, Kansas. The system is comprised of approximately 300 miles of feeder and trunk pipelines, 95 trucks, and associated storage facilities for gathering sweet Kansas, Nebraska, Oklahoma and Missouri crude oils purchased from independent crude oil producers. We also lease a section of a pipeline from Magellan, which is incorporated into our crude oil gathering system. Our crude oil gathering system has a gathering capacity of approximately 35,000 bpd. Gathered crude oil provides a base supply of feedstock for our refinery and serves as an attractive and competitive supply of crude oil. During 2010, we gathered an average of approximately 31,000 bpd.
 
  •  Phillipsburg Terminal.  We own storage and terminalling facilities for refined fuels in Phillipsburg, Kansas. The asphalt storage and terminalling facilities are used to receive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement.
 
  •  Pipelines.  We own a proprietary pipeline system capable of transporting approximately 145,000 bpd of crude oil from Caney, Kansas to our refinery. Crude oils sourced outside of our proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to Caney, Kansas via a pipeline owned by Plains Pipeline L.P. (“Plains”). We also own associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our refinery.
 
Our refinery’s 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 refinery’s complexity score has increased to 12.9 from 12.2, and we have achieved significant increases in our refinery crude oil throughput rate over historical levels. Our higher complexity provides us the flexibility to increase our refining margin over comparable refiners with lower complexities.
 
Feedstocks Supply
 
Our 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.
 
Crude oil is supplied to our 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 2010 and it now has the capacity of supplying approximately 35,000 bpd of crude oil to the refinery. For 2010, the gathering system supplied approximately 27% of the 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,


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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.
 
For the year ended December 31, 2010, our crude oil supply blend was comprised of approximately 79% light sweet crude oil, 7% medium/light sour crude oil and 14% heavy sour crude oil. The light sweet crude oil includes our locally gathered crude oil.
 
For 2010, we obtained approximately 73% of the crude oil for our refinery, under a Crude Oil Supply Agreement, as amended (the “Supply Agreement”) with Vitol Inc. (“Vitol”) that expires December 31, 2012. 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.
 
Marketing and Distribution
 
We focus our 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 Phillipsburg terminal and to customers at throughput terminals on Magellan’s and NuStar’s refined products distribution systems. For the year ended December 31, 2010, approximately 36% of the refinery’s products were sold through the rack system directly to retail and wholesale customers while the remaining 64% 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 Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Operating, L.P. (“Enterprise”) and NuStar.
 
Customers
 
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. For the year ended December 31, 2010, QuikTrip Corporation and Growmark, Inc. accounted for approximately 14% and 11%, respectively, 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 (“OPIS”) 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.
 
Competition
 
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 refinery provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors. We primarily compete against seven 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, Frontier, Gary-Williams, Holly, NCRA, Valero and Shell.


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Seasonality
 
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.
 
Nitrogen Fertilizer Business
 
The nitrogen fertilizer business operates the only nitrogen fertilizer plant in North America that utilizes a pet coke gasification process to produce nitrogen fertilizer.
 
Raw Material Supply
 
The nitrogen fertilizer facility’s primary input is pet coke. During the past five years, over 70% of the nitrogen fertilizer business’ pet coke requirements on average 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, which provides an additional raw material source. There are significant supplies of low grade coal within a 60-mile radius of the nitrogen fertilizer plant.
 
Pet coke is produced as a by-product of the refinery’s coker unit process. In order to refine heavy or sour crude oils, which are lower in cost and more prevalent than higher quality crude oil, refiners use coker units which enable refiners to further upgrade heavy crude oil.
 
The nitrogen fertilizer business’ plant is located in Coffeyville, Kansas, which is part of the Midwest pet coke market. The Midwest pet coke market is not subject to the same level of pet coke price variability as is the Gulf Coast pet coke market. Given the fact that the majority of the nitrogen fertilizer business’ pet coke suppliers are located in the Midwest, the nitrogen fertilizer business’ geographic location gives it a significant freight cost advantage over its Gulf Coast pet coke market competitors.
 
Linde, Inc. (“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 crude oil refinery, and then exports steam back to the 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.
 
Nitrogen Production and Plant Reliability
 
The nitrogen fertilizer plant was completed in 2000 and, based upon data supplied by Blue Johnson, 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 crude oil refinery and third party sources and converting it into approximately 1,225 tons per day of ammonia. A majority of the ammonia is converted to approximately 2,025 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 General Electric, which licenses the gasification technology to the nitrogen fertilizer business, General Electric experts provide


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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.
 
Distribution, Sales and Marketing
 
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 period, from March through May. The second-highest period of demand occurs during fall pre-plant period in late October and November. The summer wheat pre-plant period 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.
 
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. The nitrogen fertilizer business also negotiates with distributors that have their own leased railcars to utilize these assets to deliver products. The nitrogen fertilizer business owns all of the truck and rail loading equipment at our nitrogen fertilizer facility. 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 markets agricultural products to destinations that produce the best margins for the business. 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. By securing this business directly, the nitrogen fertilizer business reduces its dependence on distributors serving the same customer base, which enables the nitrogen fertilizer business to capture a larger margin and allows it to better control its product distribution. Most of the agricultural sales are made on a competitive spot basis. The nitrogen fertilizer business also offers products on a prepay basis for in-season demand. The heavy in-season demand periods are spring and fall in the corn belt and summer in the wheat belt. The wheat belt is the primary wheat producing region of the United States, which includes Kansas, North Dakota, Oklahoma, South Dakota and Texas. Some of the industrial sales are spot sales, but most are on annual or multi-year contracts.
 
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 on the balance sheet upon receipt along with a corresponding liability. Revenue, associated with prepaid sales, is recognized at the time the product is delivered to the customer.
 
Customers
 
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 Fertilizers LLC, Transammonia, Inc., Agri Services


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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 years ended December 31, 2010, 2009 and 2008, the top five ammonia customers in the aggregate represented 44.2%, 43.9% and 54.7% of the nitrogen fertilizer business’ ammonia sales, respectively, and the top five UAN customers in the aggregate represented 43.3%, 44.2% and 37.2% of the nitrogen fertilizer business’ UAN sales, respectively. Approximately 12%, 15% and 13% of the nitrogen fertilizer business’ aggregate sales for the years ended December 31, 2010, 2009, and 2008, respectively, were made to Gavilon Fertilizers LLC. Additionally, approximately 10% of the nitrogen fertilizer business’ aggregate sales for the year ended December 31, 2010 were made to United Suppliers, Inc.
 
Competition
 
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 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 Blue Johnson data regarding total U.S. demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant’s UAN production in 2010 represented approximately 5.1% of the total U.S. demand and that the net ammonia produced and marketed at Coffeyville represented less than 1% of the total U.S. demand.
 
Seasonality
 
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. In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers who make planting decisions based largely on the prospective profitability of a harvest. The specific varieties and amounts of fertilizer they apply depend on factors like crop prices, farmers’ current liquidity, soil conditions, weather patterns and the types of crops planted.
 
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:
 
  •  restrictions on operations or the need to install enhanced or additional controls;
 
  •  the need to obtain and comply with permits and authorizations;


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  •  liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and off-site waste disposal locations; and
 
  •  specifications for the products marketed by our petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia.
 
Our operations require numerous permits and authorizations. Failure to comply with these permits or environmental laws generally 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
 
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 specific air pollutants, as well as the requirement to maintain a risk management program to help prevent accidental releases, of certain hazardous 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 compounds, 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.
 
In March 2004, Coffeyville Resources Refining & Marketing, LLC (“CRRM”) and Coffeyville Resources Terminal, LLC (“CRT”) entered into a Consent Decree (the “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 crude oil refinery and Phillipsburg terminal facilities. As a result of an agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Under the Consent Decree, CRRM agreed to install controls to reduce emissions of SO2, nitrogen oxides and particulate matter from its fluid catalytic cracking unit (“FCCU”) by January 1, 2011. In addition, pursuant to the Consent Decree, CRRM and CRT assumed cleanup obligations at the


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Coffeyville refinery and the Phillipsburg terminal facilities. The remaining costs of complying with the Consent Decree are expected to be approximately $49 million, of which approximately $47 million is expected to be capital expenditures which does not 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 Consent Decree. On June 30, 2009, CRRM submitted a force majeure notice to the EPA and KDHE in which CRRM indicated that it may be unable to meet the Consent Decree’s January 1, 2011 deadline related to the installation of controls on the FCCU because of delays caused by the June/July 2007 flood. In February 2010, CRRM and the EPA agreed to a fifteen month extension of the January 1, 2011, deadline for the installation of controls which was approved by the Court as a material modification to the existing Consent Decree. Pursuant to this agreement, CRRM would offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe.
 
In the meantime, CRRM has been negotiating with the EPA and KDHE to replace the current Consent Decree, including the fifteen month extension, with a global settlement under the national petroleum refining initiative. Over the course of the last decade, the EPA has embarked on a national Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues under the Clean Air Act: New Source Review, Flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The Petroleum Refining Initiative has resulted in most refiners entering into consent decrees imposing civil penalties and requiring substantial expenditures for pollution control and enhanced operating procedures. The EPA has indicated that it will seek to have all refiners enter into “global settlements” pertaining to all “marquee” issues. Our current Consent Decree covers some, but not all, of the “marquee” issues. We have been negotiating with EPA about expanding our existing Consent Decree obligations to include all of the “marquee” issues under the Petroleum Refining Initiative and have reached an agreement in principle on most of the issues, including an agreement to further delay the installation of controls on the FCCU. Under the global settlement, we may 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.
 
Release Reporting
 
Our facilities periodically experience releases of hazardous substances and extremely hazardous substances. If we fail to properly report the release or if the release violates the law or our permits, it could cause us to become the subject of a government enforcement action or third party claims. 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. 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 $900,000 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. The Company has reviewed and intends to contest these allegations. In the interim, we have entered into a tolling agreement relating to EPA’s allegations.
 
Fuel Regulations
 
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 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.


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In February 2004, the EPA granted us approval under a “hardship waiver” that deferred meeting final Ultra Low Sulfur Gasoline (“ULSG”) standards until January 1, 2011 in exchange for our meeting Ultra Low Sulfur Diesel (“ULSD”) requirements by January 1, 2007. We completed all the requirements of our waiver by February 28, 2011.
 
As a result of the 2007 flood, our refinery exceeded the annual average sulfur standard mandated by our hardship waiver. The EPA agreed to modify certain provisions of our hardship waiver, which gave CRRM short-term flexibility on sulfur content and we agreed to meet the final ULSG annual average standard in 2010. We met the required sulfur standards under our hardship waiver for 2010.
 
Mobile Source Air Toxic II Emissions
 
In 2007, the EPA promulgated the Mobile Source Air Toxic II (“MSAT II”) rule that requires the reduction of benzene in gasoline by 2011. CRRM is considered a small refiner under the MSAT II rule and compliance with the rule is extended until 2015 for small refiners. Capital expenditures to comply with the rule are expected to be approximately $10.0 million.
 
Renewable Fuel Standards
 
In February 2010, the EPA finalized changes to the Renewable Fuel Standards (RFS) which require the total volume of renewable transportation fuels sold or introduced in the U.S. to reach 12.95 billion gallons in 2010 and rise to 36 billion gallons by 2022. Due to mandates in the RFS2 requiring increasing volumes of renewable fuels to replace petroleum products in the U.S. motor fuel market, there may be a decrease in demand for petroleum products. In addition, CRRM may be impacted by increased capital expenses and production costs to accommodate mandated renewable fuel volumes to the extent that these increased costs cannot be passed on to the consumers. CRRM’s small refiner status under the RFS expired on December 31, 2010. Beginning on January 1, 2011, CRRM will be required to blend renewable fuels into its gasoline and diesel fuel or purchase renewable energy credits, known as Renewable Identification Numbers (RINs), in lieu of blending.
 
Greenhouse Gas Emissions
 
Currently, various legislative and regulatory measures to address greenhouse gas emissions (including carbon dioxide (“CO2”), methane and nitrous oxides) are in various phases of discussion or implementation. At the federal legislative level, Congress could adopt some form of federal mandatory greenhouse gas emission reduction laws, although the specific requirements and timing of any such laws are uncertain at this time. In June 2009, the U.S. House of Representatives passed a bill that would have created a nationwide cap-and-trade program designed to regulate emissions of CO2, methane and other greenhouse gases. A similar bill was introduced in the U.S. Senate, but was not voted upon. Congressional passage of such legislation does not appear likely at this time, though 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 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 our greenhouse gas emissions and will report the emissions to the EPA beginning in 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 our refinery and the nitrogen fertilizer plant, must obtain permits under the NSR 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”) for its greenhouse gas emissions. Phase-in permit requirements will begin for the largest stationary sources in 2011. We do not currently anticipate that the nitrogen fertilizer’s business’ proposed UAN expansion project or any other currently anticipated project will result in a significant increase in greenhouse gas emissions triggering the need to install BACT. However, beginning in July 2011, a major modification resulting in a significant expansion of production and a significant increase in greenhouse gas emissions at our nitrogen fertilizer plan or refinery may


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require the installation of BACT. The EPA’s Greenhouse Gas Tailoring Rule and certain other greenhouse gas emission rules have been challenged and will likely be subject to extensive litigation. In addition, a number of Congressional bills to overturn or bar the EPA from regulating greenhouse gas emissions, or at least to defer such action by the EPA under the federal Clean Air Act, have been proposed in the past, although President Obama has announced his intention to veto any such bills if passed.
 
In addition to federal regulations, 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 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 the timing and specific requirements of any such laws or regulations in Kansas are uncertain at this time.
 
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.
 
RCRA
 
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 refinery and eight other hazardous waste units in the process of being closed pending state agency approval. In addition, one closed interim status hazardous waste landfarm located at the Phillipsburg terminal is under long-term post closure care.
 
We have issued letters of credit of approximately $0.2 million in financial assurance for closure/post-closure care for hazardous waste management units at the Phillipsburg terminal and the Coffeyville refinery.
 
Impacts of Past Manufacturing.  The 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 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.


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The anticipated remediation costs through 2014 were estimated, as of December 31, 2010, to be as follows:
 
                                 
                Total Operation &
    Total
 
    Site
          Maintenance
    Estimated
 
    Investigation
    Capital
    Costs
    Costs
 
Facility
  Costs     Costs     Through 2014     Through 2014  
    (in millions)  
 
Coffeyville Refinery
  $ 0.2     $     $ 0.8     $ 1.0  
Phillipsburg Terminal
    0.2             1.0       1.2  
                                 
Total Estimated Costs
  $ 0.4     $     $ 1.8     $ 2.2  
                                 
 
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 2011, we will spend $2.9 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the Phillipsburg terminal. It is possible that additional costs will be required after this ten year period. We spent approximately $1.0 million in 2010 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 Phillipsburg facilities in the event we fail to fulfill our clean-up obligations. In accordance with the 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.
 
Environmental Remediation
 
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 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, retroactive 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”) 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 flood at our refinery, the U.S. Coast Guard on behalf of the EPA has made a claim for approximately $1.8 million in response cost reimbursement. We have requested detailed cost data in order to evaluate the claim. As is the case with all companies engaged in similar industries, depending on the underlying facts and circumstances 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.
 
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 performance,


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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.
 
Process Safety Management.  We maintain a process safety management (“PSM”) program. This program is designed to address all aspects of the federal Occupational Safety and Health Act (“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.
 
In 2007, OSHA began PSM inspections of all refineries under its jurisdiction as part of its National Emphasis Program (the “NEP”) following OSHA’s investigation of PSM issues relating to the multiple fatality explosion and fire at the BP Texas City facility in 2005. Completed NEP inspections have resulted in OSHA levying significant fines and penalties against most of the refineries inspected to date. Our refinery was inspected in connection with OSHA’s NEP program. The inspection commenced in September 2008 and was completed in March 2009, resulting in an assessed penalty of $32,500, which has been paid. In addition, OSHA announced in 2009 that it was going to pursue NEP inspections for chemical operations. OSHA began a PSM NEP inspection at our nitrogen fertilizer operations in late 2010. On March 3, 2011, we received OSHA’s report alleging certain violations resulting in a proposed penalty of $13,500. We plan to contest both the findings and the penalty.
 
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.
 
Security.  We have a comprehensive security program to protect our facility from unauthorized entry and exit from our facilities and potential acts of terrorism. Recent changes in the U.S. Department of Homeland Security rules and requirements may require enhancements and improvements to our current program.
 
Community Advisory Panel.  We developed and continue to support ongoing discussions with the community to share information about our operations and future plans. Our community advisory panel includes wide representation of residents, business owners and local elected representatives for the city and county.
 
Employees
 
At December 31, 2010, 493 employees were employed in our petroleum business, 122 were employed by the nitrogen fertilizer business and 80 employees were employed by the Company and CRLLC at our offices in Sugar Land, Texas and Kansas City, Kansas.
 
At December 31, 2010, approximately 39% of our employees (all of whom work in our petroleum business) 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 was entered into with the Metal Trade Unions effective August 31, 2008. No substantial changes were made to the prior agreement. This agreement expires in March 2013. In addition, a new collective bargaining agreement was entered into with the United Steelworkers on March 3, 2009. There were no substantial changes to the prior agreement. This agreement expires in March 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 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.


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Trademarks, Trade Names and Service Marks
 
This Annual Report on Form 10-K for the year ended December 31, 2010 (the “Report”) may include our 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 either registered or for which we have applied for federal registration. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.
 
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
 
The price volatility of crude oil, other feedstocks and refined products may have a material adverse effect on our earnings, profitability and cash flows.
 
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 narrows, 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. 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.
 
Volatile prices for natural gas and electricity 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.
 
Our internally generated cash flows and other sources of liquidity may not be adequate for our capital needs.
 
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


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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, 2010, we had cash and cash equivalents of $200.0 million and $79.6 million available under our first priority revolving credit facility. On February 22, 2011, we entered into an asset-backed revolving credit facility (“ABL credit facility”) and concurrently terminated our first priority credit facility. Our availability under the ABL credit facility is reduced by outstanding letters of credit. As of March 2, 2011, we had $192.1 million available under the ABL credit facility. Crude oil price volatility can significantly impact working capital on a week-to-week and month-to-month basis.
 
We have short-term and long-term capital needs. Our short-term working capital needs are primarily crude oil purchase requirements, which fluctuate with the pricing and sourcing of crude oil. Our long-term capital needs include capital expenditures we are required to make to comply with Tier II gasoline standards and the Consent Decree. The remaining costs of complying with the Consent Decree are expected to be approximately $49 million, of which approximately $47 million is expected to be capital expenditures. We also have budgeted capital expenditures for turnarounds at each of our facilities, and from time to time we are required to spend significant amounts for repairs when one or more facilities experiences temporary shutdowns. We also have significant debt service obligations. Our liquidity position will affect our ability to satisfy any of these needs.
 
If we are required to obtain our crude oil supply without the benefit of a crude oil supply agreement, our exposure to the risks associated with volatile crude oil prices may increase and our liquidity may be reduced.
 
We currently obtain the majority of our crude oil supply through the Supply Agreement with Vitol, which became effective on December 31, 2008. The Supply Agreement expires on December 31, 2012. The Supply Agreement 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 an 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.
 
Disruption of our ability to obtain an adequate supply of crude oil could reduce our liquidity and increase our costs.
 
In addition to the crude oil we gather locally in Kansas, Oklahoma, Missouri, and Nebraska, we purchase an additional 85,000 to 100,000 bpd of crude oil to be refined into liquid fuel. We obtain a portion of our non-gathered crude oil, approximately 16% in 2010, from foreign sources. The majority of these non-gathered 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, including through the Seaway Pipeline from the U.S. Gulf Coast to Cushing, Oklahoma. 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 our access to the pipelines on which we rely for the supply of our feedstock and the distribution of our products is interrupted, our inventory and costs may increase and we may be unable to efficiently distribute our products.
 
If one of the pipelines on which we rely for supply of our crude oil becomes inoperative, we would be required to obtain crude oil for our refinery through an alternative pipeline 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 from the refinery, which could increase our costs and result in a decline in profitability.
 
Our petroleum business’ financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.
 
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 our business, 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 could have the effect of reducing demand for gasoline and diesel fuel which could result in lower prices and reduce operating margins.
 
We face significant competition, both within and outside of our industry. Competitors who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us.
 
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 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 in the United States as a whole, and one of our regional 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.


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Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity and our ability to operate our refineries at full capacity.
 
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 refinery at full capacity could adversely affect our profitability and cash flows.
 
The recent adoption of derivatives legislation by the U.S. Congress could have an adverse effect on our ability to hedge risks associated with our business.
 
The U.S. Congress recently adopted comprehensive financial reform legislation, known as the Dodd-Frank Act, that establishes federal oversight and regulation of the over-the-counter derivatives market and entities that participate in that market. The Dodd-Frank Act was signed into law by the President on July 21, 2010, and requires the Commodities Futures Trading Commission (“CFTC”) and the SEC to promulgate rules and regulations implementing the new legislation within 360 days from the date of enactment. The act also requires the CFTC to institute broad new position limits for futures and options traded on regulated exchanges. Although 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.
 
Risks Related to the Nitrogen Fertilizer Business
 
The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile, and the nitrogen fertilizer business has experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose the nitrogen fertilizer business to significant fluctuations in its operating and financial results, and have a material adverse effect on our earnings, profitability and cash flows.
 
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 projections, 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.


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The costs associated with operating the nitrogen fertilizer plant are largely fixed. If nitrogen fertilizer prices fall below a certain level, the nitrogen fertilizer business may not generate sufficient revenue to operate profitably or cover its costs.
 
The nitrogen fertilizer plant has largely fixed costs compared to natural gas-based nitrogen fertilizer plants. As a result, 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. Declines in the price of nitrogen fertilizer products could have a material adverse effect on our results of operations and financial condition. Unlike its 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 its nitrogen fertilizer plant.
 
A decline in natural gas prices could impact the nitrogen fertilizer business’ relative competitive position when compared to other nitrogen fertilizer producers.
 
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 was not 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 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.
 
Any decline in U.S. agricultural production or limitations on the use of nitrogen fertilizer for agricultural purposes could have a material adverse effect on the market for nitrogen fertilizer, and 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 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.


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A major factor underlying the current high level of demand for nitrogen-based fertilizer products is the expanding production of ethanol. A decrease in ethanol production, an increase in ethanol imports or a shift away from corn as a principal raw material used to produce ethanol could 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. Such 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. Studies showing that expanded ethanol production may increase the level of greenhouse gases in the environment may reduce political support for ethanol production. The elimination or significant reduction in ethanol incentive programs, such as the 45 cents per gallon ethanol tax credit and the 54 cents per gallon ethanol import tariff, 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). This trend is driven by the fact that cellulose-based biomass is generally cheaper than corn, and producing ethanol from cellulose-based biomass would create opportunities to produce ethanol in areas that are unable to grow corn. Although current technology is not sufficiently efficient to be competitive, new conversion technologies may be developed in the future. 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.
 
Nitrogen fertilizer products are global commodities, and the nitrogen fertilizer business faces intense competition from other nitrogen fertilizer producers.
 
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. An inability to compete successfully could result in the loss of customers, which could adversely affect the sales, profitability and the cash flows of the nitrogen fertilizer business.
 
Adverse weather conditions during peak fertilizer application periods may have a material adverse effect on our results of operations, financial condition and cash flows, because the agricultural customers of the nitrogen fertilizer business are geographically concentrated.
 
The nitrogen fertilizer business’ sales to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. 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


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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.
 
The nitrogen fertilizer business is seasonal, which may result in it carrying significant amounts of inventory and seasonal variations in working capital. Our inability to predict future seasonal nitrogen fertilizer demand accurately may result in excess inventory or product shortages.
 
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.
 
The nitrogen fertilizer business’ operations are dependent on third party suppliers, including Linde, which owns an air separation plant that provides oxygen, nitrogen and compressed dry air to its gasifiers, and the City of Coffeyville, which supplies the nitrogen fertilizer business with electricity. A deterioration in the financial condition of a third party supplier, a mechanical problem with the air separation plant, or the inability of a third party supplier to perform in accordance with its contractual obligations could have a material adverse effect on our results of operations, financial condition and cash flows.
 
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, we 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 nitrogen fertilizer business’ results of operations, financial condition and cash flows may be adversely affected by the supply and price levels of pet coke.
 
The profitability of the nitrogen fertilizer business is directly affected by the price and availability of pet coke obtained from our crude oil refinery pursuant to a long-term agreement and pet coke purchased from third parties, 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 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 third party providers of transportation services and equipment, which subjects it to risks and uncertainties beyond its control that may have a material adverse effect on our results of operations, financial condition and cash flows.
 
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 and fluctuate based upon business and economic conditions and governmental policies affecting the agricultural industry. These factors are outside of our control and may significantly affect our profitability.
 
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, for U.S. markets, are:
 
  •  weather patterns and field conditions (particularly during periods of traditionally high nitrogen fertilizer consumption);
 
  •  quantities of nitrogen fertilizers imported to and exported from North America;
 
  •  current and projected grain inventories and prices, which are heavily influenced by U.S. exports and world-wide grain markets; and
 
  •  U.S. governmental policies, including farm and biofuel policies, which may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted or crop prices.
 
International market conditions, which are also outside of our control, may also significantly influence the nitrogen fertilizer business’ operating results. The international market for nitrogen fertilizers is 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


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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.
 
Ammonia can be very volatile and extremely hazardous. Any liability for accidents involving ammonia that cause severe damage to property or injury to the environment and human health could have a material adverse effect on our results of operations, financial condition and cash flows. In addition, the costs of transporting ammonia could increase significantly in the future.
 
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 heat exchangers and other equipment. It experienced more significant ammonia releases in August 2007 due to the failure of a high-pressure pump and in September 2010 due to a UAN vessel rupture. Similar events may occur in the future.
 
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, onboard 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 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 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. If any such 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.
 
Environmental laws and regulations on fertilizer end-use and application and numeric nutrient water quality criteria could have a material adverse impact on fertilizer demand in the future.
 
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 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 EPA rule 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. Any such laws, regulations or interpretations could have a material adverse effect on our results of operations, financial condition and cash flows.


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The nitrogen fertilizer business’ plans to address its CO2production may not be successful.
 
The nitrogen fertilizer business has signed a letter of intent with a third party with expertise in CO2 capture and storage systems to develop plans whereby it may, in the future, either sell up to 850,000 tons per year of high purity CO2 produced by the nitrogen fertilizer plant to oil and gas exploration and production companies to enhance oil recovery, or pursue an economic means of geologically sequestering such CO2. There can be no guarantee that this proposed CO2 capture and storage system will be constructed successfully or at all or, if constructed, that it will provide an economic benefit and will not result in economic losses or additional costs that may have a material adverse effect on our results of operations, financial condition and cash flows.
 
If licensed technology were no longer available, the nitrogen fertilizer business may be adversely affected.
 
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, 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.
 
The nitrogen fertilizer business may face third party claims of intellectual property infringement, which if successful could result in significant costs.
 
There are currently no pending claims relating to the infringement of any third party intellectual property rights. However, 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.
 
There can be no assurance that the transportation costs of the nitrogen fertilizer business’ competitors will not decline.
 
Our nitrogen fertilizer plant is located within the U.S. farm belt, where the majority of the end users of our nitrogen fertilizer products grow their crops. Many of our 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 our competitors’ transportation costs will not decline or that additional pipelines will not be built, lowering the price at which our competitors can sell their products, which would have a material adverse effect on our results of operations and financial condition.


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Risks Related to Our Entire Business
 
Instability and volatility in the capital, credit and commodity markets in the global economy could negatively impact our business, financial condition, results of operations and cash flows.
 
The global capital and credit markets experienced extreme volatility and disruption over the past two years. Our business, financial condition and results of operations could be negatively impacted by the 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 U.S. and globally during 2008 and 2009. The difficult conditions in these markets and the overall economy affect us in a number of ways. For example:
 
  •  Although we believe we have sufficient liquidity under our ABL credit facility to run our business, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all.
 
  •  Market volatility could exert downward pressure on our stock price, which may make it more difficult for us to raise additional capital and thereby limit our ability to grow.
 
  •  Our ABL credit facility contains various covenants that we must comply with and if we are not in compliance, there can be no assurance that we would be able to successfully amend the agreement in the future. Further, any such amendment could be very expensive.
 
  •  Market conditions could result in our significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us.
 
Our refinery and nitrogen fertilizer facilities face operating hazards and interruptions, including unscheduled maintenance or downtime. We could face potentially significant costs to the extent these hazards or interruptions cause a material decline in production and are not fully covered by our existing insurance coverage. Insurance companies that currently insure companies in the energy industry may cease to do so, may change the coverage provided or may substantially increase premiums in the future.
 
Our operations, located primarily in a single location, are subject to significant operating hazards and interruptions. If any of our facilities, including our refinery and 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 all of our refining operations and fertilizer manufacturing at a single location compounds such risks.
 
Operations at our refinery 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:
 
  •  unscheduled maintenance or catastrophic events such as a major accident or fire, damage by severe weather, flooding or other natural disaster;
 
  •  labor difficulties that result in a work stoppage or slowdown;
 
  •  environmental proceedings or other litigation that compel the cessation of all or a portion of the operations; and
 
  •  increasingly stringent environmental regulations.
 
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 refinery requires a scheduled maintenance turnaround every four to five years for each unit, and the nitrogen fertilizer plant requires a scheduled


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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 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 facility’s UAN plant was out of service for approximately six weeks after the rupture of a high pressure vessel in September 2010 and required significant expenditures to repair. Our 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 throughput and required significant expenditures to repair. The refinery returned to full operations on January 26, 2011. 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 have a $1.0 billion limit, with a $2.5 million deductible for physical damage and a 45-day waiting period before losses resulting from business interruptions are recoverable. 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 current property policy contains a specific sub-limit of $150.0 million for damage caused by flooding. 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 days.
 
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 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.
 
Environmental laws and regulations could require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.
 
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.


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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 business is subject to 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 refinery, 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 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, facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or by-products 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, CRRM and CRT entered into a Consent Decree to address certain allegations of Clean Air Act violations by Farmland at our Coffeyville crude oil refinery and Phillipsburg terminal facility in order to address the alleged violations and eliminate liabilities going forward. The remaining costs of complying with the 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 RCRA and described in Item 1 Business — “Environmental Matters — RCRA — Impacts of Past Manufacturing.” To date, CRRM and CRT 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 Consent Decree. As described in “Environmental, Health and Safety (“EHS”) Matters” and “The Federal Clean Air Act,” the CRRM and the EPA agreed to extend the refinery’s deadline under the Consent Decree to install certain air pollution controls on its FCCU due to delays caused by the June/July 2007 flood. Pursuant to this agreement, CRRM would offset any incremental emissions resulting from the delay by providing additional controls to existing emission sources over a set timeframe. A number of factors could affect our ability to meet the requirements imposed by the Consent Decree and have a material adverse effect on our results of operations, financial condition and profitability.
 
Two of our facilities, including our Coffeyville crude oil refinery and the Phillipsburg terminal (which operated as a refinery until 1991), have environmental contamination. We have assumed Farmland’s responsibilities under certain RCRA administrative orders related to contamination at or that originated from the refinery (which includes portions of the nitrogen fertilizer plant) and the Phillipsburg terminal. If significant unknown liabilities that have been undetected to date by our soil and groundwater investigation and sampling programs arise in the areas where we have assumed liability for the corrective action, that liability could have


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a material adverse effect on our results of operations and financial condition 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 may be unable to obtain or renew permits necessary for our operations, which could inhibit our ability to do business.
 
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.
 
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition, and cash flows.
 
Currently, various legislative and regulatory measures to address greenhouse gas emissions (including CO2, methane and nitrous oxides) are in various phases of discussion or implementation. At the federal legislative level, Congress could adopt some form of federal mandatory greenhouse gas emission reduction laws, although the specific requirements and timing of any such laws are uncertain at this time. In June 2009, the U.S. House of Representatives passed a bill that would have created a nationwide cap-and-trade program designed to regulate emissions of CO2, methane and other greenhouse gases. A similar bill was introduced in the U.S. Senate, but was not voted upon. Congressional passage of such legislation does not appear likely at this time, though 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 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 our greenhouse gas emissions and will report the emissions to the EPA beginning in 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 our refinery and the nitrogen fertilizer plant, must obtain permits under NSR 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 BACT for its greenhouse gas emissions. Phase-in permit requirements will begin for the largest stationary sources in 2011. We do not currently anticipate that the nitrogen fertilizer business’ previously announced UAN expansion project or any other currently anticipated projects will result in a significant increase in greenhouse gas emissions triggering the need to install BACT. However, beginning in July 2011, a major modification resulting in a significant expansion of production at the nitrogen fertilizer plant resulting in a significant increase in greenhouse gas emissions may require the installation of BACT for the nitrogen fertilizer plant’s gas emissions. The EPA’s Greenhouse Gas Tailoring Rule and certain other greenhouse gas emission rules have been challenged and will likely be subject to extensive litigation. In addition, a number of Congressional bills to overturn or bar the EPA from regulating greenhouse gas emissions, or at least to defer such action by the EPA under the federal Clean Air Act, have been proposed in the past, although President Obama has announced his intention to veto any such bills if passed.
 
In addition to federal regulations, 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


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our 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 the timing and specific requirements of any such laws or regulations in Kansas are uncertain at this time.
 
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 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.
 
We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.
 
We are subject to the requirements of OSHA and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, record keeping requirements and monitoring and control of occupational exposure to regulated substances, could have a material adverse effect on our results of operations, financial condition and the cash flows if we are subjected to significant fines or compliance costs.
 
Both the petroleum and nitrogen fertilizer businesses depend on significant customers and the loss of one or several significant customers may have a material adverse impact on our results of operations and financial condition.
 
The petroleum and nitrogen fertilizer businesses both have a high concentration of customers. Our five largest customers in the petroleum business represented 47.6% of our petroleum sales for the year ended December 31, 2010. Further in the aggregate, the top five ammonia customers of the nitrogen fertilizer business represented 44.2% of its ammonia sales for the year ended December 31, 2010 and the top five UAN customers of the nitrogen fertilizer business represented 43.3% 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.
 
The acquisition and expansion strategy of our petroleum business and the nitrogen fertilizer business involves significant risks.
 
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 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


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and expansions may entail significant transaction costs and risks associated with entry into new markets and lines of business.
 
The nitrogen fertilizer business has announced that it intends to move forward with an expansion of its nitrogen fertilizer plant, which will allow it the flexibility to upgrade all of its ammonia production to UAN. 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:
 
  •  unforeseen difficulties in the acquired operations and disruption of the ongoing operations of our petroleum business and the nitrogen fertilizer business;
 
  •  failure to achieve cost savings or other financial or operating objectives with respect to an acquisition;
 
  •  strain on the operational and managerial controls and procedures of our petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources;
 
  •  difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;
 
  •  assumption of unknown material liabilities or regulatory non-compliance issues;
 
  •  amortization of acquired assets, which would reduce future reported earnings;
 
  •  possible adverse short-term effects on our cash flows or operating results; and
 
  •  diversion of management’s attention from the ongoing operations of our business.
 
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 (including the CO2 sequestration or sale project) 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, 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.
 
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 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 depend upon our subsidiaries for our cash flow.
 
We are a holding company. 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, tax sharing payments or otherwise. In addition, CRLLC, our indirect subsidiary, which is the primary obligor under our existing credit facility, is a holding company and its ability to meet its debt service obligations depends on the cash flow of its subsidiaries. The ability of our subsidiaries to make any payments to us will depend on their earnings, the terms of their indebtedness, including the terms of our credit facility, tax considerations and legal restrictions. In particular, our credit


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facility currently imposes significant limitations on the ability of our subsidiaries to make distributions to us and consequently our ability to pay dividends to our stockholders.
 
Our significant indebtedness may affect our ability to operate our business, and may have a material adverse effect on our financial condition and results of operations.
 
As of December 31, 2010, we had senior secured notes outstanding with an aggregate principal balance of $472.5 million, $70.4 million in letters of credit outstanding and borrowing availability of $79.6 million under our first priority credit facility. As discussed above, we terminated the first priority credit facility as of February 22, 2011 and replaced it with the ABL credit facility. As of March 2, 2011 we had $192.1 million available under the ABL credit facility. 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 high level of indebtedness could have important consequences, such as:
 
  •  limiting our ability to obtain additional financing to fund our working capital needs, capital expenditures, debt service requirements or for other purposes;
 
  •  limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt;
 
  •  limiting our ability to compete with other companies who are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions;
 
  •  placing restrictive financial and operating covenants in the agreements governing our and our subsidiaries’ long-term indebtedness and bank loans, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us;
 
  •  exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries’ debt instruments that could have a material adverse effect on our business, financial condition and operating results;
 
  •  increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and
 
  •  limiting our ability to react to changing market conditions in our industry and in our customers’ industries.
 
In addition, borrowings under our ABL 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.
 
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 our liability 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 our credit facility. Upon a default, unless waived, the lenders under our credit facility would have all remedies available


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to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our or our subsidiaries’ assets, and force us and our subsidiaries into bankruptcy or liquidation. In addition, any defaults under the credit facility or any other debt could trigger cross defaults under other or future credit agreements. 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.
 
A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.
 
As of December 31, 2010, approximately 39% of our employees, all of whom work in our petroleum business, were represented by labor unions under collective bargaining agreements. Our collective bargaining agreement with the United Steelworkers will expire in March 2012 and our collective bargaining agreement with the Metal Trades Unions will expire in March 2013. 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 and financial condition.
 
Our business may suffer if any of our key senior executives or other key employees discontinues employment with us. Furthermore, a shortage of skilled labor or disruptions in our labor force may make it difficult for us to maintain labor productivity.
 
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 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.
 
New regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities could result in higher operating costs.
 
The costs of complying with 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. Simultaneously, local, state and federal governments have begun a regulatory process that could lead to new regulations impacting the security of refinery and chemical plant locations and the transportation of petroleum and hazardous chemicals. Our business could be materially adversely affected by the cost of complying with new regulations.
 
Compliance with and changes in the tax laws could adversely affect our performance.
 
We are subject to extensive tax liabilities, including United States and state income taxes and transactional taxes such as excise, sales/use, payroll, and franchise and withholding. New tax laws and regulations are continuously being enacted or proposed that could result in increased expenditures for tax liabilities in the future.


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Risks Related to Our Common Stock
 
Shares eligible for future sale may cause the price of our common stock to decline.
 
Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our amended and restated certificate of incorporation, we are authorized to issue up to 350,000,000 shares of common stock, of which 86,413,781 shares of common stock were outstanding as of March 2, 2011. Of these shares, CALLC currently owns 7,988,179 shares and has registration rights with respect to the remainder of their shares that would allow them to be sold in a secondary public offering.
 
Risks Related to the Limited Partnership Structure Through Which
We Currently Hold Our Interest in the Nitrogen Fertilizer Business
 
There are risks associated with the limited partnership structure through which we currently hold our interest in the Nitrogen Fertilizer Business. Some of these risks include:
 
  •  Because we neither serve as, nor control, the managing general partner of the Partnership, the managing general partner may operate the Partnership in a manner with which we disagree or which is not in our interest. CVR GP, LLC or Fertilizer GP, which is owned by CALLC III and senior management, is the managing general partner of the Partnership which holds the nitrogen fertilizer business. The managing general partner is authorized to manage the operations of the nitrogen fertilizer business (subject to our specified joint management rights), and we do not control the managing general partner. Although our senior management also serves as the senior management of Fertilizer GP, in accordance with a services agreement among us, Fertilizer GP and the Partnership, our senior management operates the Partnership under the direction of the managing general partner’s board of directors and Fertilizer GP has the right to select different management at any time (subject to our joint right in relation to the chief executive officer and chief financial officer of the managing general partner). Accordingly, the managing general partner may operate the Partnership in a manner with which we disagree or which is not in the interests of our company and our stockholders.
 
  •  The Partnership has a preferential right to pursue most corporate opportunities (outside of the refining business) before we can pursue them. Also, we have agreed with the Partnership that we will not own or operate a fertilizer business other than the Partnership (with certain exceptions).
 
  •  If the Partnership elects to pursue and completes a public offering or private placement of limited partner interests, our voting power in the Partnership would be reduced and our rights to distributions from the Partnership could be materially adversely affected.
 
  •  We may be required in the future to share increasing portions of the cash flows of the nitrogen fertilizer business with third parties and we may in the future be required to deconsolidate the nitrogen fertilizer business from our consolidated financial statements.
 
  •  Fertilizer GP can require us to be a selling unit holder in the Partnership’s initial offering at an undesirable time or price.
 
  •  Our rights to remove Fertilizer GP as managing general partner of the Partnership are extremely limited.
 
  •  Fertilizer GP’s interest in the Partnership and the control of Fertilizer GP may be transferred to a third party without our consent. The new owners of Fertilizer GP may have no interest in CVR Energy and may take actions that are not in our interest.


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Our rights to receive distributions from the Partnership may be limited over time.
 
Fertilizer GP will have no right to receive distributions in respect of its IDRs (i) until the Partnership has distributed all aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 and (ii) for so long as the Partnership or its subsidiaries are guarantors under our credit facility (the date both of the actions described in (i) and (ii) are completed is referred to as the “IDR Effective Date”).
 
As of the IDR Effective Date, distributions of amounts greater than the aggregate adjusted operating surplus generated will be allocated between us and Fertilizer GP (and the holders of any other interests in the Partnership), and thereafter, the allocation will grant Fertilizer GP a greater percentage of the Partnership’s distributions as more cash becomes available for distribution. After the IDR Effective Date, if quarterly distributions exceed the target of $0.4313 per unit, Fertilizer GP will be entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target level, in respect of its IDRs. Fertilizer GP’s discretion in determining the level of cash reserves may materially adversely affect the Partnership’s ability to make distributions to us.
 
The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our stockholders.
 
The managing general partner of the Partnership, Fertilizer GP, is responsible for the management of the Partnership (subject to our specified joint management rights). Although Fertilizer GP has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and holders of interests in the Partnership (including us, in our capacity as holder of special units), the fiduciary duty is specifically limited by the express terms of the partnership agreement and the directors and officers of Fertilizer GP also have a fiduciary duty to manage Fertilizer GP in a manner beneficial to the owners of Fertilizer GP. The interests of the owners of Fertilizer GP may differ from, or conflict with, our interests and the interests of our stockholders. In resolving these conflicts, Fertilizer GP may favor its own interests and/or the interests of its owners over our interests and the interests of our stockholders (and the interests of the Partnership). In addition, while our directors and officers have a fiduciary duty to make decisions in our interests and the interests of our stockholders, one of our wholly-owned subsidiaries is also a general partner of the Partnership and, therefore, in such capacity, has a fiduciary duty to exercise rights as general partner in a manner beneficial to the Partnership and its unitholders, subject to the limitations contained in the partnership agreement. As a result of these conflicts, our directors and officers may feel obligated to take actions that benefit the Partnership as opposed to us and our stockholders.
 
The potential conflicts of interest include, among others, the following:
 
  •  Fertilizer GP, as managing general partner of the Partnership, holds all of the IDRs in the Partnership. IDRs give Fertilizer GP a right to increasing percentages of the Partnership’s quarterly distributions after the IDR Effective Date, and if the quarterly distributions exceed the target of $0.4313 per unit. Fertilizer GP may have an incentive to manage the Partnership in a manner which preserves or increases the possibility of these future cash flows rather than in a manner that preserves or increases current cash flows.
 
  •  The owners of Fertilizer GP, who include the Goldman Sachs Funds, the Kelso Funds and senior management, are permitted to compete with us or the Partnership or to own businesses that compete with us or the Partnership. In addition, the owners of Fertilizer GP are not required to share business opportunities with us, and our owners are not required to share business opportunities with the Partnership or Fertilizer GP.
 
  •  Neither the partnership agreement nor any other agreement requires the owners of Fertilizer GP to pursue a business strategy that favors us or the Partnership. The owners of Fertilizer GP have fiduciary duties to make decisions in their own best interests, which may be contrary to our interests and the interests of the Partnership. In addition, Fertilizer GP is allowed to take into account the interests of


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  parties other than us, such as its owners, or the Partnership in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.
 
  •  Fertilizer GP has limited its liability and reduced its fiduciary duties under the partnership agreement and has also restricted the remedies available to the unitholders of the Partnership, including us, for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of our ownership interest in the Partnership, we may consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.
 
  •  Fertilizer GP determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, issuances of additional partnership interests and cash reserves maintained by the Partnership (subject to our specified joint management rights), each of which can affect the amount of cash that is available for distribution to us.
 
  •  Fertilizer GP is also able to determine the amount and timing of any capital expenditures and whether a capital expenditure is for maintenance, which reduces operating surplus, or expansion, which does not. Such determinations can affect the amount of cash that is available for distribution and the manner in which the cash is distributed.
 
  •  The partnership agreement does not restrict Fertilizer GP from causing the nitrogen fertilizer business to pay it or its affiliates for any services rendered to the Partnership or entering into additional contractual arrangements with any of these entities on behalf of the Partnership.
 
  •  Fertilizer GP determines which costs incurred by it and its affiliates are reimbursable by the Partnership.
 
  •  The executive officers of Fertilizer GP, and the majority of the directors of Fertilizer GP, also serve as our directors and/or executive officers. The executive officers who work for both us and Fertilizer GP, including our chief executive officer, chief operating officer, chief financial officer and general counsel, divide their time between our business and the business of the Partnership. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or the Partnership.
 
The Fertilizer GP can require us to purchase the managing general partner interest in the Partnership. We may not have requisite funds to do so.
 
As the Partnership did not consummate an initial private or public offering by October 24, 2009, the Fertilizer GP can require us to purchase the managing general partner interest. This put right expires on the earlier of (1) October 24, 2012 and (2) the closing of the Partnership’s initial offering.
 
The Partnership has agreed to purchase the managing general partner’s incentive distribution rights for $26.0 million, and we have agreed to repurchase the managing general partner interest for nominal consideration, contingent on the closing of the Partnership’s initial public offering.
 
If the Partnership’s initial public offering does not close, Fertilizer GP may elect to require us to purchase the managing general partner interest in the future. We may not have available cash resources to pay the purchase price. In addition, any purchase of the managing general partner interest would divert our capital resources from other intended uses, including capital expenditures and growth capital. In addition, the instruments governing our indebtedness may limit our ability to acquire, or prohibit us from acquiring, the managing general partner interest.


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If we were deemed an investment company under the Investment Company Act of 1940, applicable restrictions would make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business. We may in the future be required to sell some or all of our partnership interests in order to avoid being deemed an investment company, and such sales could result in gains taxable to the company.
 
In order not to be regulated as an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), unless we can qualify for an exemption, we must ensure that we are engaged primarily in a business other than investing, reinvesting, owning, holding or trading in securities (as defined in the 1940 Act) and that we do not own or acquire “investment securities” having a value exceeding 40% of the value of our total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We believe that we are not currently an investment company because our general partner interests in the Partnership should not be considered to be securities under the 1940 Act and, in any event, both our refinery business and the nitrogen fertilizer business are operated through majority-owned subsidiaries. In addition, even if our general partner interests in the Partnership were considered securities or investment securities, we believe that they do not currently have a value exceeding 40% of the fair market value of our total assets on an unconsolidated basis.
 
However, there is a risk that we could be deemed an investment company if the SEC or a court determines that our general partner interests in the Partnership are securities or investment securities under the 1940 Act and if our Partnership interests constituted more than 40% of the value of our total assets. Currently, our interests in the Partnership constitute less than 40% of our total assets on an unconsolidated basis, but they could constitute a higher percentage of the fair market value of our total assets in the future if the value of our Partnership interests increases, the value of our other assets decreases, or some combination thereof occurs.
 
We intend to conduct our operations so that we will not be deemed an investment company. However, if we were deemed an investment company, restrictions imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business and the price of our common stock. In order to avoid registration as an investment company under the 1940 Act, we may have to sell some or all of our interests in the Partnership at a time or price we would not otherwise have chosen. The gain on such sale would be taxable to us. We may also choose to seek to acquire additional assets that may not be deemed investment securities, although such assets may not be available at favorable prices. Under the 1940 Act, we may have only up to one year to take any such actions.
 
Risks Related to the Structure Through Which We Would Hold Our Interest
in the Nitrogen Fertilizer Business Following an Equity Offering at the Nitrogen Fertilizer Business
 
We may have liability to repay distributions that are wrongfully distributed to us.
 
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.
 
If the Partnership effects an initial public offering of its common units, public investors will own a portion of the nitrogen fertilizer business.
 
If the Partnership effects an initial public offering of its common units, public investors will own a portion of the nitrogen fertilizer business. Following such offering, we will not be entitled to receive 100% of the cash generated by the nitrogen fertilizer business. Furthermore, the general partner of the Partnership that owns the nitrogen fertilizer business will owe certain contractual governance duties to manage the business of the Partnership, which may be different from our best interest.


38


 

The nitrogen fertilizer business will incur increased costs as a result of being a publicly traded partnership.
 
As a subsidiary of a publicly traded partnership, the nitrogen fertilizer business will incur significant legal, accounting and other expenses that it did not incur prior to any such offering. In addition, the Sarbanes-Oxley Act of 2002 and the Dodd-Frank Act of 2010, as well as rules implemented by the SEC and the New York Stock Exchange, require, or will require, publicly traded entities to adopt various corporate governance practices that will further increase its costs. Before it is able to make distributions to us, it must first pay its expenses, including the costs of being a public company and other operating expenses. As a result, the amount of cash it has available for distribution to us will be affected by its expenses, including the costs associated with being a publicly traded partnership. It is estimated that the nitrogen fertilizer business will incur approximately $3.5 million of estimated incremental costs per year, some of which will be direct charges associated with being a publicly traded partnership, and some of which will be allocated to the nitrogen fertilizer business by us; however, it is possible that the actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.
 
The nitrogen fertilizer business has not filed separate reports with the SEC. Following any public offering, it will become subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These requirements will increase legal and financial compliance costs and will make compliance activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, the nitrogen fertilizer business will be required to have at least three independent directors (it currently has two) and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal control over financial reporting.
 
As a stand-alone public company, the nitrogen fertilizer business will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.
 
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 in its second annual report following its initial public offering. Furthermore, 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, or 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.
 
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


39


 

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.
 
Item 1B.   Unresolved Staff Comments
 
None.
 
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
Phillipsburg, KS
  200   Own   Terminal facility
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.
 
As of December 31, 2010, we had storage capacity for 767,000 barrels of gasoline, 1,062,000 barrels of distillates, 928,000 barrels of intermediates and 3,920,000 barrels of crude oil. The crude oil storage consisted of 674,000 barrels of refinery storage capacity, 536,000 barrels of field storage capacity and 2,710,000 barrels of storage at Cushing, Oklahoma. We expect that our current owned and leased facilities will be sufficient for our needs over the next twelve months. Additionally, we own 183 acres of land in Cushing, Oklahoma upon which we are proceeding to build approximately an additional 1,000,000 barrels of crude oil 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 three lawsuits in Note 15, “Commitments and Contingencies” to our Consolidated Financial Statements as set forth in Part II, Item 7. Included in this note is a description of the Samson, J. Aron and TransCanada litigation, as well as other legal proceedings. 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.
 
Item 4.   (Removed and Reserved)


40


 

 
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:
 
                 
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  
 
                 
2009:
  High   Low
 
First Quarter
  $ 6.71     $ 3.13  
Second Quarter
    10.74       5.24  
Third Quarter
    12.67       6.21  
Fourth Quarter
    13.89       6.50  
 
Holders of Record
 
As of March 2, 2011, there were 443 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
 
We do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain future earnings from our refinery business, if any, together with any distributions we may receive from the Partnership, to finance operations, expand our business, and make principal payments on our debt. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and other factors that the board deems relevant. In addition, the covenants contained in 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.
 
In addition, the partnership agreement which governs the Partnership includes restrictions on the Partnership’s ability to make distributions to us. If the Partnership issues limited partner interests to third party investors, these investors will have rights to receive distributions which, in some cases, will be senior to our rights to receive distributions. In addition, the managing general partner of the Partnership has IDRs which, over time, will give it rights to receive distributions. These provisions limit the amount of distributions which the Partnership can make to us which, in turn, limit our ability to make distributions to our stockholders. In addition, since the Partnership makes its distributions to CVR Special GP, LLC, which is controlled by CRLLC, a subsidiary of ours, our credit facility limits the ability of CRLLC to distribute these distributions to us. In addition, the Partnership may also enter into its own credit facility or other contracts that limit its ability to make distributions to us.


41


 

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, 2010, as compared to the cumulative return of the Russell 2000 Index and an industry peer group consisting of Holly Corporation, Frontier Oil 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 stock on December 31, 2010 was $15.18. 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, 2010
among CVR Energy, Inc., Russell 2000 Index and a peer group
 
PERFORMANCE GRAPH
 
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   Mar ‘10   Jun ‘10   Sep ‘10   Dec ‘10
 
CVR Energy, Inc. 
    100.00       123.16       113.73       95.06       42.07       19.75       27.36       36.20       61.43       33.88       43.21       37.14       40.74       74.96  
Russell 2000 Index
    100.00       93.59       84.05       84.26       83.02       61.02       51.65       62.10       73.83       76.40       82.91       74.46       82.60       90.24  
Peer Group
    100.00       84.02       58.83       50.99       40.49       27.68       33.43       27.26       31.52       28.34       31.53       30.31       31.66       47.10  


42


 

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, 2010. 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 delivering shares to recipients of share-based compensation awards that have vested. The Company does not consider this to be a share buyback program.
 
                                 
                      Maximum Number (or
 
                      Approximate Dollar
 
                Total Number of Shares
    Value) of Shares that
 
                Purchased as Part of
    May Yet Be Purchased
 
    Total Number of
    Average Price Paid per
    Publicly Announced
    Under the
 
Period
  Shares Purchased     Share     Plans or Programs     Plans or Programs  
 
October 1, 2010 to October 31, 2010
                       
November 1, 2010 to November 30, 2010
                       
December 1, 2010 to December 31, 2010
    22,765     $ 14.27              
                                 
Total
    22,765     $ 14.27              
                                 
 
Equity Compensation Plans
 
The table below contains information about securities authorized for issuance under our long-term incentive plan as of December 31, 2010. This plan was approved by our stockholders in October 2007.
 
                         
Equity Compensation Plan Information  
                Number of
 
                Securities
 
    Number of
          Remaining Available
 
    Securities to be
          for Future Issuance
 
    Issued Upon
    Weighted-Average
    Under Equity
 
    Exercise of
    Exercise Price of
    Compensation Plans
 
    Outstanding Options
    Outstanding Options
    (Excluding Securities
 
Plan Category
  Warrants and Rights(a)     Warrants and Rights(b)     Reflected in (a) (c))  
 
Equity compensation plans approved by security holders:
                       
CVR Energy, Inc. Long-Term Incentive Plan
    22,900 (1)   $ 18.03       5,835,428 (2)
Equity compensation plans not approved by security holders:
                       
None
                 
                         
Total
    22,900     $ 18.03       5,835,428  
 
 
(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 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, 2010, 1,657,056 shares of non-vested common stock had been granted under this plan, of which 4,899 shares have been forfeited and 1,369,182 remain unvested.


43


 

 
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, 2010, 2009 and 2008 and the selected consolidated financial information presented below under the caption “Balance Sheet Data” as of December 31, 2010 and 2009 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 “Statement of Operations Data” for the years ended December 31, 2007 and 2006 and the consolidated financial information presented below under the caption “Balance Sheet Data” at December 31, 2008, 2007 and 2006, is derived from our audited consolidated financial statements that are not included in this Report.
 
We calculate earnings per share in 2007 and 2006 on a pro forma basis. This calculation gives effect to the issuance of 23,000,000 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. The weighted-average shares outstanding for 2006 also gives effect to an increase in the number of shares which, when multiplied by the initial public offering price, would be sufficient to replace the capital in excess of earnings withdrawn, as a result of our paying dividends in the year ended December 31, 2006 in excess of earnings for such period, or 3,075,194 shares.
 
                                                 
    Year Ended December 31,        
    2010     2009     2008     2007     2006        
    (in millions, except share data)        
 
Statements of Operations Data:
                                               
Net sales
  $ 4,079.8     $ 3,136.3     $ 5,016.1     $ 2,966.9     $ 3,037.6          
Cost of product sold(1)
    3,568.1       2,547.7       4,461.8       2,308.8       2,443.4          
Direct operating expenses(1)
    240.8       226.0       237.5       276.1       199.0          
Selling, general and administrative expenses(1)
    92.0       68.9       35.2       93.1       62.6          
Net costs associated with flood
    (1.0 )     0.6       7.9       41.5                
Depreciation and amortization
    86.8       84.9       82.2       60.8       51.0          
Goodwill impairment(2)
                42.8                      
                                                 
Operating income
  $ 93.1     $ 208.2     $ 148.7     $ 186.6     $ 281.6          
Other income (expense), net(3)
    (13.2 )     (0.1 )     (5.9 )     0.2       (20.8 )        
Interest expense
    (50.3 )     (44.2 )     (40.3 )     (61.1 )     (43.9 )        
Gain (loss) on derivatives, net
    (1.5 )     (65.3 )     125.3       (282.0 )     94.5          
                                                 
Income (loss) before income taxes and noncontrolling interest
  $ 28.1     $ 98.6     $ 227.8     $ (156.3 )   $ 311.4          
Income tax (expense) benefit
    (13.8 )     (29.2 )     (63.9 )     88.5       (119.8 )        
Noncontrolling interest
                      0.2                
                                                 
Net income (loss)(4)
  $ 14.3     $ 69.4     $ 163.9     $ (67.6 )   $ 191.6          
Basic earnings (loss) per share(5)
  $ 0.17     $ 0.80     $ 1.90     $ (0.78 )   $ 2.22          
Diluted earnings (loss) per share(5)
  $ 0.16     $ 0.80     $ 1.90     $ (0.78 )   $ 2.22          
Weighted-average common shares outstanding(5):
                                               
Basic
    86,340,342       86,248,205       86,145,543       86,141,291       86,141,291          
Diluted
    86,789,179       86,342,433       86,224,209       86,141,291       86,158,791          
Management common units subject to redemption
                                  $ 3.1          
Common units
                                  $ 246.9          


44


 

                                                 
    Year Ended December 31,        
    2010     2009     2008     2007     2006        
    (in millions, except share data)        
 
Balance Sheet Data:
                                               
Cash and cash equivalents
  $ 200.0     $ 36.9     $ 8.9     $ 30.5     $ 41.9          
Working capital
    333.6       235.4       128.5       10.7       112.3          
Total assets
    1,740.2       1,614.5       1,610.5       1,868.4       1,449.5          
Total debt, including current portion
    477.0       491.3       495.9       500.8       775.0          
Noncontrolling interest(6)
    10.6       10.6       10.6       10.6       4.3          
Total CVR stockholders’ equity/members’ equity
    689.6       653.8       579.5       432.7       76.4          
Cash Flow Data:
                                               
Net cash flow provided by (used in):
                                               
Operating activities
    225.4       85.3       83.2       145.9       186.6          
Investing activities
    (31.3 )     (48.3 )     (86.5 )     (268.6 )     (240.2 )        
Financing activities
    (31.0 )     (9.0 )     (18.3 )     111.3       30.8          
Other Financial Data:
                                               
Capital expenditures for property, plant and equipment
    32.4       48.8       86.5       268.6       240.2          
 
 
(1) Amounts are shown exclusive of depreciation and amortization.
 
(2) 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.
 
(3) During the years ended December 31, 2010, 2009, 2008, 2007 and 2006, we recognized a loss of $16.6 million, $2.1 million, $10.0 million, $1.3 million and $23.4 million, respectively, on early extinguishment of debt.
 
(4) 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,
    2010   2009   2008   2007   2006    
    (in millions)
 
Loss on extinguishment of debt(a)
  $ 16.6     $ 2.1     $ 10.0     $ 1.3     $ 23.4          
Letter of credit expense and interest rate swap not included in interest expense(b)
    4.7       13.4       7.4       1.8                
Major scheduled turnaround expense(c)
    4.8             3.3       76.4       6.6          
Unrealized (gain) loss from Cash Flow Swap
          40.9       (253.2 )     103.2       (126.8 )        
Share-based compensation(d)
    37.2       8.8       (42.5 )     44.1       16.9          
Goodwill impairment(e)
                42.8                      
 
 
  (a)  Represents (1) for 2010, a premium of 2.0% paid in connection with unscheduled prepayments and payoff of our tranche D term loan contributing $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 senior secured notes, $0.1 million of third party costs were immediately expensed. In December 2010, we made a voluntary unscheduled principal payment on our senior secured 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; (2) for 2009, the write-off of $2.1 million of previously deferred financing costs in connection with the reduction, effective June 1, 2009, and eventual termination of the first priority funded letter of credit facility on October 15, 2009; (3) for 2008, the write-off of $10.0 million of previously deferred financing costs in connection with the second amendment to our first priority credit facility on December 22, 2008;

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  (4) for 2007, the write-off of $1.3 million of previously deferred financing costs in connection with the repayment and termination of three credit facilities on October 26, 2007; and (5) for 2006, the write-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006.
 
  (b)  Consists of fees which are expensed to selling, general and administrative expenses in connection with our letters of credit outstanding and the first priority funded letter of credit facility issued in support of the Cash Flow Swap until it was terminated effective October 15, 2009.
 
  (c)  Represents expense associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery.
 
  (d)  Represents the impact of share-based compensation awards.
 
  (e)  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.
 
(5) Earnings per share and weighted-average shares outstanding are shown on a pro forma basis for 2007 and 2006.
 
(6) Noncontrolling interest at December 31, 2006 reflects common stock in two of our subsidiaries owned by our chief executive officer (which were exchanged for shares of our common stock with an equivalent value prior to the consummation of our initial public offering). 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. 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.
 
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 Report, 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:
 
  •  statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future;
 
  •  statements relating to future financial performance, future capital sources and other matters; and
 
  •  any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions.
 
Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Report 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


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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 document. We undertake no obligation to update or revise publicly any forward-looking statements to reflect events or circumstances that occur after the date of this Report, or to reflect the occurrence of unanticipated events.
 
Overview and Executive Summary
 
We are an independent petroleum refiner and marketer of high value transportation fuels. In addition, we currently own all of the interests (other than the managing general partner interest and associated IDRs) in a limited partnership which produces nitrogen fertilizers in the form of ammonia and UAN.
 
We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2010, 2009 and 2008, we generated consolidated net sales of $4.1 billion, $3.1 billion and $5.0 billion, respectively, and operating income of $93.1 million, $208.2 million and $148.7 million, respectively. Our petroleum business generated net sales of $3.9 billion, $2.9 billion and $4.8 billion, respectively, over these periods. The nitrogen fertilizer business generated net sales of $180.5 million, $208.4 million and $263.0 million, respectively, over these periods. Our petroleum business generated operating income of $104.6 million, $170.2 million and $31.9 million for the years ended December 31, 2010, 2009 and 2008, respectively. Our nitrogen fertilizer business generated operating income of $20.4 million, $48.9 million and $116.8 million for the years ended December 31, 2010, 2009 and 2008, respectively.
 
Petroleum business.  Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude oil refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system with a gathering capacity of approximately 35,000 bpd serving Kansas, Oklahoma, western Missouri and southwestern Nebraska, (2) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg, Kansas and at throughput terminals on Magellan and NuStar’s refined products distribution systems, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of 1.2 million barrels and (4) storage and terminal facilities for refined fuels and asphalt in Phillipsburg, Kansas. The crude oil gathering system is supported by approximately 300 miles of Company owned and leased pipeline.
 
Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude oil variety in the world capable of being transported by pipeline. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.
 
Crude oil is supplied to our refinery through our gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead and Keystone pipelines (as discussed more fully in Note 15 to the financial statements) from Canada and have access to foreign and deepwater domestic crude oil via the Seaway Pipeline system from the U.S. Gulf Coast to Cushing. We also maintain leased storage in Cushing to facilitate optimal crude oil purchasing and blending. Our refinery blend consists of a combination of crude oil grades, including onshore and offshore domestic grades, various Canadian medium and heavy sours and sweet synthetics and from time-to-time a variety of South American, North Sea, Middle East and West African imported grades. The access to a variety of crude oils coupled with the complexity of our refinery allows us to purchase crude oil at a discount to WTI. Our consumed crude cost discount to WTI for 2010 was $3.39 per barrel compared to $4.65 per barrel in 2009 and $2.12 per barrel in 2008.
 
Nitrogen fertilizer business.  The nitrogen fertilizer business consists of our interest in the Partnership, which is controlled by our affiliates. The nitrogen fertilizer business consists of a nitrogen fertilizer facility that 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


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to function independently of the other, thereby providing redundancy and improving reliability. In 2010, the nitrogen fertilizer business produced 392,745 tons of ammonia, of which approximately 60% was upgraded into 578,272 tons of UAN.
 
The primary raw material feedstock utilized in our nitrogen fertilizer production process is pet coke, which is produced during the crude oil refining process. In contrast, substantially all of the nitrogen fertilizer businesses’ competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been significantly less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. By using pet coke as the primary raw material feedstock instead of natural gas, the nitrogen fertilizer business has historically been the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. The nitrogen fertilizer business currently purchases most of its pet coke from CVR pursuant to a long-term agreement having an initial term that ends in 2027, subject to renewal. During the past five years, over 70% of the pet coke utilized by the nitrogen fertilizer plant was produced and supplied by CVR’s crude oil refinery.
 
CVR’s Shelf Registration Statements
 
On March 6, 2009, the SEC declared effective our registration statement on Form S-3 (initially filed on June 19, 2008 and amended on February 12, 2009), which enabled (1) the Company to offer and sell from time to time, in one or more public offerings or direct placements, up to $250.0 million of common stock, preferred stock, debt securities, warrants and subscription rights and (2) certain selling stockholders to offer and sell from time to time, in one or more offerings, up to 15,000,000 shares of our common stock. As afforded by the registration statement, a stockholder, CALLC II, sold into the public market 7,376,264 shares on November 12, 2009.
 
On July 1, 2010, the SEC declared effective a second registration statement on Form S-3 (initially filed on April 12, 2010 and amended on June 24, 2010), which enabled certain selling stockholders to offer and sell from time to time, in one or more offers up to 55,738,127 shares of our common stock. As afforded by the registration statement, 20,700,000 shares were sold into the public market on November 24, 2010, by the following stockholders: CALLC — 11,686,158 shares; CALLC II — 8,943,842 shares; and John J. Lipinski, our president, chief executive officer and chairman of the Board — 70,000 shares.
 
In February 2011, CALLC and CALLC II sold 11,759,023 shares and 15,113,254 shares, respectively, into the public market. As a result of this sale, CALLC II is no longer a shareholder of the Company. As of the date of this Report, CALLC owns 7,988,179 shares and has additional registration rights with respect to the remainder of their shares.
 
Major Influences on Results of Operations
 
Petroleum Business
 
Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of and demand for crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out (“FIFO”) accounting to value our inventory, crude oil price movements may impact net income in the short term because of changes in the value of our unhedged on-hand inventory. The effect of changes in crude oil prices on our results of operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.


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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 is calculated by assuming that two barrels of benchmark light sweet crude oil is converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI, we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude oil refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.
 
Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil and the price of WTI. The spread is referred to as our consumed crude oil differential. Our refinery margin can be impacted significantly by the consumed crude oil differential. Our consumed crude oil differential will move directionally with changes in the WTS differential to WTI and the West Canadian Select (“WCS”) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude oil differential and published differentials will vary depending on the volume of light medium sour crude oil and heavy sour crude oil we purchase as a percent of our total crude oil volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.
 
We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices in our region include the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact that the actual product specifications used to determine the NYMEX 2-1-1 crack spread are different from the actual production in our refinery is that prices we realize are different than those used in determining the 2-1-1 crack spread. The difference between our price and the price used to calculate the 2-1-1 crack spread is referred to as gasoline PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and Ultra Low Sulfur Diesel PADD II, Group 3 vs. NYMEX basis, or Ultra Low Sulfur Diesel basis. If both gasoline and Ultra Low Sulfur Diesel basis are greater than zero, this means that prices in our marketing area exceed those used in the 2-1-1 crack spread.
 
Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy, which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices. Assuming the same rate of consumption of natural gas for the year ended December 31, 2010, a $1.00 change in natural gas prices would have increased or decreased our natural gas costs by approximately $3.2 million.


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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 refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The refinery generally undergoes a facility turnaround every four to five years. The length of the turnaround is contingent upon the scope of work to be completed. The next turnaround for our refinery is scheduled to commence in the fourth quarter of 2011 and will be completed in the first quarter of 2012.
 
Our refinery experienced an equipment malfunction and small fire in connection with its FCCU on December 28, 2010, which led to reduced crude throughput and cost approximately $6.5 million to repair (before any insurance recovery). 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 will be lost in the first quarter due to this incident.
 
Nitrogen Fertilizer Business
 
In the nitrogen fertilizer business, earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices and direct operating expenses. Unlike its competitors, the nitrogen fertilizer business does not use natural gas as a feedstock and uses a minimal amount of natural gas as an energy source in its operations. As a result, volatile swings in natural gas prices have a minimal impact on its results of operations. Instead, our adjacent refinery supplies the nitrogen fertilizer business with most of the pet coke feedstock it needs pursuant to a long-term pet coke supply agreement entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets. Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.
 
In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.


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Natural gas is the most significant raw material required in our competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility. This pricing and volatility has a direct impact on our competitors’ cost of producing nitrogen fertilizer.
 
In order to assess the operating performance of the nitrogen fertilizer business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs.
 
We have a significant transportation cost advantage when compared to our out-of-region competitors in serving the attractive U.S. farm belt agricultural market. In 2010, approximately 45% of the corn planted in the United States was grown within a $35/UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors’ revenues 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 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 2010, the nitrogen fertilizer business upgraded approximately 60% of its ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.
 
The direct operating expense structure of the nitrogen fertilizer business also directly affects its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These costs comprise the fixed costs associated with the nitrogen fertilizer plant. Variable costs associated with the nitrogen fertilizer plant averaged approximately 14% of direct operating expenses over the 24 months ended December 31, 2010. The average annual operating costs over the 24 months ended December 31, 2010 have approximated $86 million, of which substantially all are fixed in nature.
 
The nitrogen fertilizer business’ largest raw material expense is pet coke, which it purchases from the petroleum business and third parties. In December 31, 2010, 2009 and 2008, the nitrogen fertilizer business spent $7.4 million, $12.8 million and $14.1 million, respectively, for pet coke, which equaled an average cost per ton of $17, $27 and $31, respectively.
 
Consistent, safe, and reliable operations at the nitrogen fertilizer plant are critical to its financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2010, at a cost of approximately $3.5 million. In connection with the biennial turnaround, the nitrogen fertilizer business also wrote off approximately $1.4 million of fixed assets. The next facility turnaround is currently scheduled for the fourth quarter of 2012.


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Agreements Between CVR Energy and the Partnership
 
In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership in October 2007, we entered into a number of agreements with the Partnership that govern the business relations between the parties. These include the pet coke supply agreement mentioned above, under which the petroleum business sells pet coke to the nitrogen fertilizer business; a services agreement, in which our management operates the nitrogen fertilizer business; a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; an easement agreement; an environmental agreement; and a lease agreement pursuant to which we lease office space and laboratory space to the Partnership. We expect that certain of these agreements would be amended and/or restated in connection with any offering of the Partnership equity interests in a public offering.
 
The nitrogen fertilizer business obtains most (over 70% on average during the last five years) of the pet coke it needs from our adjacent crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price the nitrogen fertilizer business pays pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.
 
For the periods ending December 31, 2010, 2009 and 2008, the nitrogen fertilizer segment was charged $10.6 million, $12.1 million and $13.2 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.
 
Refinancing and Prior Indebtedness
 
In January 2010, we made a voluntary unscheduled principal payment of $20.0 million on our tranche D term loans. In addition, we made a second voluntary unscheduled principal payment of $5.0 million in February 2010, reducing our tranche D term loans’ outstanding principal balance to $453.3 million. In connection with these voluntary prepayments, we paid a 2.0% premium totaling $0.5 million to the lenders of our first priority credit facility. In April 2010, we paid off the remaining $453.0 million tranche D term loans. This payoff was made possible by the issuance of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). In connection with the payoff, we paid a 2.0% premium totaling approximately $9.1 million. In addition, previously deferred financing costs totaling approximately $5.4 million associated with the first priority credit facility term debt were also written off at that time. The Company also recognized approximately $0.1 million of third party costs at the time the Notes were issued. Other financing and third party costs incurred at the time were deferred and are amortized over the respective terms of the Notes. The premiums paid, previously deferred financing costs subject to write-off and immediately recognized third party expenses are reflected as a loss on extinguishment of debt in our Consolidated Statements of Operations.
 
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 March 12, 2010, CRLLC entered into a fourth amendment to its first priority credit facility. The amendment, among other things, provided CRLLC the opportunity to issue junior lien debt, subject to certain


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conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay the tranche D term loans. The amendment also provided CRLLC the ability to issue up to $350.0 million of first lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay all of the remaining tranche D term loans.
 
In connection with the fourth amendment, CRLLC incurred lender fees of approximately $4.5 million. These fees were recorded as deferred financing costs in the first quarter of 2010. In addition, CRLLC incurred third party costs of approximately $1.5 million primarily consisting of administrative and legal costs. Of the third party costs incurred we expensed $1.1 million in 2010 and the remaining $0.4 million was recorded as additional deferred financing costs.
 
On October 2, 2009, CRLLC entered into a third amendment to its first priority credit facility. The amendment was entered into, among other things, to provide financial flexibility to us through modifications to our financial covenants for the remaining term of the credit facility. Additionally, the amendment afforded CVR (which is not a party to the credit agreement) the opportunity to incur indebtedness by allowing subsidiaries of CVR, which are parties to the credit agreement, to distribute dividends to CVR in order to fund interest payments of up to $20.0 million annually, so long as CVR agreed, for the benefit of the lenders to contribute at least 35% of the net proceeds of such indebtedness to CRLLC for the purpose of repaying the tranche D term loans under the credit agreement. In addition, CVR is required to agree for the benefit of the lenders not to use the proceeds of such indebtedness to repurchase its capital stock or pay any dividend or other distributions on its capital stock.
 
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.
 
During June 2009, CRLLC successfully reduced the first priority funded letter of credit 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 in our Consolidated Statements of Operations as a loss on extinguishment of debt.
 
On December 22, 2008, CRLLC amended its outstanding credit facility for the purpose of modifying certain restrictive covenants and related financial definitions. In connection with this amendment, we paid approximately $8.5 million of lender and third party costs. We immediately expensed $4.7 million of these costs and the remainder was deferred to be amortized to interest expense over the respective term of the first priority term debt, revolver and funded letters of credit, as applicable. Previously deferred financing costs of $5.3 million were also written off at that time. The total amount expensed in 2008 of $10.0 million, is reflected in our Consolidated Statements of Operations as a loss on extinguishment of debt.
 
Goodwill Impairment Charges
 
As a result of our annual review of goodwill in 2008, we recorded non-cash charges of $42.8 million during the fourth quarter, to write-off the entire balance of the petroleum segment’s goodwill. The write-off was associated with lower cash flow forecasts as well as a significant decline in market capitalization in the fourth quarter of 2008 that resulted in large part from severe disruptions in the capital and commodities markets.
 
2010 and 2008 Turnarounds
 
During the fourth quarter of 2010 and 2008, we completed a planned turnaround of the nitrogen fertilizer plant at a total cost of approximately $3.5 million and $3.3 million, respectively, of which the majority of


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these costs were expensed in the fourth quarter of each respective year. In connection with the nitrogen fertilizer plant’s biennial turnaround, we also wrote off approximately $1.4 million and $2.3 million of fixed assets for the years ended December 31, 2010 and 2008, respectively. For the year ended December 31, 2010, our petroleum segment incurred approximately $1.2 million of turnaround costs in preparation for the 2011/2012 turnaround. No planned major turnaround activities occurred in 2009.
 
Cash Flow Swap
 
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 year ended December 31, 2010. For the years ended December 31, 2009 and 2008, we recorded net realized losses of $14.3 million and $110.4 million with respect to the Cash Flow Swap, respectively. In addition, for the years ended December 31, 2009 and 2008, we recorded net unrealized gains (losses) of $(40.9) million and $253.2 million, respectively.
 
Share-Based Compensation
 
Through a wholly-owned subsidiary, we have the two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”), whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. We account for awards under our Phantom Unit Plans as liability based awards. In accordance with FASB ASC Topic 718, Compensation — Stock Compensation, the expense associated with these awards for 2010 is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of our common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.
 
Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment by an investor for stock-based compensation granted to employees of an equity method investee. In addition, these awards are subject to an accounting standard issued by the FASB which provides guidance regarding the accounting treatment for equity instruments that are issued to 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, 2010, 2009 and 2008, we increased (reversed) compensation expense by $34.8 million, $7.9 million and $(43.3) million, respectively, as a result of the phantom and override unit share-based compensation awards. We expect to incur additional incremental share-based compensation expense with respect to unvested CALLC and CALLC II override units and phantom awards to the extent our common stock price increases.
 
Through the Company’s Long-Term Incentive Plan, shares of non-vested common stock may be awarded to the Company’s employees, officers, consultants, advisors and directors. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock and the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the years ended December 31, 2010, 2009 and 2008, we incurred compensation expense of $2.4 million, $0.8 million and $0.6 million, respectively, related to non-vested share-based compensation awards.


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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.
 
The cost to repair the damage caused by the incident was approximately $10.5 million, and repairs were substantially complete prior to the end of December 2010. Of the costs incurred approximately $4.5 million of the costs was capitalized. The nitrogen fertilizer plant is covered for property damage under CVR’s insurance policies, which have a deductible of $2.5 million. We anticipate that substantially all of the repair costs in excess of the $2.5 million deductible will be covered by insurance. These insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs we have incurred relating to the damage and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. In connection with the incident, the Company recorded an insurance receivable of $4.5 million of which approximately $4.3 million of insurance proceeds were received as of December 31, 2010 and the remaining $0.2 million was received in January 2011.
 
Fertilizer Plant Property Taxes
 
The nitrogen fertilizer plant received a ten year tax abatement from Montgomery County, Kansas in connection with its construction that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed the nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment has resulted in an increase to annual property tax liability for the plant by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, and approximately $11.7 million for the year ended December 31, 2010. We do not agree with the county’s classification of the nitrogen fertilizer plant and are currently disputing it before the Kansas Court of Tax Appeals (“COTA”). However, the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008 have been fully accrued and paid. These amounts are reflected as a direct operating expense in the nitrogen fertilizer business’ financial results. An evidentiary hearing before COTA occurred during the first quarter of 2011 regarding our property tax claims for the year ended December 31, 2008. We believe COTA is likely to issue a ruling sometime during 2011. However, the timing of a ruling in the case is uncertain, and there can be no assurance we will receive a ruling in 2011. If we are successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, a portion of the accrued and paid expenses would be refunded to the nitrogen fertilizer business, which could have a material positive effect on its results of operations. If we are not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, we expect that the nitrogen fertilizer business will pay taxes at or below the elevated rates described above.
 
Consolidation of Nitrogen Fertilizer Limited Partnership
 
Prior to the consummation of our initial public offering, we transferred our nitrogen fertilizer business to the Partnership and sold the managing general partner interest in the Partnership to an entity owned by CALLC III and senior management. At December 31, 2010, we owned all of the interests in the Partnership (other than the managing general partner interest and associated IDRs) and are entitled to all cash that is distributed by the Partnership, except with respect to the IDRs. The Partnership is operated by our senior management pursuant to a services agreement among us, the managing general partner and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, us, as special general partner. As special general partner of the Partnership, we have joint management rights regarding the appointment, termination and compensation of the chief executive officer and chief financial officer of the managing general partner, have the right to


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designate two members to the board of directors of the managing general partner and have joint management rights regarding specified major business decisions relating to the Partnership.
 
We consolidate the Partnership for financial reporting purposes. We have determined that following the sale of the managing general partner interest to CALLC III and senior management, the Partnership is a variable interest entity (“VIE”) under the provisions of FASB ASC 810-10, Consolidation — Variable Interest Entities (“ASC 810-10”).
 
Using criteria set forth by ASC 810-10, our management has determined that we are the primary beneficiary of the Partnership, although 100% of the managing general partner interest is owned by CALLC III and senior management outside our reporting structure. Since we are the primary beneficiary, the financial statements of the Partnership remain consolidated in our financial statements. The managing general partner’s interest is reflected as a non-controlling interest on our Consolidated Balance Sheets.
 
The conclusion that CVR is the primary beneficiary of the Partnership and is required to consolidate the Partnership as a VIE is based primarily on three criteria. First, the general partner has the power to direct the activities over the Partnership that most significantly impacts the entity’s economic performance. The managing general partner is a wholly-owned subsidiary of CALLC III. CALLC III is owned by the Goldman Sachs Funds and the Kelso Funds that owned, as of December 31, 2010, approximately 40% of the common stock of CVR, and by members of CVR’s management. Second, the special general partner is a wholly-owned subsidiary of CVR and substantially all of the expected losses are absorbed by the special general partner and substantially all of the equity investment at risk was contributed on behalf of the special general partner, with nominal amounts contributed by the managing general partner. Finally, the special general partner is also expected to receive the majority, if not substantially all, of the expected returns of the Partnership through the Partnership’s cash distribution provisions.
 
We periodically reassess whether we remain the primary beneficiary of the Partnership in order to determine if consolidation of the Partnership remains appropriate on a going forward basis. Should we determine that we are no longer the primary beneficiary of the Partnership, we will be required to deconsolidate the Partnership in our financial statements for accounting purposes on a going forward basis. In that event, we would be required to account for our investment in the Partnership under the equity method of accounting, which would affect our reported amounts of consolidated revenues, expenses and other income statement items.
 
The principal events that would require the reassessment of our accounting treatment related to our interest in the Partnership include:
 
  •  a sale of some or all of our partnership interests to an unrelated party;
 
  •  a sale of the managing general partner interest to a third party;
 
  •  the issuance by the Partnership of partnership interests to parties other than us or our related parties; and
 
  •  the acquisition by us of additional partnership interests (either new interests issued by the Partnership or interests acquired from unrelated interest holders).
 
In addition, we would need to reassess our consolidation of the Partnership if the Partnership’s governing documents or contractual arrangements are changed in a manner that reallocates between us and other unrelated parties either (1) the power to direct the activities of the Partnership that most significantly impacts its economic performance; (2) the obligation to absorb the expected losses of the Partnership; or, (3) the right to receive the expected residual returns of the Partnership.
 
If the offering of Partnership interests described in the Registration Statement filed with the SEC on December 20, 2010, as amended, is consummated, we believe we would continue to consolidate the Partnership in our financial statements as a VIE. However, the initial public offering may not occur on the terms described in the Registration Statement or at all, and we are not making any offers to sell, or soliciting any offers to buy, common units of the Partnership.


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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 2.7 million barrels of crude oil storage in Cushing, Oklahoma 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.
 
Nitrogen Fertilizer Business
 
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 31% between September 2001 and September 2009, 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 (“USDA”).
 
World grain demand has increased 11% 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 $3.63 per bushel, an increase of 72% above the average price of $2.11 per bushel during the preceding five years. Recently, this trend has continued as U.S. 30-day corn and wheat futures increased 78% and 76%, respectively, from June 1, 2010 to December 31, 2010. During this same time period, Southern Plains ammonia prices increased 74% from $360 per ton to $625 per ton and corn belt UAN prices increased 32% from $252 per ton to $333 per ton. At existing grain prices and prices implied by futures markets, farmers are expected to generate substantial profits, leading to relatively inelastic demand for fertilizers. Nitrogen fertilizer prices have decoupled from their historical correlation with natural gas prices and are now driven primarily by demand dynamics. Nitrogen fertilizer prices in the U.S. farm belt are typically higher than U.S. Gulf Coast prices because it is costly to transport nitrogen fertilizer.
 
The United States is the world’s largest exporter of coarse grains, accounting for 46% of world exports and 31% 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 46% 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.


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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.
 
Consolidated Results of Operations
 
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, 2010 with the year ended December 31, 2009 and the year ended December 31, 2009 with the year ended December 31, 2008.
 
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 are not a sum of only the operating results of the petroleum and nitrogen fertilizer businesses.
 
The following table provides an overview of our results of operations during the past three fiscal years:
 
                         
    Year Ended December 31,  
Consolidated Financial Results
  2010     2009     2008  
    (in millions)  
 
Net sales
  $ 4,079.8     $ 3,136.3     $ 5,016.1  
Cost of product sold (exclusive of depreciation and amortization)
    3,568.1       2,547.7       4,461.8  
Direct operating expenses (exclusive of depreciation and amortization)
    240.8       226.0       237.5  
Selling, general and administrative expense (exclusive of depreciation and amortization)
    92.0       68.9       35.2  
Net costs associated with flood
    (1.0 )     0.6       7.9  
Depreciation and amortization(1)
    86.8       84.9       82.2  
Goodwill impairment(2)
                42.8  
                         
Operating income
  $ 93.1     $ 208.2     $ 148.7  
Net income(3)
    14.3       69.4       163.9  
 
 
(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:
 


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    Year Ended December 31,
Consolidated Financial Results
  2010   2009   2008
    (in millions)
 
Depreciation and amortization excluded from cost of product sold
  $ 2.8     $ 2.9     $ 2.5  
Depreciation and amortization excluded from direct operating expenses
    81.9       80.0       78.0  
Depreciation and amortization excluded from selling, general and administrative expense
    2.1       2.0       1.7  
                         
Total depreciation and amortization
  $ 86.8     $ 84.9     $ 82.2  
                         
 
(2) 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 goodwill.
 
(3) The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature:
 
                         
    Year Ended December 31,  
Consolidated Financial Results
  2010     2009     2008  
    (in millions)  
 
Loss on extinguishment of debt(a)
  $ 16.6     $ 2.1     $ 10.0  
Letter of credit expense & interest rate swap not included in interest expense(b)
    4.7       13.4       7.4  
Major scheduled turnaround expense(c)
    4.8             3.3  
Unrealized (gain) loss from Cash Flow Swap
          40.9       (253.2 )
Share-based compensation expense(d)
    37.2       8.8       (42.5 )
Goodwill impairment(e)
                42.8  
 
 
(a) For 2010, we recognized a premium of 2.0% premium paid in connection with unscheduled prepayments and payoff of our tranche D term loan contributing $9.6 million of the loss on extinguishment of debt. 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 senior secured notes, $0.1 million of third party costs were immediately expensed. In December 2010, we made a principal prepayment on our senior secured notes resulting in a premium payment of 3.0% and a partial write-off of previously deferred financing costs, underwriting discount and original issue discount totaling $1.6 million. For 2009, the $2.1 million loss on extinguishment of debt represents the write-off of deferred financing costs associated with the reduction of the first priority funded letter of credit facility from $150.0 million to $60.0 million, effective June 1, 2009, and eventual termination of the first priority funded letter of credit facility effective October 15, 2009. For 2008, represents the write-off of $10.0 million of deferred financing costs in connection with the second amendment to our first priority credit facility, which was amended on December 22, 2008.
 
(b) 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.
 
(c) Represents expenses associated with major scheduled turnarounds at the nitrogen fertilizer plant and our refinery.
 
(d) Represents the impact of share-based compensation awards.
 
(e) 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,

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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.
 
Year Ended December 31, 2010 Compared to the Year Ended December 31, 2009 (Consolidated)
 
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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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.
 
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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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


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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 our 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 or 55.3%. 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).
 
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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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,


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2009. The change in gain (loss) on derivatives for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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 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.
 
Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008 (Consolidated)
 
Net Sales.  Consolidated net sales were $3,136.3 million for the year ended December 31, 2009, compared to $5,016.1 million for the year ended December 31, 2008. The decrease of $1,879.8 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily due to a decrease in petroleum net sales of $1,839.4 million that resulted from lower product prices ($1,866.8 million), partially offset by slightly higher sales volumes ($27.4 million). The decline in average finished product prices was primarily due to a decline in underlying feedstock costs compared to 2008. Nitrogen fertilizer net sales decreased $54.6 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, as a result of lower average plant gate prices ($91.3 million) and partially offset by an increase in overall sales volumes ($36.7 million).
 
Cost of Product Sold (Exclusive of Depreciation and Amortization).  Consolidated cost of product sold (exclusive of depreciation and amortization) was $2,547.7 million for the year ended December 31, 2009, as compared to $4,461.8 million for the year ended December 31, 2008. The decrease of $1,914.1 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, primarily resulted from a significant decrease in crude oil prices. On a year-over-year basis, our consumed crude oil prices decreased


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approximately 42% from an average price of $98.52 per barrel in 2008 compared to an average price of consumed crude oil of $57.64 per barrel in 2009. Partially offsetting the decrease in raw material prices was a 2.3% increase in crude oil throughput in 2009 compared to 2008. In addition, the nitrogen fertilizer business experienced higher costs of product sold as a result of increased sales volume, freight expense and hydrogen costs.
 
Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Consolidated direct operating expenses (exclusive of depreciation and amortization) were $226.0 million for the year ended December 31, 2009, as compared to $237.5 million for the year ended December 31, 2008. This decrease of $11.5 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was due to a decrease in petroleum and nitrogen fertilizer direct operating expenses of $9.8 million and $1.7 million, respectively. This decrease was primarily the result of net decreases in downtime repairs and maintenance ($13.0 million), outside services and other direct operating expenses ($9.1 million), production chemicals ($3.7 million) and turnaround ($3.4 million). The decrease in repairs and maintenance expense was the result of fewer contract maintenance personnel and a decreased need for equipment repairs for the year ended December 31, 2009 compared to the year ended December 31, 2008. Additionally in 2008 the petroleum business experienced higher costs related to work related to the fluid catalytic cracking unit, hydrodesulfurization unit and the start of up the continuous catalyst regeneration (CCR) reformer that occurred in 2008 and not 2009. Additionally, the nitrogen fertilizer plant turnaround in 2008 reduced the need for additional repairs in maintenance for 2009. The decrease of outside services and other direct operating expenses was primarily the result of a decrease in the work performed by outside consultants, lower costs for environmental and waste water services and less desox consumption for the year ended December 31, 2009 compared to the year ended December 31, 2008 for our petroleum business. The decrease in production chemicals was primarily the result of reduced consumption of various catalyst and additives utilized by the petroleum business. The decrease in turnaround costs was the result of the nitrogen fertilizer plant’s biennial turnaround that occurred in 2008 and not 2009. These decreases were partially offset by net increases in labor ($9.8 million), property taxes ($4.2 million), catalyst ($1.0 million), energy and utilities ($0.6 million) and insurance ($0.2 million), combined with a decrease in the price we received for sulfur produced as a by-product of our manufacturing process ($2.0 million). Increased labor costs were primarily the result of increased headcount of the petroleum business and an increase in share-based compensation expense.
 
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization).  Consolidated selling, general and administrative expenses (exclusive of depreciation and amortization) were $68.9 million for the year ended December 31, 2009, as compared to $35.2 million for the year ended December 31, 2008. This $33.7 million increase in selling, general and administrative expenses over the comparable period was primarily the result of increases in share-based compensation ($45.3 million), administrative payroll ($4.2 million) and bank charges ($1.1 million), which were partially offset by decreases in expenses associated with outside services ($6.1 million), loss on disposition of assets ($5.7 million), bad debt expense ($3.0 million) and other selling, general and administrative expenses ($2.1 million). The increase in share-based compensation for the year ended December 31, 2009 was primarily the result of the significant decrease in our stock price in 2008 which resulted in a reversal of share-based compensation for the year ended December 31, 2008. Conversely, our stock price increased from December 31, 2008 to December 31, 2009, resulting in increased share-based compensation expense. The decrease in loss on disposition of assets was primarily the result of decreased disposed assets by the nitrogen fertilizer business that were made during the biennial turnaround that occurred for year ended December 31, 2008. The decrease in bad debt expense was the result of a lower provision needed for the year ended December 31, 2009 compared to the year ended December 31, 2008. During 2008, we recorded a significant provision for one specific receivable outstanding and no such provision of equal or greater amount was recorded for the year ended December 31, 2009.
 
Net Costs Associated with Flood.  Consolidated net costs associated with the June/July 2007 flood for the year ended December 31, 2009 approximated $0.6 million, as compared to $7.9 million for the year ended December 31, 2008.
 
Goodwill Impairment.  In connection with our 2009 annual goodwill impairment testing, we determined that the goodwill associated with our Nitrogen Fertilizer business was not impaired, thus no impairment charge


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was recorded for 2009. In 2008, we wrote-off approximately $42.8 million of goodwill in connection with our annual impairment testing. This goodwill was entirely attributable to the petroleum business.
 
Operating Income.  Consolidated operating income was $208.2 million for the year ended December 31, 2009, as compared to operating income of $148.7 million for the year ended December 31, 2008, an increase of $59.5 million or 40.0%. For the year ended December 31, 2009, as compared to the year ended December 31, 2008, petroleum operating income increased $138.3 million primarily as a result of a decrease in the cost of product sold as well as the fact that in 2008 the petroleum segment recognized a goodwill impairment charge of $42.8 million compared to none in 2009. Partially offsetting the increase in operating income from the petroleum business was a decrease of $67.9 million related to nitrogen fertilizer operations. This decrease is primarily the result of lower plant gate prices for 2009 compared to 2008. In addition to decreased margins related to nitrogen fertilizer, consolidated selling, general and administrative expenses increased by $33.7 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, which was primarily the result of increased share-based compensation expense.
 
Interest Expense.  Consolidated interest expense for the year ended December 31, 2009 was $44.2 million, as compared to interest expense of $40.3 million for the year ended December 31, 2008. This 9.7% increase for the year ended December 31, 2009, as compared to the year ended December 31, 2008, primarily resulted from an increase in our weighted-average interest rate on a year-over-year basis.
 
Gain (Loss) on Derivatives, Net.  For the year ended December 31, 2009, we incurred $65.3 million in net losses on derivatives. This compares to a $125.3 million net gain on derivatives for the year ended December 31, 2008. The change in gain (loss) on derivatives for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily attributable to the realized and unrealized losses on our Cash Flow Swap. For the year ended December 31, 2009, we recognized a $40.9 million unrealized loss on the cash flow swap compared to a $253.2 million unrealized gain for the year ended December 31, 2008. Unrealized losses on our Cash Flow Swap for the year ended December 31, 2009 reflected an increase in the crack spread values relative to December 31, 2008 on the unrealized positions comprising the Cash Flow Swap. Realized losses on the Cash Flow Swap for the year ended December 31, 2009 and the year ended December 31, 2008 were $14.3 million and $110.4 million, respectively. The primary cause of the remaining difference was attributable to an increase in net realized losses on other agreements and interest rate swap of $1.0 million offset by an increase in net unrealized gains of $8.4 million associated with the other agreements and interest rate swap.
 
Income Tax Expense.  Income tax expense for the year ended December 31, 2009 was $29.2 million or 29.7% of income before income taxes, as compared to an income tax expense for the year ended December 31, 2008 of $63.9 million or 28.1% of income before income taxes. This is in comparison to a combined federal and state expected statutory rate of 39.7% for 2009 and 2008. Our effective tax rate increased for the year ended December 31, 2009, as compared to the year ended December 31, 2008, due to the correlation between the amount of credits generated due to the production of ultra low sulfur diesel fuel and Kansas state incentives generated under the HPIP, in relative comparison with the pre-tax income level in each year. We also recognized a federal income tax benefit of approximately $4.8 million in 2009, compared to $23.7 million in 2008, on a credit of approximately $7.4 million in 2009, compared to a credit of approximately $36.5 million in 2008 related to the production of ultra low sulfur diesel. In addition, state income tax credits, net of federal expense, approximating $3.2 million were earned and recorded in 2009 that related to Kansas HPIP credits, compared to $14.4 million earned and recorded in 2008.
 
Net Income.  For the year ended December 31, 2009, net income decreased to $69.4 million as compared to net income of $163.9 million for the year ended December 31, 2008.
 
Petroleum Business Results of Operations
 
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 refinery’s 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.


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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,  
    2010     2009     2008  
    (in millions)  
 
Petroleum Business Financial Results
                       
Net sales
  $ 3,903.8     $ 2,934.9     $ 4,774.3  
Cost of product sold (exclusive of depreciation and amortization)
    3,538.0       2,514.3       4,449.4  
Direct operating expenses (exclusive of depreciation and amortization)(1)
    154.1       141.6       151.4  
Net costs associated with flood
    (1.0 )     0.6       6.4  
Depreciation and amortization
    66.4       64.4       62.7  
                         
Gross profit(2)
  $ 146.3     $ 214.0     $ 104.4  
Plus direct operating expenses (exclusive of depreciation and amortization)
    154.1       141.6       151.4  
Plus net costs associated with flood
    (1.0 )     0.6       6.4  
Plus depreciation and amortization
    66.4       64.4       62.7  
                         
Refining margin(3)
  $ 365.8     $ 420.6     $ 324.9  
Goodwill impairment(4)
  $     $     $ 42.8  
Operating income
  $ 104.6     $ 170.2     $ 31.9  
Adjusted Petroleum EBITDA(5)
  $ 154.7     $ 142.3     $ 109.1  
 
                         
    Year Ended December 31,
    2010   2009   2008
    (dollars per barrel)
 
Key Operating Statistics
                       
Per crude oil throughput barrel:
                       
Refining margin(3)
  $ 8.84     $ 10.65     $ 8.39  
Gross profit(2)
    3.54       5.42       2.69  
Direct operating expenses (exclusive of depreciation and amortization)(1)
    3.72       3.58       3.91  
Direct operating expenses per barrel sold(6)
    3.32       3.21       3.47  
Barrels sold (barrels per day)(6)
    127,142       125,005       119,061  
 


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    Year Ended December 31,  
    2010     2009     2008  
          %           %           %  
 
Refining Throughput and Production
Data (bpd)
                                               
Throughput:
                                               
Sweet
    89,746       72.5       82,598       68.7       77,315       65.7  
Light/medium sour
    8,180       6.6       15,602       13.0       16,795       14.3  
Heavy sour
    15,439       12.5       10,026       8.3       11,727       10.0  
                                                 
Total crude oil throughput
    113,365       91.6       108,226       90.0       105,837       90.0  
All other feedstocks and blendstocks
    10,350       8.4       12,013       10.0       11,882       10.0  
                                                 
Total throughput
    123,715       100.0       120,239       100.0       117,719       100.0  
Production:
                                               
Gasoline
    61,136       49.1       62,309       51.6       56,852       48.0  
Distillate
    50,439       40.5       46,909       38.8       48,257       40.7  
Other (excluding internally produced fuel)
    12,978       10.4       11,549       9.6       13,422       11.3  
                                                 
Total refining production (excluding internally produced fuel)
    124,553       100.0       120,767       100.0       118,531       100.0  
Product price (dollars per gallon):
                                               
Gasoline
          $ 2.10             $ 1.68             $ 2.50  
Distillate
          $ 2.20             $ 1.68             $ 3.00  
 
                         
    Year Ended December 31,
    2010   2009   2008
 
Market Indicators (dollars per barrel)
                       
West Texas Intermediate (WTI) NYMEX
  $ 79.61     $ 62.09     $ 99.75  
Crude Oil Differentials:
                       
WTI less WTS (light/medium sour)
    2.15       1.53       3.44  
WTI less WCS (heavy sour)
    15.07       9.57       19.42  
NYMEX Crack Spreads:
                       
Gasoline
    9.62       9.05       4.76  
Heating Oil
    10.53       8.03       20.25  
NYMEX 2-1-1 Crack Spread
    10.07       8.54       12.50  
PADD II Group 3 Basis:
                       
Gasoline
    (1.49 )     (1.25 )     0.12  
Ultra Low Sulfur Diesel
    1.35       0.03       4.22  
PADD II Group 3 Product Crack:
                       
Gasoline
    8.13       7.81       4.88  
Ultra Low Sulfur Diesel
    11.88       8.06       24.47  
PADD II Group 3 2-1-1
    10.01       7.93       14.68  
 
 
(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.

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(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 refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) is taken directly from our Statements of Operations. Our calculation of refining margin may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period. We believe that refining margin and refining margin per crude oil throughput barrel is important to enable investors to better understand and evaluate our ongoing operating results and for greater transparency in the review of our overall business, financial, operational and economic financial performance.
 
(4) Upon applying the goodwill impairment testing criteria under existing accounting rules during the fourth quarter of 2008, we determined that the goodwill of the petroleum business was impaired, which resulted in a goodwill impairment loss of $42.8 million in the fourth quarter. This goodwill impairment is included in the petroleum business operating income but is excluded in the refining margin and the refining margin per crude oil throughput barrel.
 
(5) Adjusted Petroleum EBITDA represents operating income adjusted for FIFO impacts (favorable) unfavorable, share-based compensation, loss on disposition of assets, major scheduled turnaround expenses, realized gain (loss) on derivatives, net, goodwill impairment, 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, 2010, 2009 and 2008:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (unaudited)  
 
Petroleum:
                       
Petroleum operating income
  $ 104.6     $ 170.2     $ 31.9  
FIFO impacts (favorable), unfavorable(a)
    (31.7 )     (67.9 )     102.5  
Share-based compensation
    11.5       (3.7 )     (10.8 )
Loss on disposition of assets(b)
    1.3              
Major scheduled turnaround expenses(c)
    1.2              
Realized gain (loss) on derivatives, net
    0.7       (21.0 )     (121.0 )
Goodwill impairment(d)
                42.8  
Depreciation and amortization
    66.4       64.4       62.7  
Other income (expense)
    0.7       0.3       1.0  
                         
Adjusted Petroleum EBITDA
  $ 154.7     $ 142.3     $ 109.1  
 
 
(a) FIFO is the petroleum business’ basis for determining inventory value on a GAAP basis. Changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods thereby resulting in favorable FIFO impacts when crude oil prices increase and


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unfavorable FIFO impacts when crude oil prices decrease. The FIFO impact is calculated based upon inventory values at the beginning of the accounting period and at the end of the accounting period. In order to derive the FIFO impact per crude oil throughput barrel, we utilize the total dollar figures for the FIFO impact and divide by the number of crude oil throughput barrels for the period.
 
(b) During the second quarter of 2010, the Company wrote-off an amount associated with a capital project.
 
(c) Represents expense associated with a major scheduled turnaround at our refinery.
 
(d) 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.
 
(6) Direct operating expense is presented on a per barrel sold basis. Barrels sold are derived from the barrels produced and shipped from the refinery. We utilize 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, 2010 Compared to the Year Ended December 31, 2009 (Petroleum Business)
 
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 from the year ended December 31, 2010, as compared to the year ended December 31, 2009, was primarily the result of higher product prices and overall higher sales volumes. Overall sales 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     Volume
  Price
    Volume(1)   $ per barrel   Sales $(2)   Volume(1)   $ per barrel   Sales $(2)     Volume(1)   Sales $(2)     Variance   Variance
                                        (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  
 
 
(1) Barrels in millions
 
(2) Sales dollars in millions
 
Cost of Product Sold (Exclusive of Depreciation and Amortization).  Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $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 from the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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% for the year ended December 31, 2010 as compared to the year ended December 31, 2009. 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.


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Refining margin per barrel of crude 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 for the year ended December 31, 2010 over the year ended December 31, 2009 and a 27% decrease in our consumed crude oil discount to WTI as a result of our refinery processing a sweeter crude 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 $154.1 million for the year ended December 31, 2010, compared to direct operating expenses of $141.6 million for the year ended December 31, 2009. The increase of $12.5 million for the year ended December 31, 2010, compared to the year ended December 31, 2009, was the result of increases in expenses primarily associated with direct labor ($6.4 million), repairs and maintenance ($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), insurance ($1.2 million), other direct operating expenses ($0.6 million) and property taxes ($0.3 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 $3.72 per barrel, as compared to $3.58 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 for the year ended December 31, 2010 as compared to the year ended December 31, 2009 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).
 
Year Ended December 31, 2009 Compared to the Year Ended December 31, 2008 (Petroleum Business)
 
Net Sales.  Petroleum net sales were $2,934.9 million for the year ended December 31, 2009, compared to $4,774.3 million for the year ended December 31, 2008. The decrease of $1,839.4 million from the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily the result of significantly lower product prices, which was partially offset by slightly higher sales volumes. Overall sales volumes of refined fuels and propane for the year ended December 31, 2009 increased 0.9%, as compared to the year ended December 31, 2008. Our average sales price per gallon for the year ended December 31, 2009 for gasoline of $1.68 and distillate of $1.68 decreased by approximately 33% and 44%, respectively, as compared to the year


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ended December 31, 2008. The refinery operated at 94% of its capacity during 2009 despite a 14-day unplanned outage of its FCCU and a 26-day unplanned outage of its vacuum unit in the third quarter, which resulted in reduced crude oil runs.
 
                                                                                     
    Year Ended December 31, 2009   Year Ended December 31, 2008     Total Variance     Volume
  Price
    Volume(1)   $ per barrel   Sales $(2)   Volume(1)   $ per barrel   Sales $(2)     Volume(1)   Sales $(2)     Variance   Variance
                                        (in millions,)
Gasoline
    22.9     $ 70.40     $ 1,614.6       21.3     $ 104.92     $ 2,234.1         1.6     $ (619.5 )     $ 115.6     $ (753.1 )
                                                                                     
Distillate
    17.0     $ 70.74     $ 1,200.4       18.2     $ 126.04     $ 2,293.2         (1.2 )   $ (1,092.8 )     $ (86.7 )   $ (1,006.1 )
 
 
(1) Barrels in millions
 
(2) Sales dollars in millions
 
Cost of Product Sold (Exclusive of Depreciation and Amortization).  Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold (exclusive of depreciation and amortization) was $2,514.3 million for the year ended December 31, 2009, compared to $4,449.4 million for the year ended December 31, 2008. The decrease of $1,935.1 million from the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily the result of lower crude oil prices offset by the impact of FIFO accounting. Our average cost per barrel of crude oil consumed for the year ended December 31, 2009 was $57.46, compared to $98.52 for the comparable period of 2008, a decrease of approximately 42%. 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, 2009, we had a favorable FIFO impact of $67.9 million compared to an unfavorable FIFO impact of $102.5 million for the comparable period of 2008.
 
Refining margin per barrel of crude throughput increased from $8.39 for the year ended December 31, 2008 to $10.65 for the year ended December 31, 2009. Refining margin adjusted for FIFO impact was $8.93 per crude oil throughput barrel for the year ended December 31, 2009, as compared to $11.03 per crude oil throughput barrel for the year ended December 31, 2008. Gross profit per barrel increased to $5.42 for the year ended December 31, 2009 as compared to gross profit per barrel of $2.69 for the year ended December 31, 2008. The increase of our refining margin per barrel is due to a decrease in our cost of consumed crude oil, partially offset by a decrease in the average sales prices of our produced gasoline and distillates. Consumed crude oil costs declined due to a 38% decrease in WTI for the year ended December 31, 2009 over the comparable period of 2008 and a 119% improvement in our consumed crude oil discount to WTI as a result of the Contango in the U.S. crude oil market. Our average sales price of gasoline decreased approximately 33% and our average sales price for distillates decreased approximately 44% for the year ended December 31, 2009 over the year ended December 31, 2008.
 
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 $141.6 million for the year ended December 31, 2009, compared to direct operating expenses of $151.4 million for the year ended December 31, 2008. The decrease of $9.8 million for the year ended December 31, 2009, compared to the year ended December 31, 2008, was the result of net decreases in expenses associated with outside services and other direct operating expenses ($8.4 million), downtime repairs and maintenance ($6.5 million), production chemicals ($3.8 million) and energy and utilities ($3.8 million). The decrease of outside services and other direct operating expenses is the result of a decrease in the work performed by outside consultants, lower costs for environmental and waste water services and less desox consumption for the year ended December 31, 2009 compared to the year ended December 31, 2008. The decrease in repairs and maintenance expense was the result of fewer contract maintenance personnel and a decreased need for equipment repairs for the year ended December 31, 2009 compared to the year ended December 31, 2008. Additionally in 2008 the petroleum


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business experienced higher costs related to work related to the fluid catalytic cracking unit, hydrodesulfurization unit and the start of up the continuous catalyst regeneration (CCR) reformer that occurred in 2008 and not 2009. The decrease in production chemical costs was primarily due to reduced consumption of FCCU catalyst and additives and the decrease in energy and utility costs was the result of reduced natural gas prices, however was partially offset by increased natural gas consumption and increased electricity cost per kilowatt hour. The decreases are partially offset by increases in expenses associated with direct labor ($7.4 million), property taxes ($4.9 million) and insurance ($0.4 million). The increase in direct labor costs was the result of increased head count and share-based compensation expense. On a per barrel of crude oil throughput basis, direct operating expenses per barrel of crude oil throughput for the year ended December 31, 2009 decreased to $3.58 per barrel, as compared to $3.91 per barrel for the year ended December 31, 2008, principally due to a net dollar decrease in expenses from year to year as detailed above.
 
Net Costs Associated with Flood.  Petroleum net costs associated with the June/July 2007 flood for the year ended December 31, 2009 approximated $0.6 million, as compared to $6.4 million for the year ended December 31, 2008.
 
Goodwill Impairment.  In connection with our annual goodwill impairment testing, we determined our goodwill associated with our petroleum business was impaired in 2008. As a result, we wrote-off approximately $42.8 million in 2008. This amount represented the entire balance of goodwill of our petroleum business.
 
Operating Income.  Petroleum operating income was $170.2 million for the year ended December 31, 2009, as compared to operating income of $31.9 million for the year ended December 31, 2008. This increase of $138.3 million from the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily the result of an increase in the refining margin ($95.7 million), a reduction in direct operating expenses (exclusive of depreciation and amortization) ($9.8 million), a reduction in net costs associated with the flood ($5.8 million) and a non-cash charge related to the impairment of goodwill recorded in 2008 ($42.8 million). Partially offsetting these positive impacts was an increase in depreciation and amortization ($1.7 million) and an increase in selling, general and administrative expenses ($14.1 million) primarily attributable to an increase in share-based compensation expense.
 
Nitrogen Fertilizer Business Results of Operations
 
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
  2010   2009   2008
    (in millions)
 
Net sales
  $ 180.5     $ 208.4     $ 263.0  
Cost of product sold (exclusive of depreciation and amortization)
    34.3       42.2       32.6  
Direct operating expenses (exclusive of depreciation and amortization)
    86.7       84.5       86.1  
Net costs associated with flood
                 
Depreciation and amortization
    18.5       18.7       18.0  
Operating income
  $ 20.4     $ 48.9     $ 116.8  
Adjusted Nitrogen Fertilizer (EBITDA)(1)
  $ 52.8     $ 70.8     $ 129.9  
 


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    Year Ended December 31,  
Key Operating Statistics
  2010     2009     2008  
 
Production (thousand tons):
                       
Ammonia (gross produced)(2)
    392.7       435.2       359.1  
Ammonia (net available for sale)(2)
    155.6       156.6       112.5  
UAN
    578.3       677.7       599.2  
Pet coke consumed (thousand tons)
    436.3       483.5       451.9  
Pet coke (cost per ton)
  $ 17     $ 27     $ 31  
Sales (thousand tons)(3):
                       
Ammonia
    164.7       159.9       99.4  
UAN
    580.7       686.0       594.2  
                         
Total sales
    745.4       845.9       693.6  
Product pricing (plant gate) (dollars per ton)(3):
                       
Ammonia
  $ 361     $ 314     $ 557  
UAN
  $ 179     $ 198     $ 303  
On-stream factor(4):
                       
Gasification
    89.0 %     97.4 %     87.8 %
Ammonia
    87.7 %     96.5 %     86.2 %
UAN
    80.8 %     94.1 %     83.4 %
Reconciliation to net sales (dollars in millions):
                       
Freight in revenue
  $ 17.0     $ 21.3     $ 18.9  
Hydrogen revenue
    0.1       0.8       9.0  
Sales net plant gate
    163.4       186.3       235.1  
                         
Total net sales
  $ 180.5     $ 208.4     $ 263.0  
 
                         
    Year Ended December 31,  
Market Indicators
  2010     2009     2008  
 
Natural gas NYMEX (dollars per MMBtu)
  $ 4.38     $ 4.16     $ 8.91  
Ammonia — Southern Plains (dollars per ton)
  $ 437     $ 306     $ 707  
UAN — Mid Cornbelt (dollars per ton)
  $ 266     $ 218     $ 422  
 
 
(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 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

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income to adjusted EBITDA for the nitrogen fertilizer segment for the years ended December 31, 2010, 2009 and 2008:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (unaudited)  
 
Nitrogen Fertilizer:
                       
Nitrogen fertilizer operating income
  $ 20.4     $ 48.9     $ 116.8  
Share-based compensation
    9.0       3.2       (10.6 )
Loss on disposition of assets(a)
    1.4             2.3  
Major scheduled turnaround expenses(b)
    3.5             3.3  
Depreciation and amortization
    18.5       18.7       18.0  
Other income (expense)
                0.1  
                         
Adjusted Nitrogen Fertilizer EBITDA
  $ 52.8     $ 70.8     $ 129.9  
 
 
(a) During the fourth quarter of 2010 and 2008, the Company wrote-off approximately $1.4 million and $2.3 million, respectively, of assets in connection with the biennial major scheduled turnaround completed by the nitrogen fertilizer business.
 
(b) Represents expense associated with a major scheduled turnaround at our nitrogen fertilizer plant.
 
(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 2010 adjusted for these events would have been 97.6% for gasifier, 96.8% for ammonia and 96.1% for UAN, (ii) the on-stream factors in 2009 adjusted for the Linde air separation unit outage would have been 99.3% for gasifier, 98.4% for ammonia and 96.1% for UAN, and (iii) the on-stream factors in 2008 adjusted for major scheduled turnaround would have been 91.7% for gasifier, 90.2% for ammonia and 87.4% for UAN.
 
Year Ended December 31, 2010 compared to the Year Ended December 31, 2009 (Nitrogen Fertilizer Business)
 
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 our 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 from the year ended December 31, 2010 as compared to the year ended December 31, 2009 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


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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
  Price
    Volume(1)   $ per ton   Sales $(2)   Volume(1)   $ per ton   Sales $(2)     Volume(1)   Sales $(2)     Variance   Variance
                                        (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, our 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 our nitrogen fertilizer operations, primarily due to unscheduled downtime associated with the Linde air separation unit 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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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 UAN vessel rupture.
 
Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Direct operating expenses (exclusive of depreciation and amortization) for our 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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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


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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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, was the result of a decline in the nitrogen fertilizer margin ($20.0 million), increases in selling, general and administrative expenses ($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).
 
Year Ended December 31, 2009 compared to the Year Ended December 31, 2008 (Nitrogen Fertilizer Business)
 
Net Sales.  Nitrogen fertilizer net sales were $208.4 million for the year ended December 31, 2009, compared to $263.0 million for the year ended December 31, 2008. For the year ended December 31, 2009, ammonia, UAN and hydrogen made up $54.6 million, $153.0 million and $0.8 million of our net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $59.2 million, $194.8 million and $9.0 million for the year ended December 31, 2008, respectively. The decrease of $54.6 million from the year ended December 31, 2009, as compared to the year ended December 31, 2008, was the result of increases in overall sales volumes, offset by lower plant gate prices. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia and UAN for the year ended December 31, 2009 compared to the year ended December 31, 2008.
 
                                                                                     
    Year Ended December 31, 2009   Year Ended December 31, 2008     Total Variance     Volume
  Price
    Volume(1)   $ per ton   Sales $(2)   Volume(1)   $ per ton   Sales $(2)     Volume(1)   Sales $(2)     Variance   Variance
                                        (in millions)
Ammonia
    159,860     $ 342     $ 54.6       99,374     $ 596     $ 59.2         60,486     $ (4.6 )     $ 20.7     $ (25.3 )
UAN
    686,009     $ 223     $ 153.0       594,203     $ 328     $ 194.8         91,806     $ (41.7 )     $ 20.5     $ (62.2 )
 
 
(1) Sales volumes in tons
 
(2) Sales dollars in millions
 
In regard to product sales volumes for the year ended December 31, 2009, our nitrogen fertilizer operations experienced an increase of 61% in ammonia sales unit volumes and an increase of 15% in UAN sales unit volumes. The downtime associated with the biennial turnaround in 2008 led to reduced sales volumes during that year. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2009 compared to 2008 were higher for all units of our nitrogen fertilizer operations, primarily due to unscheduled downtime and the completion of the biennial scheduled turnaround for the nitrogen fertilizer plant completed in October 2008. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant, which results 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, 2009 for ammonia and UAN were less than plant gate prices for the comparable period of 2008 by 44% and 34%,


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respectively. We believe the dramatic decrease in nitrogen fertilizer prices was in part due to the decrease in natural gas prices and overall economic and market conditions.
 
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, 2009 was $42.2 million, compared to $32.6 million for the year ended December 31, 2008. The increase of $9.6 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily the result of increased sales volumes for both ammonia and UAN, which contributed $6.1 million of the increase. The increased sales volumes also resulted in additional freight expense of $2.6 million and hydrogen costs of $1.6 million. These increases were partially offset by a decrease in pet coke cost of $1.2 million over the comparable periods.
 
Direct Operating Expenses (Exclusive of Depreciation and Amortization).  Direct operating expenses (exclusive of depreciation and amortization) for our 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, 2009 were $84.5 million, as compared to $86.1 million for the year ended December 31, 2008. The decrease of $1.6 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was primarily the result of net decreases in expenses associated with downtime repairs and maintenance ($6.5 million), turnaround ($3.4 million), outside services and other direct operating expenses ($0.7 million), property taxes ($0.7 million), and insurance ($0.2 million). The decrease in expenses associated with downtime repairs and maintenance expense for the year ended December 31, 2009 was attributable to the fact that the biennial turnaround occurred in 2008 and not 2009. Due to the maintenance that occurred during the 2008 turnaround, repairs and maintenance to the operating units decreased in 2009. These decreases in direct operating expenses were partially offset by increases in expenses associated with utilities ($4.4 million), labor ($2.4 million), catalyst ($1.0 million) and combined with a decrease in the price we receive for sulfur produced as a by-product of our manufacturing process ($2.0 million). The increase in energy and utilities for the year ended December 31, 2009 was partially attributable to our increased on-stream times for our processing units that in turn resulted in higher electrical costs. Additionally, our electrical rates were higher for the year ended December 31, 2009 compared to the year ended December 31, 2008 as a result of the City of Coffeyville charging a higher rate for electricity, starting in August 2008, than what had been agreed to in our electricity contract. Our increased catalyst costs for the year ended December 31, 2009 were primarily attributable to our increased on-stream times on a year-over-year basis. Labor costs for the year ended December 31, 2009 were higher than the year ended December 31, 2008, primarily as a result of share-based compensation expense charged to direct operating expense.
 
Operating Income.  Nitrogen fertilizer operating income was $48.9 million for the year ended December 31, 2009, or 23% of net sales, as compared to $116.8 million for the year ended December 31, 2008, or 44% of net sales. This decrease of $67.9 million for the year ended December 31, 2009, as compared to the year ended December 31, 2008, was the result of a decline in the nitrogen fertilizer margin ($64.2 million), increases in selling, general and administrative expenses ($4.7 million), primarily attributable to an increase in share-based compensation expense, and depreciation and amortization ($0.7 million) partially offset by lower direct operating expenses ($1.6 million).
 
Liquidity and Capital Resources
 
Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash and cash equivalent balances, our working capital and our existing revolving credit facility. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined and nitrogen fertilizer products at margins sufficient to cover fixed and variable expenses.


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We believe that our cash flows from operations and existing cash and cash equivalents and improvements in our working capital, together with borrowings under our existing revolving credit facility as necessary, will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.
 
Cash Balance and Other Liquidity
 
As of December 31, 2010, we had cash and cash equivalents of $200.0 million. Since January 1, 2010, our cash position has increased approximately $163.1 million primarily as a result of favorable changes in our working capital position, the receipt of income tax refunds and related interest and lower capital expenditures. As of December 31, 2010, we had no amounts outstanding under our first priority revolving credit facility and aggregate availability of $79.6 million under our first priority revolving credit facility. As discussed below, the first priority credit facility was terminated on February 22, 2011 and was replaced with an ABL credit facility. Our availability under the ABL credit facility is reduced by outstanding letters of credit. As of March 2, 2011, we had $192.1 million available under the ABL credit facility and had cash and cash equivalents of approximately $103.6 million.
 
On February 22, 2011, CRLLC entered into a $250.0 million asset-backed revolving credit agreement (“ABL credit facility”) with a group of lenders including Deutsche Bank Trust Company Americas as collateral and administrative agent. The ABL credit facility is scheduled to mature in August 2014 and replaced the first priority credit facility which was terminated. The ABL credit facility will be 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 $500.0 million (in the aggregate), subject to additional lender commitments.
 
Senior Secured Notes
 
On April 6, 2010, CRLLC and its newly formed wholly-owned subsidiary, Coffeyville Finance Inc. (together the “Issuers”), completed the private offering of $275.0 million aggregate principal amount of 9.0% First Lien Senior Secured Notes due April 1, 2015 (the “First Lien Notes”) and $225.0 million aggregate principal amount of 10.875% Second Lien Senior Secured Notes due April 1, 2017 (the “Second Lien Notes” and together with the First Lien Notes, the “Notes”). The First Lien Notes were issued at 99.511% of their principal amount and the Second Lien Notes were issued at 98.811% of their principal amount. On December 30, 2010, we made a voluntary unscheduled principal payment of $27.5 million on our First Lien Notes. As 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. As of December 31, 2010, the Notes had an aggregate principal balance of $472.5 million and a net carrying value of $469.0 million.
 
CRLLC received total net proceeds from the offering of approximately $485.7 million, net of underwriter fees of $10.0 million and original issue discount of approximately $4.0 million, but before deducting other third party fees and expenses associated with the offering. CRLLC applied the net proceeds to prepay all of the outstanding balance of its tranche D term loan under its first priority credit facility in an amount equal to $453.3 million and to pay related fees and expenses. The balance of the net proceeds were used for general corporate purposes. In accordance with the terms of its first priority credit facility, CRLLC paid a 2.0% premium totaling approximately $9.1 million to the lenders of the term debt upon the prepayment of the outstanding balance. This amount was recorded as a loss on extinguishment of debt during the second quarter of 2010. This premium was in addition to the 2.0% premium totaling $0.5 million paid in first quarter of 2010 for voluntary unscheduled prepayments of $25.0 million on its tranche D term loan. This premium was


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recognized as a loss on extinguishment of debt in the first quarter of 2010. Additionally, due to the prepayment and termination of the term debt, a write-off of previously deferred financing costs of approximately $5.4 million was recorded during the second quarter of 2010. The discount and related debt issuance costs of the Notes are being amortized over the term of the applicable Notes.
 
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, beginning on October 1, 2010, to holders of record at the close of business on March 15 and September 15, as the case may be, immediately preceding each such interest payment date.
 
The Issuers have the right to redeem the First Lien Notes at the redemption prices set forth below:
 
  •  On or after April 1, 2012, some or all of the First Lien Notes may be redeemed at a redemption price of (i) 106.750% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2012; (ii) 104.500% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; and (iii) 100% of the principal amount, if redeemed on or after April 1, 2014, in each case, plus any accrued and unpaid interest;
 
  •  Prior to April 1, 2012, up to 35% of the First Lien Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 109.000% of the principal amount thereof, plus any accrued and unpaid interest;
 
  •  Prior to April 1, 2012, some or all of the First Lien Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest; and
 
  •  Prior to April 1, 2012, but not more than once in any twelve-month period, up to 10% of the First Lien Notes may be redeemed at a price equal to 103.000% of the principal amount thereof, plus accrued and unpaid interest to the date of redemption.
 
The Issuers have the right to redeem the Second Lien Notes at the redemption prices set forth below:
 
  •  On or after April 1, 2013, some or all of the Second Lien Notes may be redeemed at a redemption price of (i) 108.156% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2013; (ii) 105.438% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2014; (iii) 102.719% of the principal amount thereof, if redeemed during the twelve-month period beginning on April 1, 2015; and (iv) 100% of the principal amount if redeemed on or after April 1, 2016, in each case, plus any accrued and unpaid interest;
 
  •  Prior to April 1, 2013, up to 35% of the Second Lien Notes may be redeemed with the proceeds from certain equity offerings at a redemption price of 110.875% of the principal amount thereof, plus any accrued and unpaid interest; and
 
  •  Prior to April 1, 2013, some or all of the Second Lien Notes may be redeemed at a price equal to 100% of the principal amount thereof, plus a make-whole premium and any accrued and unpaid interest.
 
In the event of a “change of control” as defined in the Indentures, the Issuers are required to offer to buy back all of the Notes at 101% of their principal amount. A change of control is generally defined as (1) the


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direct or indirect sale or transfer (other than by a merger) of “all or substantially all of the assets of the Company” to any person other than permitted holders, which are generally GS, Kelso and certain members of management, (2) liquidation or dissolution of CRLLC, (3) any person, other than a permitted holder, directly or indirectly acquiring 50% of the voting stock of CRLLC or (4) the first day when a majority of the directors of CRLLC or CVR Energy are not Continuing Directors (as defined in the Indentures). Continuing Directors are generally our existing directors, directors approved by the then-Continuing Directors or directors nominated or elected by GS or Kelso.
 
The definition of “change of control” specifically excludes a transaction where CVR Energy becomes a subsidiary of another company, so long as (1) CVR Energy’s shareholders own a majority of the surviving parent or (2) no one person owns a majority of the common stock of the surviving parent following the merger.
 
The Indentures also allow the Company to sell, spin-off or complete an initial public offering of the Partnership, as long as the Company buys back a percentage of the Notes as described in the Indentures. In the event of a Fertilizer Business Event (as defined in the indentures governing the Notes), CRLLC is required to offer to purchase a portion of the Notes from holders at a purchase price equal to 103% of the principal amount thereof plus accrued and unpaid interest. In addition, the Notes provide that upon the occurrence of a Fertilizer Business Event, the guaranty of the Partnership and its subsidiary will be fully and unconditionally released, and the assets of the fertilizer business will no longer constitute collateral for the benefit of the Notes (but the common units which CRLLC owns in the Partnership will remain collateral for the benefit of the Notes).
 
The Indentures impose covenants that restrict the ability of the Credit Parties to (i) issue debt, (ii) incur or otherwise cause liens to exist on any of their property or assets, (iii) declare or pay dividends, repurchase equity, or make payments on subordinated or unsecured debt, (iv) make certain investments, (v) sell certain assets, (vi) merge, consolidate with or into another entity, or sell all or substantially all of their assets, and (vii) enter into certain transactions with affiliates. Most of the foregoing covenants would cease to apply at such time that the Notes are rated investment grade by both S&P and Moody’s. However, such covenants would be reinstituted if the Notes subsequently lost their investment grade rating. In addition, the Indentures contain customary events of default, the occurrence of which would result in, or permit the Trustee or holders of at least 25% of the First Lien Notes or Second Lien Notes to cause the acceleration of the applicable Notes, in addition to the pursuit of other available remedies. We were in compliance with the covenants as of December 31, 2010.
 
The obligations of the Credit Parties under the Notes and the guarantees are secured by liens on substantially all of the Credit Parties’ assets. The liens granted in connection with the First Lien Notes are first-priority liens and rank pari passu with the liens granted to the lenders under the first priority credit facility and certain hedge counterparties. The liens granted in connection with the Second Lien Notes are second-priority liens and rank junior to the aforementioned first-priority liens.
 
First Priority Credit Facility
 
As of December 31, 2010, the first priority credit facility consisted of a $150.0 million revolving credit facility. The revolving credit facility provided for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving credit facility were subject to a $100.0 million sub-limit. Outstanding letters of credit reduced the amount available under our revolving credit facility. As of December 31, 2010, we had $70.4 million of outstanding letters of credit consisting of: $0.2 million in letters of credit in support of certain environmental obligations, $30.6 million in letters of credit to secure transportation services for crude oil ($27.4 million of which relates to TransCanada Keystone Pipeline, LP petroleum transportation service agreements) and $39.6 million letters of credit issued in support of the purchase of feedstocks. On January 4, 2011, the stand-by letters of credit issued in support of the purchase of feedstocks were reduced to $15.4 million. The revolving loan commitment was scheduled to expire on December 28, 2012. As of December 31, 2010, we had available $79.6 million under the revolving credit


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facility. The first priority credit facility was terminated on February 22, 2011 and replaced by the ABL credit facility, as discussed in further detail below.
 
On March 12, 2010, CRLLC entered into a fourth amendment to its first priority credit facility. The amendment, among other things, provided CRLLC the opportunity to issue junior lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay the tranche D term loans. The amendment also provided CRLLC the ability to issue up to $350.0 million of first lien debt, subject to certain conditions, including, but not limited to, a requirement that 100% of the proceeds be used to prepay all of the remaining tranche D term loans.
 
The amendment also provided financial flexibility to CRLLC through modifications to its financial covenants through the quarter ended December 31, 2010 and as a result of the Notes issuance on April 6, 2010, the total leverage ratio became a first-lien only test and the interest coverage ratio was further modified. Additionally, the amendment permitted CRLLC to re-invest up to $15.0 million of asset sale proceeds each year, so long as such proceeds are re-invested within twelve months of receipt (eighteen months if a binding agreement is entered into within twelve months). CRLLC paid an upfront fee in an amount equal to 0.75% of the aggregate of the approving lenders’ loans and commitments outstanding as of March 11, 2010.
 
The first priority credit facility contained customary covenants, which, among other things, restricted, subject to certain exceptions, the ability of CRLLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The first priority credit facility provided that CRLLC could not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeded 75% of Actual Production (the estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from December 28, 2006. In addition, CRLLC was not to enter into material amendments related to any material rights under the Partnership’s partnership agreement without the prior written approval of the requisite lenders. These limitations were subject to critical exceptions and exclusions and were not designed to protect investors in our common stock. As of December 31, 2010, we were in compliance with our covenants under the first priority credit facility.
 
ABL Credit Facility
 
As documented above, CRLLC entered into a $250.0 million ABL credit facility on February 22, 2011, that provides for borrowings, letter of credit issuances and a feature that permits an increase of borrowings up to $500.0 million (in the aggregate) subject to additional lender commitments.
 
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 rank pari passu with liens granted in connection with the First Lien Notes and a second priority lien (subject to certain customary exceptions) and security interest in the Note Priority Collateral (as defined in the ABL Intercreditor Agreement).
 
The ABL credit facility also contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness, creation of liens on assets, the ability to dispose assets, make restricted payments, investments or acquisitions, enter into sales lease back transactions or enter into affiliate transactions. The facility also contains a fixed charge coverage ratio financial covenant


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that is triggered when borrowing base excess availability is less than certain thresholds, as defined under the facility.
 
Capital Spending
 
We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.
 
The following table summarizes our total actual capital expenditures for 2010 and budgeted capital expenditures for 2011 by operating segment and major category:
 
                 
    Year Ended December 31,  
    2010 Actual     2011 Budget  
    (in millions)  
 
Petroleum Business:
               
Maintenance
    18.2       50.8  
Growth
    1.6       32.2  
                 
Petroleum business total capital excluding turnaround expenditures
    19.8       83.0  
                 
Nitrogen Fertilizer Business:
               
Maintenance
    8.9       6.6  
Growth
    1.2       4.3  
                 
Nitrogen fertilizer business total capital excluding turnaround expenditures
    10.1       10.9  
                 
Corporate:
    2.5       1.9  
                 
Total capital spending
  $ 32.4     $ 95.8  
                 
 
During the fourth quarter of 2010, we completed our biennial turnaround of the nitrogen fertilizer plant. In connection with this turnaround, we incurred approximately $3.5 million of expense. In connection with the nitrogen fertilizer plant’s biennial turnaround, we also wrote off approximately $1.4 million of fixed assets. In addition, we incurred approximately $1.2 million of expenses in preparation for our 2011/2012 refinery turnaround. The refinery turnaround is expected to commence at the end of the fourth quarter of 2011 and be completed in the first quarter of 2012. We expect to incur total major scheduled turnaround expenses of approximately $65 million in connection with the refinery turnaround, of which $50.0 million of this expense is expected to be incurred in 2011.
 
Included in the above 2011 budgeted capital expenditures is $25.0 million associated with the construction of approximately an additional 1,000,000 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 $10.4 million in 2010.
 
Our estimated capital expenditures are subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our refinery or nitrogen fertilizer plant. Capital spending for the nitrogen fertilizer business has been and will be determined by the board of directors of the general partner of the Partnership.
 
The 2011 budgeted capital expenditures for the nitrogen fertilizer business do not include estimated capital spending associated with the proposed UAN expansion that would be accelerated upon the consummation of the proposed initial public offering of the Partnership. As disclosed in the registration statement filed


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by the Partnership, the Partnership intends to move forward with the UAN expansion, following the consummation of the initial public offering. We estimate that the additional capital spending that would be incurred in 2011 if the UAN expansion was accelerated would be approximately $38.0 million. We expect that the approximately $135 million UAN expansion, for which approximately $31 million had been spent as of December 31, 2010, will take eighteen to twenty-four months to complete and is anticipated to be funded by proceeds of the Partnership’s initial public offering and term loan borrowings made by the Partnership. There can be no assurance that the initial offering will be consummated by the Partnership under the terms described in the registration statement or at all.
 
Cash Flows
 
The following table sets forth our cash flows for the periods indicated below:
 
                         
    Year Ended December 31,  
    2010     2009     2008  
    (in millions)  
 
Net cash provided by (used in)
                       
Operating activities
  $ 225.4     $ 85.3     $ 83.2  
Investing activities
    (31.3 )     (48.3 )     (86.5 )
Financing activities
    (31.0 )     (9.0 )     (18.3 )
                         
Net increase (decrease) in cash and cash equivalents
  $ 163.1     $ 28.0     $ (21.6 )
                         
 
Cash Flows Provided by Operating Activities
 
For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.
 
Net cash flows 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 fertilizers 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


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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 flows from operating activities for the year ended December 31, 2008 were $83.2 million. The positive cash flow from operating activities generated over this period was primarily driven by $163.9 million of net income, favorable changes in trade working capital and other assets and liabilities partially offset by unfavorable changes in other working capital. 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. Therefore, net income for the year ended December 31, 2008 included both the realized losses and the unrealized gains on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2008 (approximately one year and six months) and the NYMEX crack spread that is the basis for the underlying swaps had decreased, the unrealized gains on the Cash Flow Swap significantly increased our net income over this period. The impact of these unrealized gains on the Cash Flow Swap is apparent in the $326.5 million decrease in the payable to swap counterparty. Other uses of cash from other working capital included $19.1 million from prepaid expenses and other current assets, $9.5 million from accrued income taxes and $7.4 million from deferred revenue and $5.3 million from other current liabilities, partially offset by a $74.2 million source of cash from insurance proceeds. Increasing our operating cash flow for the year ended December 31, 2008 was an $88.1 million source of cash related to changes in trade working capital. For the year ended December 31, 2008, accounts receivable decreased $49.5 million and inventory decreased by $98.0 million resulting in a net source of cash of $147.5 million. These sources of cash due to changes in trade working capital were partially offset by a decrease in accounts payable, or a use of cash, of $59.4 million. Other primary sources of cash during the period include a $55.9 million cash related to deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
 
Cash Flows Used In Investing Activities
 
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 for the year ended December 31, 2010, as compared to the year ended December 31, 2009, 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.


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Cash Flows Used In Financing Activities
 
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 $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 initial public offering of the Partnership, $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, 2010 relating to the Notes, operating leases, capital lease obligations, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following December 31, 2010 and thereafter. As of


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December 31, 2010, there were no amounts outstanding under the $150.0 million first priority revolving credit facility. The following table assumes no borrowings are made under the first priority revolving credit facility.
 
                                                         
    Payments Due by Period  
    Total     2011     2012     2013     2014     2015     Thereafter  
    (in millions)  
 
Contractual Obligations
                                                       
Long-term debt(1)
  $ 472.5     $     $     $     $     $ 247.5     $ 225.0  
Operating leases(2)
    24.3       6.8       6.8       5.0       2.8       1.6       1.3  
Capital lease obligations(3)
    5.1       4.9       0.1       0.1                    
Unconditional purchase obligations(4)(5)
    822.2       82.5       84.4       84.5       84.6       78.9       407.3  
Environmental liabilities(6)
    4.6       1.5       0.7       0.2       0.2       0.2       1.8  
Interest payments(7)
    254.4       41.2       46.7       46.7       46.7       35.9       37.2  
                                                         
Total
  $ 1,583.1     $ 136.9     $ 138.7     $ 136.5     $ 134.3     $ 364.1     $ 672.6  
Other Commercial Commitments
                                                       
Standby letters of credit(8)
  $ 70.4     $     $     $     $     $     $  
 
 
(1) As described above, the Company issued the Notes in an aggregate principal amount of $500.0 million on April 6, 2010. The First Lien Notes and Second Lien Notes bear an interest rate of 9.0% and 10.875% per year, respectively, payable semi-annually. The First Lien Notes mature on April 1, 2015, unless earlier redeemed or repurchased by the Issuers. The Second Lien Notes mature on April 1, 2017, unless earlier redeemed or repurchased by the Issuers. In December 2010, we made a voluntary unscheduled prepayment on our First Lien Notes of $27.5 million, reducing the aggregate principal balance of the Notes to $472.5 million.
 
(2) The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods.
 
(3) The amount includes commitments under capital lease arrangements for equipment as well as for real property used for corporate purposes.
 
(4) The amount includes (a) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation, (b) commitments under an electric supply agreement with the city of Coffeyville and (c) a product supply agreement with Linde.
 
(5) This amount includes approximately $552.8 million payable ratably over ten years pursuant to petroleum transportation service agreements between CRRM and TransCanada Keystone Pipeline, LP (“TransCanada”). Under the agreements, CRRM would receive transportation of at least 25,000 barrels per day of crude oil with a delivery point at Cushing, Oklahoma for a term of ten years on TransCanada’s Keystone pipeline system. We began receiving crude oil under the agreements in the first quarter of 2011. On September 15, 2009, the Company filed a Statement of Claim in the Court of the Queen’s Bench of Alberta, Judicial District of Calgary, to dispute the validity of the petroleum transportation service agreements. The Company and TransCanada are currently engaged in settlement discussions that would resolve the litigation and result in the Company receiving transportation of crude oil on substantially the same terms discussed above. The Company cannot provide any assurance that the litigation will be settled in a manner favorable to the Company.
 
(6) Environmental liabilities represents (a) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (b) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleaning and Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters.”


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(7) Interest payments are based on stated interest rates for the respective Notes. Interest is payable on the Notes semi-annually on April 1 and October 1 of each year. These interest payments commenced on October 1, 2010.
 
(8) Standby letters of credit include $0.2 million of letters of credit issued in connection with environmental liabilities, $30.6 million in letters of credit to secure transportation services for crude oil and a $39.6 million standby letter of credit issued in support of the purchase of feedstocks.
 
Our ability to make payments on and to refinance our indebtedness, to fund budgeted capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile. This, to a certain extent, is subject to refining spreads, fertilizer margins and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
 
Off-Balance Sheet Arrangements
 
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.
 
Recently Issued Accounting Standards
 
In July 2010, the FASB issued Accounting Standards Update (“ASU”) No. 2010-20, which amends ASC Topic 310, Receivables to provide greater transparency about an entity’s allowance for credit losses and the credit quality of its financing receivables. This ASU will require an entity to disclose (1) the inherent credit risk in its financing receivables, (2) how the credit risk is analyzed and assessed in calculating the allowance for credit losses and (3) the changes and reasons for those changes in the allowance for credit losses. The provisions of ASU No. 2010-20 are effective for interim and annual reporting periods ending on or after December 31, 2010. The adoption of this standard did not impact our financial position or results of operations.
 
In January 2010 the FASB issued ASU No. 2010-06, Improving Disclosures about Fair Value Measurements an amendment to ASC Topic 820, Fair Value Measurements and Disclosures. This amendment requires an entity to: (i) disclose separately the amounts of significant transfers in and out of Level 1 and Level 2 fair value measurements and describe the reasons for the transfers, (ii) present separate information for Level 3 activity pertaining to gross purchases, sales, issuances, and settlements and (iii) enhance disclosures of assets and liabilities subject to fair value measurements. The provisions of ASU No. 2010-06 are effective for us for interim and annual reporting beginning after December 15, 2009, with one new disclosure effective after December 15, 2010. We adopted this ASU as of January 1, 2010. The adoption of this standard did not impact our financial position or results of operations.
 
In June 2009, the FASB issued an amendment to a previously issued standard regarding consolidation of variable interest entities. This amendment was intended to improve financial reporting by enterprises involved with variable interest entities. Overall, the amendment revises the test for determining the primary beneficiary of a variable interest entity from a primarily quantitative analysis to a qualitative analysis. The provisions of the amendment are effective as of the beginning of the entity’s first annual reporting period that begins after November 15, 2009, for interim periods within that first annual reporting period, and for interim and annual reporting periods thereafter. We adopted this standard as of January 1, 2010. The adoption of this standard did not impact our financial position or results of operations; however, ongoing assessments of the Partnership will be performed which may impact our position as the primary beneficiary and related consolidation treatment of the Partnership.


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Critical Accounting Policies
 
We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited financial statements included elsewhere in this Report. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.
 
Goodwill
 
To comply with ASC Topic 350, Intangibles — Goodwill and Other (“ASC 350”), we perform a test for goodwill impairment annually or more frequently in the event we determine that a triggering event has occurred. Our annual testing is performed as of November 1.
 
In accordance with ASC 350, we identified our reporting units based upon our two key operating segments. These reporting units are our petroleum and nitrogen fertilizer segments. For 2010, the nitrogen fertilizer segment was the only reporting unit that had goodwill. The nitrogen fertilizer segment is a unique reporting unit that has discrete financial information available that management regularly reviews.
 
Goodwill and other intangible accounting standards provide that goodwill and other intangible assets with indefinite lives are not amortized but instead are tested for impairment on an annual basis. In accordance with these standards, we completed our annual test for impairment of goodwill as of November 1, 2010. For 2010, the annual test of impairment indicated that the remaining goodwill attributable to the nitrogen fertilizer segment was not impaired. The impairment test resulted in a calculated fair value substantially in excess of the carrying value.
 
The annual review of impairment was performed by comparing the carrying value of the applicable reporting unit to its estimated fair value. The valuation analysis used both income and market approaches as described below:
 
  •  Income Approach:  To determine fair value, we discounted the expected future cash flows for each reporting unit utilizing observable market data to the extent available. The discount rate used was 14.6% representing the estimated weighted-average costs of capital, which reflects the overall level of inherent risk involved in each reporting unit and the rate of return an outside investor would expect to earn.
 
  •  Market-Based Approach:  To determine the fair value of each reporting unit, we also utilized a market based approach. We used the guideline company method, which focuses on comparing our risk profile and growth prospects to select reasonably similar publicly traded companies.
 
We assigned an equal weighting of 50% to the result of both the income approach and market based approach based upon the reliability and relevance of the data used in each analysis. This weighting was deemed reasonable as the guideline public companies have a high-level of comparability with the respective reporting units and the projections used in the income approach were prepared using current estimates.
 
Long-Lived Assets
 
We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. The Company accounts for impairment of long-lived assets in accordance with ASC Topic 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets (“ASC 360”). In accordance with ASC 360, the Company reviews long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its


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estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
 
Derivative Instruments and Fair Value of Financial Instruments
 
We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long-term debt. Although management considers these derivatives economic hedges, our other derivative instruments do not qualify as hedges for hedge accounting purposes under ASC Topic 815, Derivatives and Hedging (“ASC 815”), and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The Company recorded net gains (losses) from derivative instruments of $(1.5) million, $(65.3) million and $125.3 million in gain (loss) on derivatives, net for the fiscal years ended December 31, 2010, 2009 and 2008, respectively.
 
Share-Based Compensation
 
For the years ended December 31, 2010, 2009 and 2008, we account for share-based compensation in accordance with ASC Topic 718, Compensation — Stock Compensation (“ASC 718”). ASC 718 requires that compensation costs relating to share-based payment transactions be recognized in a company’s financial statements. ASC 718 applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments.
 
The Company accounts for awards under its Phantom Unit Plans as liability based awards. In accordance with ASC 718, the expense associated with these awards for 2010 is based on the current fair value of the awards which was derived from a probability-weighted expected return method. The probability-weighted expected return method involves a forward-looking analysis of possible future outcomes, the estimation of ranges of future and present value under each outcome, and the application of a probability factor to each outcome in conjunction with the application of the current value of our common stock price with a Black-Scholes option pricing formula, as remeasured at each reporting date until the awards are settled.
 
Also, in conjunction with the initial public offering in October 2007, the override units of CALLC were modified and split evenly into override units of CALLC and CALLC II. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting standards issued by the FASB regarding the treatment of share-based compensation granted to employees of an equity method investee, as well as the accounting treatment for equity investments that are issued to individuals other than employees for acquiring or in conjunction with selling goods or services. In accordance with that accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived in 2010, 2009 and 2008 under the same methodology as the Phantom Unit Plan, 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 year ending December 31, 2010, 2009 and 2008, we increased (reversed) compensation expense by $34.8 million, $7.9 million and $(43.3) million, respectively, as a result of the phantom and override unit share-based compensation awards.
 
Through the Company’s Long-Term Incentive Plan, shares of non-vested common stock may be awarded to the Company’s subsidiaries’ employees, officers, consultants, advisors and directors. Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock and the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. For the years


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ended December 31, 2010, 2009 and 2008, we incurred compensation expense of $2.4 million, $0.8 million and $0.6 million, respectively, related to non-vested share-based compensation awards.
 
Assuming the fair value of our share-based awards changed by $1.00, our compensation expense would increase or decrease by approximately $2.6 million.
 
Income Taxes
 
We provide for income taxes in accordance with ASC Topic 740, Income Taxes (“ASC 740”), accounting for uncertainty in income taxes. We record deferred tax assets and liabilities to account for the expected future tax consequences of events that have been recognized in our financial statements and our tax returns. We routinely assess the realizability of our deferred tax assets and if we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized, the deferred tax asset would be reduced by a valuation allowance. We consider future taxable income in making such assessments which requires numerous judgments and assumptions. We record contingent income tax liabilities, interest and penalties, based on our estimate as to whether, and the extent