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

Form 10-K

 

 

Commission file number: 001-33492

 

CVR Energy, Inc.

(Exact name of registrant as specified in its charter)

 

Registrant’s telephone number, including area code:

(281) 207-3200

 

 

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

 

 

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):

 

(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.

 

 

Documents Incorporated By Reference

 

 

TABLE OF CONTENTS

 

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.

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.

 

 

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:

 

 

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

Coffeyville, Kansas and completed the purchase of these assets on March 3, 2004. Coffeyville Group Holdings, LLC operated our business from March 3, 2004 through June 24, 2005.

 

On June 24, 2005, Coffeyville Acquisition LLC (“CALLC”), which was formed by certain funds affiliated with Goldman, Sachs & Co. and Kelso & Company, L.P. (the “Goldman Sachs Funds” and the “Kelso Funds,” respectively), acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. CALLC operated our business from June 24, 2005 until CVR Energy’s initial public offering in October 2007. CVR Energy was formed in September 2006 as a subsidiary of CALLC in order to consummate an initial public offering of the businesses operated by CALLC. Immediately prior to CVR Energy’s initial public offering in October 2007:

 

 

CVR Energy consummated its initial public offering on October 26, 2007. 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.

Organizational Structure and Related Ownership as of March 1, 2011

 

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

 

 

 

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:

 

 

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,

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.

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

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

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:

 

 

 

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

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.

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

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.

The anticipated remediation costs through 2014 were estimated, as of December 31, 2010, to be as follows:

 

 

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,

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.

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.

 

 

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

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.

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.

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.

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.

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

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

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:

 

 

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

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.

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.

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:

 

 

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:

 

 

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

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.

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

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

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

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:

 

 

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

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:

 

 

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

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.

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:

 

 

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:

 

 

 

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.

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.

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

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.

 

 

None.

 

 

The following table contains certain information regarding our principal properties:

 

 

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.

 

 

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.

 

 

 

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:

 

 

 

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.

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

 

 

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.

 

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.

 

 

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.

 

 

 

 

 

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.

 

 

 

 

 

 

 

 

 

 

 

 

 

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:

 

 

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

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

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.

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.

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.

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.

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

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

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.

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

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:

 

 

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.

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.

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, 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

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,

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

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

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.

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: