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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Form 10-K
(Mark One)
| þ | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the fiscal period ended December 31, 2011 |
OR
| ¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| For the transition period from to . |
Commission file number: 001-35120
CVR Partners, LP
(Exact name of registrant as specified in its charter)
| Delaware | 56-2677689 | |
| (State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) | |
| 2277 Plaza Drive, Suite 500 | ||
| Sugar Land, Texas (Address of principal executive offices) |
77479 (Zip Code) | |
(281) 207-3200
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
| Title of Each Class |
Name of each exchange on which registered | |
| Common units representing limited partner interests |
New York Stock Exchange |
Securities registered pursuant to section 12(g) of the Act:
None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ¨ No þ
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 ¨ 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 ¨.
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 or Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No ¨.
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. þ
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer ¨ |
Accelerated filer ¨ | Non-accelerated filer þ | Smaller reporting company ¨ | |||
| (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 ¨ 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, 2011 (the last day of the registrant’s second fiscal quarter) was $487,485,878.
Indicate the number of units outstanding of each of the registrant’s classes of common units, as of the latest practicable date.
| Class |
Outstanding at February 20, 2012 | |
| Common unit representing limited partner interests | 73,030,936 units |
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GLOSSARY OF SELECTED TERMS
The following are definitions of certain terms used in this Form 10-K.
| 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. | |
| Blue Johnson | Blue, Johnson & Associates, Inc. | |
| 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. | |
| Coffeyville Resources or CRLLC | Coffeyville Resources, LLC, the subsidiary of CVR Energy which directly owns our general partner and 50,920,000 common units, or approximately 69.7% of our common units. | |
| common units | Common units representing limited partner interests of CVR Partners, LP. | |
| corn belt | The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. | |
| CVR Energy | CVR Energy, Inc., a publicly traded company listed on the New York Stock Exchange under the ticker symbol “CVI,” which indirectly owns our general partner and the common units owned by CRLLC. | |
| ethanol | A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate. | |
| farm belt | Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. | |
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| feedstocks | Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products, such as gasoline, diesel fuel and jet fuel, which are produced by a refinery. | |
| general partner | CVR GP, LLC, our general partner, which is a wholly-owned subsidiary of Coffeyville Resources. | |
| Initial Public Offering | Initial public offering (“IPO”) of CVR Partners, LP common units that closed on April 13, 2011. | |
| MMbtu | One million British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit. | |
| on-stream | Measurement of the reliability of the gasification, ammonia and UAN units, defined as the total number of hours operated by each unit divided by the total number of hours in the reporting period. | |
| pet coke | A coal-like substance that is produced during the refining process. | |
| plant gate price | The unit price of fertilizer, in dollars per ton, offered on a delivered basis, and excluding shipment costs. | |
| prepaid sales | Represents customer payments under contracts to guarantee a price and supply of fertilizer in quantities expected to be delivered in the next twelve months. Revenue is not recorded for such sales until the product is considered delivered. Prepaid sales are also referred to as deferred revenue. | |
| recordable incident | An injury, as defined by OSHA. All work-related deaths and illnesses, and those work-related injuries which result in loss of consciousness, restriction of work or motion, transfer to another job, or require medical treatment beyond first aid. | |
| slag | A glasslike substance removed from the gasifier containing the metal impurities originally present in pet coke. | |
| slurry | A byproduct of the fluid catalytic cracking process that is sold for further processing or blending with fuel oil. | |
| spot market | A market in which commodities are bought and sold for cash and delivered immediately. | |
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| syngas | A mixture of gases (largely carbon monoxide and hydrogen) that results from heating coal in the presence of steam. | |
| throughput | The volume processed through a unit. | |
| ton | One ton is equal to 2,000 pounds. | |
| turnaround | A periodically required standard procedure to refurbish and maintain a facility that involves the shutdown and inspection of major processing units. | |
| UAN | UAN is 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. | |
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PART I
Overview
CVR Partners, LP (“CVR Partners”, the “Company”, the “Partnership”, “we”, “us”, or “our”) is a Delaware limited partnership formed by CVR Energy, Inc. to own, operate and grow our nitrogen fertilizer business. Strategically located adjacent to CVR Energy’s refinery in Coffeyville, Kansas, our nitrogen fertilizer manufacturing facility is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer.
We produce and distribute nitrogen fertilizer products, which are used primarily by farmers to improve the yield and quality of their crops. Our principal products are ammonia and UAN. These products are manufactured at our facility in Coffeyville, Kansas. Our product sales are heavily weighted toward UAN and all of our products are sold on a wholesale basis.
Our facility includes a 1,225 ton-per-day ammonia unit, a 2,025 ton-per-day UAN unit and a gasifier complex with built-in redundancy having a capacity of 84 million standard cubic feet per day. We upgrade a majority of the ammonia we produce to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate which has historically commanded a premium price over ammonia. In 2011, we produced 411,189 tons of ammonia, of which approximately 72% was upgraded into 714,130 tons of UAN.
We are expanding our existing asset base and utilizing the experience of our and CVR Energy’s management teams to execute our growth strategy, which includes expanding production of UAN and acquiring and building additional infrastructure and production assets. A significant two-year plant expansion designed to increase our UAN production capacity by 400,000 tons, or approximately 50%, per year, is underway. CVR Energy, a New York Stock Exchange listed company, which indirectly owns our general partner and approximately 70.0% of our outstanding common units, currently operates a 115,000 bpd oil refinery in Coffeyville, Kansas, a 70,000 bpd oil refinery in Wynnewood, Oklahoma, and ancillary businesses. On February 13, 2012, CVR Energy announced its intention to sell a portion of its common unit holdings in CVR Partners. There can be no assurance as to the terms, conditions, amount or timing of such offering, or whether such offering will take place at all. This announcement does not constitute an offer of any securities for sale and is being made pursuant to and in accordance with Rule 135 under the Securities Act.
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 our nitrogen fertilizer competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. We believe our nitrogen fertilizer business has historically been a lower cost producer and marketer of ammonia and UAN fertilizers in North America. During the past five years, over 70% of the pet coke consumed by our plant was produced and supplied by CVR Energy’s crude oil refinery pursuant to a renewable long-term agreement.
We generated net sales of $302.9 million, $180.5 million and $208.4 million, net income of $132.4 million, $33.3 million and $57.9 million for the years ended December 31, 2011, 2010 and 2009, respectively.
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Organizational Structure and Related Ownership as of December 31, 2011
The following chart illustrates our organizational structure.
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Raw Material Supply
The nitrogen fertilizer facility’s primary input is pet coke. Pet coke is produced as a byproduct of a refinery’s coker unit process. In order to refine heavy or sour crude oil, which are lower in cost and more prevalent than higher quality crude oil, refiners use coker units, which enables refiners to further upgrade heavy crude oil. Our fertilizer 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 Texas Gulf Coast pet coke market, where daily production exceeds 40,000 tons per day. Our average daily pet coke demand from 2009-2011 was less than 1,400 tons per day. Given the fact that the majority of our third-party pet coke suppliers are located in the Midwest, our geographic location gives us (and our similarly located competitors) a transportation cost advantage over our U.S. Gulf Coast market competitors.
During the past five years, over 70% of our pet coke requirements on average were supplied by CVR Energy’s adjacent crude oil refinery, pursuant to a renewable long-term agreement. Historically we have obtained the remainder of our 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 our nitrogen fertilizer plant.
Linde LLC (“Linde”) owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to our gasifiers for a monthly fee. We provide and pay for all utilities required for operation of the air separation plant. The air separation plant has not experienced any long-term operating problems; however, CVR Energy maintains, for our benefit, contingent business interruption insurance with a $50 million limit for any interruption that results in a loss of production from an insured peril. The agreement with Linde provides that if our requirements for liquid or gaseous oxygen, liquid or gaseous nitrogen or clean dry air exceed specified instantaneous flow rates by at least 10%, we can solicit bids from Linde and third parties to supply our incremental product needs. We are required to provide notice to Linde of the approximate quantity of excess product that we will need and the approximate date by which we will need it; we and Linde will then jointly develop a request for proposal for soliciting bids from third parties and Linde. The bidding procedures may be limited under specified circumstances. The agreement with Linde expires in 2020.
We import start-up steam for the nitrogen fertilizer plant from CVR Energy’s adjacent crude oil refinery, and then export steam back to the crude oil refinery once all of our units are in service. We have entered into a feedstock and shared services agreement with CVR Energy, which regulates, among other things, the import and export of start-up steam between the adjacent refinery and the nitrogen fertilizer plant. Monthly charges and credits are recorded with the steam valued at the natural gas price for the month.
Production Process
Our nitrogen fertilizer plant was built in 2000 with two separate gasifiers to provide redundancy and reliability. It uses a gasification process licensed from an affiliate of the General Electric Company (“General Electric”), to convert pet coke to high purity hydrogen for a subsequent conversion to ammonia. The nitrogen fertilizer plant is capable of processing approximately 1,400 tons per day of pet coke from CVR Energy’s crude oil refinery and third-party sources and converting it into approximately 1,200 tons per day of ammonia. A majority of the ammonia is converted to approximately 2,000 tons per day of UAN. Typically 0.41 tons of ammonia are required to produce one ton of UAN.
Pet coke is first ground and blended with water and a fluxant (a mixture of fly ash and sand) to form a slurry that is then pumped into the partial oxidation gasifier. The slurry is then contacted with oxygen from an air separation unit. Partial oxidation reactions take place and the synthesis gas, or syngas, consisting predominantly of hydrogen and carbon monoxide, is formed. The mineral residue from the slurry is a molten slag (a glasslike substance containing the metal impurities originally present in pet coke) and flows along with the syngas into a quench chamber. The syngas and slag are rapidly cooled and the syngas is separated from the slag.
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Slag becomes a byproduct of the process. The syngas is scrubbed and saturated with moisture. The syngas next flows through a shift unit where the carbon monoxide in the syngas is reacted with the moisture to form hydrogen and CO2. The heat from this reaction generates saturated steam. This steam is combined with steam produced in the ammonia unit and the excess steam not consumed by the process is sent to the adjacent crude oil refinery.
After additional heat recovery, the high-pressure syngas is cooled and processed in the acid gas removal unit. The syngas is then fed to a pressure swing absorption, or PSA, unit, where the remaining impurities are extracted. The PSA unit reduces residual carbon monoxide and CO2 levels to trace levels, and the moisture-free, high-purity hydrogen is sent directly to the ammonia synthesis loop.
The hydrogen is reacted with nitrogen from the air separation unit in the ammonia unit to form the ammonia product. A large portion of the ammonia is converted to UAN. In 2011, we produced 411,189 tons of ammonia, of which approximately 72% was upgraded into 714,130 tons of UAN.
We schedule and provide routine maintenance to our critical equipment using our own maintenance technicians. Pursuant to a technical services agreement with General Electric, which licenses the gasification technology to us, General Electric provides 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 perpetual license agreement that is fully paid. The license grants us perpetual rights to use the pet coke gasification process on specified terms and conditions.
Distribution, Sales and Marketing
The primary geographic markets for our fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas. We market 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 season, from March through May. The second-highest period of demand occurs during fall pre-plant in late October and November. The summer wheat pre-plant occurs in August and September. In addition, smaller quantities of ammonia are sold in the off-season to fill available storage at the dealer level.
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. We lease a fleet of railcars for use in product delivery, and also negotiate with distributors that have their own leased railcars to utilize these assets to deliver products. We operate two truck loading and four rail loading racks for each of ammonia and UAN, with an additional four rail loading racks for UAN. We own all of the truck and rail loading equipment at our nitrogen fertilizer facility.
We market agricultural products to destinations that produce strong margins. The UAN market is primarily located near the Union Pacific Railroad lines or destinations that can be supplied by truck. The ammonia market is primarily located near the Burlington Northern Santa Fe or Kansas City Southern Railroad lines or destinations that can be supplied by truck. By securing this business directly, we reduce our dependence on distributors serving the same customer base, which enables us to capture a larger margin and allows us to better control our product distribution. Most of the agricultural sales are made on a competitive spot basis. We also offer 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 corn belt is the primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. 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 multiyear contracts.
We use forward sales of our fertilizer products to optimize our asset utilization, planning process and production scheduling. These sales are made by offering customers the opportunity to purchase product on a
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forward basis at prices and delivery dates that we propose. We use this program to varying degrees during the year and between years depending on market conditions. We have the flexibility to decrease or increase forward sales depending on our view as to whether price environments will be increasing or decreasing. Fixing the selling prices of our products months in advance of their ultimate delivery to customers typically causes our reported selling prices and margins to differ from spot market prices and margins available at the time of shipment. As of December 31, 2011, we have sold forward 22,813 tons of ammonia at an average netback of $655 and 77,895 tons of UAN at an average netback of $372 for shipment over the next six months. As of December 31, 2011, $9.0 million of our forward sales are prepaid sales, which means we received payment for such product in advance of delivery. Cash received as a result of prepayments is recognized as deferred revenue on our balance sheet upon receipt; revenue and resultant net income and EBITDA are recorded as the product is actually delivered.
Customers
We sell ammonia to agricultural and industrial customers. Based upon a three-year average, we have sold approximately 87% of the ammonia we produce to agricultural customers primarily located in the mid-continent area between North Texas and Canada, and approximately 13% to industrial customers. Agricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., Gavilon Fertilizer, LLC, Transammonia, Inc., Agri Services of Brunswick, LLC, Interchem, and CHS Inc. Industrial customers include Tessenderlo Kerley, Inc., National Cooperative Refinery Association, and Dyno Nobel, Inc. We sell UAN products to retailers and distributors. 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.
For the year ended December 31, 2011, the top five ammonia customers in the aggregate represented 61.0% of our ammonia sales, and the top five UAN customers in the aggregate represented 49.0% of our UAN sales, of which Gavilon Fertilizer, LLC and United Suppliers, Inc. accounted for approximately 17.0% and 12.0 %, respectively.
Competition
We have experienced and expect to continue to meet significant levels of competition from current and potential competitors, many of whom have significantly greater financial and other resources. See “Risk Factors — Risks Related to Our Business — Nitrogen fertilizer products are global commodities, and we face intense competition from other nitrogen fertilizer producers.”
Competition in our 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. We maintain a large fleet of leased rail cars and seasonally adjust inventory to enhance our manufacturing and distribution operations.
Our major competitors include Agrium, Koch Nitrogen, Potash Corporation and CF Industries. Domestic competition 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.
Based on Blue Johnson data regarding total U.S. use of UAN and ammonia, we estimate that our UAN production in 2011 represented approximately 6% of the total U.S. UAN use and that the net ammonia produced and marketed at our facility represented approximately 1% of the total U.S. ammonia use.
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Seasonality
Because we primarily sell agricultural commodity products, our business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, we typically generate greater net sales in the first half of the 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
Our business is subject to extensive and frequently changing federal, state and local, environmental, health and safety laws and regulations governing the emission and release of hazardous substances into the environment, the treatment and discharge of waste water and the storage, handling, use and transportation of our nitrogen fertilizer products. These laws and regulations, their underlying regulatory requirements and the enforcement thereof impact us by imposing:
| • | restrictions on operations or the need to install enhanced or additional controls; |
| • | the need to obtain and comply with permits and authorizations; |
| • | liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities (if any) and off-site waste disposal locations; and |
| • | specifications for the products we market, primarily UAN and ammonia. |
Our operations require numerous permits and authorizations. Failure to comply with these permits or environmental laws and regulations 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 and state agencies. The ultimate impact on our business of complying with existing 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 or result in delays or limits to our operations or growth while attempting to obtain required permits.
The principal environmental risks associated with our business 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 us through the federal Clean Air Act’s permitting requirements and 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 substances. 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 nitrogen fertilizer facility in order to comply. If new controls or changes to operations are needed, the costs could be significant. In addition, failure to comply with the requirements of the federal Clean Air Act and its implementing regulations could result in fines, penalties or other sanctions.
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
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our operations. 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. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations that have been promulgated or may be promulgated or revised in the future. The EPA recently proposed revisions to the New Source Performance Standards for nitric acid plants. We do not expect to incur capital expenditures or any significant additional operational expenses associated with the revised standards, as proposed.
Release Reporting
The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting requirements under federal and state environmental laws. We periodically experience releases of hazardous or extremely hazardous substances from our equipment. We experienced more significant releases in August 2007 due to the failure of a high pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. Such releases are reported to the EPA and relevant state and local agencies. From time to time, the EPA has conducted inspections and issued information requests to us with respect to our compliance with risk reporting requirements under the Comprehensive Environmental Response, Compensation and Liability Act and the Emergency Planning and Community Right-to-Know Act and the risk management program under the federal Clean Air Act. If we fail to properly report a release, or if the release violates the law or our permits, it could cause us to become the subject of a governmental enforcement action or third-party claims. Government enforcement or third-party claims relating to releases of hazardous or extremely hazardous substances could result in significant expenditures and liability.
Greenhouse Gas Emissions
Various regulatory and legislative measures to address greenhouse gas emissions (including carbon dioxide, or CO2, methane and nitrous oxides) are in different phases of implementation or discussion. In the aftermath of its 2009 “endangerment finding” that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the authority granted to it under the federal Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and report their greenhouse gas emissions to the EPA. In accordance with the rule, we have begun monitoring and reporting greenhouse gas emissions from our nitrogen fertilizer plant. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which establishes new greenhouse gas emissions thresholds that determine when stationary sources, such as our nitrogen fertilizer plant, must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the federal Clean Air Act. In cases where a new source is constructed or an existing source undergoes a major modification, the facility would need to evaluate and install best available control technology, or BACT, for its greenhouse gas emissions. Phase-in permit requirements began for the largest stationary sources in 2011. A major modification at our nitrogen fertilizer plant, subject to the PSD or Title V permitting process after July 2011, which results in a significant expansion of production at our nitrogen fertilizer plant and a significant increase in greenhouse gas emissions, may require us to install BACT for our greenhouse gas emissions as part of the permitting process. We do not currently believe that any currently anticipated projects at our nitrogen fertilizer plant will result in a significant increase in greenhouse gas emissions triggering the need to install BACT controls. At the federal legislative level, Congressional passage of legislation adopting some form of federal mandatory greenhouse gas emission reduction, such as a nationwide cap-and-trade program, does not appear likely at this time, although it could be adopted at a future date. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.
In addition to potential federal legislation, a number of states have adopted regional greenhouse gas initiatives to reduce CO2 and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas (where our nitrogen fertilizer facility is 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
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the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is unclear whether Kansas still intend to do so.
The implementation of EPA regulations and/or the passage of federal or state climate change legislation will likely 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 ability to make cash distributions.
In addition, climate change legislation and regulations may result in increased costs not only for our business but also for agricultural producers that utilize our fertilizer products, thereby potentially decreasing demand for our fertilizer products. Decreased demand for our fertilizer products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Environmental Remediation
Under the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Resource Conservation and Recovery Act (“RCRA”), and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons can include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, and, under certain circumstances, joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters, including soil and water contamination, personal injury or property damage allegedly caused by 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 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.
Environmental Insurance
We are covered by CVR Energy’s premises pollution liability insurance policies with an aggregate limit of $50.0 million per pollution condition, subject to a self-insured retention of $5.0 million. The policies include business interruption coverage, subject to a 10-day waiting period deductible. This insurance expires on July 1, 2012. The policies insure specific covered locations, including our nitrogen fertilizer facility. The policies insure (i) claims, remediation costs, and associated legal defense expenses for pollution conditions at, or migrating from, a covered location, and (ii) the transportation risks associated with moving waste from a covered location to any location for unloading or depositing waste. The policies cover any claim made during the policy period as long as the pollution conditions giving rise to the claim commenced on or after March 3, 2004. The premises pollution liability policies contain exclusions, conditions, and limitations that could apply to a particular pollution condition claim, and there can be no assurance such claim will be adequately insured for all potential damages.
In addition to the premises pollution liability insurance policies, we benefit from casualty insurance policies maintained by CVR Energy having an aggregate and occurrence limit of $150.0 million, subject to a self-insured retention of $2.0 million. This insurance provides coverage for claims involving pollutants where the discharge is sudden and accidental and first commenced at a specific day and time during the policy period. Coverage under the casualty insurance policies for pollution does not apply to damages at or within our insured premises. The pollution coverage provided in the casualty insurance policies contains exclusions, definitions, conditions and limitations that could apply to a particular pollution claim, and there can be no assurance such claim will be adequately insured for all potential damages.
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Safety, Health and Security Matters
We are subject to a number of federal and state laws and regulations related to safety, including the federal Occupational Safety and Health Act, or “OSHA,” and comparable state statutes, the purpose of which are to protect the health and safety of workers. We also are subject to OSHA Process Safety Management regulations, which are designed to prevent or minimize the consequences of catastrophic releases of toxic, reactive, flammable or explosive chemicals.
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, or PSM, program. This program is designed to address all aspects of OSHA guidelines for developing and maintaining a comprehensive process safety management program. We will continue to audit our programs and consider improvements in our management systems and equipment.
Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in our facility. This plan is communicated to local regulatory and community groups. We have on-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.
Employees
As of December 31, 2011, we had 124 direct employees. These employees operate our facilities at the nitrogen fertilizer plant level and are directly employed and compensated by us. These employees are covered by health insurance, disability and retirement plans established by CVR Energy. None of our employees are unionized, and we believe that our relationship with our employees is good.
We also rely on the services of employees of CVR Energy in the operation of our business pursuant to a services agreement among us, CVR Energy and our general partner. CVR Energy provides us with the following services under the agreement, among others:
| • | services from CVR Energy’s employees in capacities equivalent to the capacities of corporate executive officers, including chief operating officer, chief financial officer, general counsel, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve us on a shared, part-time basis only, unless we and CVR Energy agree otherwise; |
| • | administrative and professional services, including legal, accounting, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
| • | management of our property and the property of our operating subsidiary in the ordinary course of business; |
| • | recommendations on capital raising activities, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions; |
| • | managing or overseeing litigation and administrative or regulatory proceedings, establishing appropriate insurance policies, and providing safety and environmental advice; |
| • | recommending the payment of distributions; and |
| • | managing or providing advice for other projects as may be agreed by CVR Energy and our general partner from time to time. |
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For more information on this services agreement, see “Certain Relationships and Related Transactions, and Director Independence – Agreements with CVR Energy – Services Agreement.”
Available Information
Our website address is www.cvrpartners.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 the Charter of the Audit Committee of the Board of Directors of our general partner are available on our website. These guidelines and policies and the charter are available in print without charge to any unitholder requesting them.
Trademarks, Trade Names and Service Marks
This Annual Report on Form 10-K for the year ended December 31, 2011 (the “Report”) may include our and our affiliates’ trademarks, including CVR Energy, Coffeyville Resources, CVR Partners, LP and the CVR Partners, LP logo, each of which is registered with the United States Patent and Trademark Office. This Report may also contain trademarks, service marks, copyrights and trade names of other companies.
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 an actual event, our business, financial condition, cash flows or results of operations could be materially adversely affected. In that case, we might not be able to pay distributions on our common units, the trading price of our common units could decline, and you could lose all or part of your investment. Although many of our business risks are comparable to those faced by a corporation engaged in a similar business, limited partner interests are inherently different from the capital stock of a corporation and involve additional risks described below.
Risks Related to Our Business
We may not have sufficient available cash to pay any quarterly distribution on our common units. Furthermore, we are not required to make distributions to holders of our common units on a quarterly basis or otherwise, and may elect to distribute less than all of our available cash.
We may not have sufficient available cash each quarter to enable us to pay any distributions to our common unitholders. Furthermore, our partnership agreement does not require us to pay distributions on a quarterly basis or otherwise. Although our general partner’s current policy is to distribute all of our available cash on a quarterly basis, the board of directors of our general partner may at any time, for any reason, change this policy or decide not to pay cash distributions on a quarterly basis or other basis. The amount of cash we will be able to distribute on our common units principally depends on the amount of cash we generate from our operations, which is directly dependent upon the operating margins we generate, which have been volatile historically. Our operating margins are significantly affected by the market-driven UAN and ammonia prices we are able to charge our customers and our pet coke-based gasification production costs, as well as seasonality, weather conditions, governmental regulation, unscheduled maintenance or downtime at our facilities and global and domestic demand for nitrogen fertilizer products, among other factors. In addition:
| • | The amount of distributions we pay, if any, and the decision to make any distribution at all will be determined by the board of directors of our general partner, whose interests may differ from those of our common unitholders. Our general partner has limited fiduciary and contractual duties, which may permit it to favor its own interests or the interests of CVR Energy to the detriment of our common unitholders. |
| • | Our credit facility, and any credit facility or other debt instruments we enter into in the future, may limit the distributions that we can make. Our credit facility provides that we can make distributions to holders |
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| of our common units, but only if we are in compliance with our leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution, and there is no default or event of default under the facility. In addition, any future credit facility may contain other financial tests and covenants that we must satisfy. Any failure to comply with these tests and covenants could result in the lenders prohibiting distributions by us. |
| • | The amount of available cash for distribution to our unitholders depends primarily on our cash flow, and not solely on our profitability, which is affected by non-cash items. As a result, we may make distributions during periods when we record losses and may not make distributions during periods when we record net income. |
| • | The actual amount of available cash depends on numerous factors, some of which are beyond our control, including UAN and ammonia prices, our operating costs, global and domestic demand for nitrogen fertilizer products, fluctuations in our working capital needs, and the amount of fees and expenses incurred by us. |
The amount of our quarterly cash distributions, if any, will vary significantly both quarterly and annually and will be directly dependent on the performance of our business. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time.
We expect our business performance will be more seasonal and volatile, and our cash flows will be less stable, than the business performance and cash flows of most publicly traded partnerships. As a result, our quarterly cash distributions will be volatile and are expected to vary quarterly and annually. Unlike most publicly traded partnerships, we do not have a minimum quarterly distribution or employ structures intended to consistently maintain or increase distributions over time. The amount of our quarterly cash distributions will be directly dependent on the performance of our business, which has been volatile historically as a result of volatile nitrogen fertilizer and natural gas prices, and seasonal and global fluctuations in demand for nitrogen fertilizer products. Because our quarterly distributions will be subject to significant fluctuations directly related to the cash we generate after payment of our fixed and variable expenses, future quarterly distributions paid to our unitholders will vary significantly from quarter to quarter and may be zero. Given the seasonal nature of our business, we expect that our unitholders will have direct exposure to fluctuations in the price of nitrogen fertilizers. In addition, from time to time we make prepaid sales, whereby we receive cash in respect of product to be delivered in a future quarter but do not record revenue in respect of such sales until product is delivered. The cash from prepaid sales increases our operating cash flow in the quarter when the cash is received; however, we do not generate net income or EBITDA in respect of prepaid sales until product is actually delivered.
The board of directors of our general partner may modify or revoke our cash distribution policy at any time at its discretion. Our partnership agreement does not require us to make any distributions at all.
Our general partner’s current policy is to distribute all of the available cash we generate each quarter to unitholders of record on a pro rata basis. However, the board may change such policy at any time at its discretion and could elect not to make distributions for one or more quarters. Our partnership agreement does not require us to make any distributions at all. Any modification or revocation of our cash distribution policy could substantially reduce or eliminate the amounts of distributions to our unitholders.
The nitrogen fertilizer business is, and nitrogen fertilizer prices are, cyclical and highly volatile and have experienced substantial downturns in the past. Cycles in demand and pricing could potentially expose us to significant fluctuations in our operating and financial results, and expose you to substantial volatility in our quarterly cash distributions and material reductions in the trading price of our common units.
We are 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
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products and, in turn, our financial condition, cash flows and results of operations, which could result in significant volatility or material reductions in the price of our common units or an inability to make quarterly cash distributions on our common units.
Nitrogen fertilizer products are commodities, the price of which can be highly volatile. The price of nitrogen fertilizer products depend on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. If seasonal demand exceeds the projections on which we base production, our customers may acquire nitrogen fertilizer products from our competitors, and our profitability will be negatively impacted. If seasonal demand is less than we expect, we 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 business, cash flow and ability to make distributions.
Our internally generated cash flows and other sources of liquidity may not be adequate for our capital needs. As a result, we may not be able to pay any cash distributions to our unitholders and the trading price of our common units may be adversely impacted.
If we cannot generate adequate cash flow or otherwise secure sufficient liquidity to meet our working capital needs or support our short-term and long-term capital requirements, we may be unable to meet our debt obligations, pursue our business strategies or comply with certain environmental standards, which would have a material adverse effect on our business and results of operations. As of December 31, 2011, we had cash and cash equivalents of $237.0 million and $25.0 million available under our credit facility.
The costs associated with operating our nitrogen fertilizer plant are largely fixed. If nitrogen fertilizer prices fall below a certain level, we may not generate sufficient revenue to operate profitably or cover our costs and our ability to make distributions will be adversely impacted.
Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose costs are therefore largely variable, we have largely fixed costs that are not dependent on the price of natural gas because we use pet coke as the primary feedstock in our nitrogen fertilizer plant. As a result of the fixed cost nature of our operations, downtime, interruptions or low productivity due to reduced demand, adverse weather conditions, equipment failure, a decrease in nitrogen fertilizer prices or other causes can result in significant operating losses, which would have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
A decline in natural gas prices could impact our 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 has not been the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to historically low stocks of global grains and a surge in the prices of corn and wheat, the primary crops in our 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 our competitors and could disproportionately impact our operations by making us less competitive with natural gas-based nitrogen fertilizer manufacturers. A decline in natural gas prices could impair our ability to compete with other nitrogen fertilizer producers who utilize natural gas as their primary feedstock, and therefore
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have a material adverse impact on the trading price of our common units. 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, cash flows, and ability to make cash distributions.
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 sales of nitrogen fertilizer, and on our results of operations, financial condition and ability to make cash distributions.
Conditions in the U.S. agricultural industry significantly impact our operating results. 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 our 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 ability to make cash distributions.
A major factor underlying the current high level of demand for our nitrogen-based fertilizer products is the expanding production of ethanol in the United States and the expanded use of corn in ethanol production. Ethanol production in the United States is highly dependent upon a myriad of federal and state legislation and regulations, and is made significantly more competitive by various federal and state incentives, mandated production of ethanol pursuant to federal renewable fuel standards, and permitted increases in ethanol percentages in gasoline blends, such as E15, a gasoline blend with 15% ethanol. However, a number of factors, including a continuing “food versus fuel” debate and studies showing that expanded ethanol production may increase the level of greenhouse gases in the environment, have resulted in calls to reduce subsidies for ethanol, allow increased ethanol imports and adopt temporary waivers of the current renewable fuel standard levels, any of which could have an adverse effect on corn-based ethanol production, planted corn acreage and fertilizer demand. Therefore, ethanol incentive programs may not be renewed, or if renewed, they may be renewed on terms significantly less favorable to ethanol producers than current incentive programs. For example, Congress allowed both the 45 cents per gallon ethanol tax credit and the 54 cents per gallon ethanol import tariff to expire on December 31, 2011. Similarly, the EPA’s waivers partially approving the use of E15 could be revised, rescinded or delayed. These actions could have a material adverse effect on ethanol production in the United States, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Further, most ethanol is currently produced from corn and other raw grains, such as milo or sorghum — especially in the Midwest. The current trend in ethanol production research is to develop an efficient method of producing ethanol from cellulose-based biomass, such as agricultural waste, forest residue, municipal solid waste and energy crops (plants grown for use to make biofuels or directly exploited for their energy content). If an efficient method of producing ethanol from cellulose-based biomass is developed, the demand for corn may decrease significantly, which could reduce demand for our nitrogen fertilizer products and have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
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Nitrogen fertilizer products are global commodities, and we face intense competition from other nitrogen fertilizer producers.
Our 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. We compete 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. Competitors utilizing different corporate structures may be better able to withstand lower cash flows than we can as a limited partnership. Our competitive position could suffer to the extent we are not able to expand our own 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 our sales and profitability, and our ability to make cash distributions.
Adverse weather conditions during peak fertilizer application periods may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions, because our agricultural customers are geographically concentrated.
Our sales of nitrogen fertilizer products to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. For example, we generate greater net sales and operating income in the first half of the year, which we refer to 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 our net sales and margins and otherwise have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. Our quarterly results may vary significantly from one year to the next due largely to weather-related shifts in planting schedules and purchase patterns. In addition, given the seasonal nature of our business, we expect that our distributions will be volatile and will vary quarterly and annually.
Our business is seasonal, which may result in our 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.
Our 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 our products typically occurs during the planting season. In contrast, we and other nitrogen fertilizer producers generally produce our products throughout the year. As a result, we and our 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 our sales volumes and net sales being highest during the North American spring season and our working capital requirements typically being highest just prior to the start of the spring season.
If seasonal demand exceeds our projections, we will not have enough product and our customers may acquire products from our competitors, which would negatively impact our profitability. If seasonal demand is less than we expect, we will be left with excess inventory and higher working capital and liquidity requirements.
The degree of seasonality of our business can change significantly from year to year due to conditions in the agricultural industry and other factors. As a consequence of our seasonality, we expect that our distributions will be volatile and will vary quarterly and annually.
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Our operations are dependent on third-party suppliers, including Linde, which owns an air separation plant that provides oxygen, nitrogen and compressed dry air to our gasifiers, and the City of Coffeyville, which supplies us 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 our ability to make cash distributions.
Our operations 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, our 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 our nitrogen fertilizer plant was disrupted. Additionally, this air separation plant in the past has experienced numerous short-term interruptions, causing interruptions in our gasifier operations. With respect to electricity, we recently settled litigation with the City of Coffeyville regarding the price they sought to charge us for electricity and entered into an amended and restated electric services agreement which gives us an option to extend the term of such agreement through June 30, 2024. Should Linde, the City of Coffeyville or any of our other third-party suppliers fail to perform in accordance with existing contractual arrangements, our operation could be forced to halt. Alternative sources of supply could be difficult to obtain. Any shutdown of our operations, even for a limited period, could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Our results of operations, financial condition and ability to make cash distributions may be adversely affected by the supply and price levels of pet coke. Failure by CVR Energy to continue to supply us with pet coke (to the extent third-party pet coke is unavailable or available only at higher prices), or CVR Energy’s imposition of an obligation to provide it with security for our payment obligations, could negatively impact our results of operations.
Our profitability is directly affected by the price and availability of pet coke obtained from CVR Energy’s Coffeyville, Kansas crude oil refinery pursuant to a long-term agreement and pet coke purchased from third parties (with respect to which we have no contractual arrangements), both of which vary based on market prices. Pet coke is a key raw material used by us in the manufacture of nitrogen fertilizer products. If pet coke costs increase, we may not be able to increase our prices to recover these increased costs, because market prices for our nitrogen fertilizer products are not correlated with pet coke prices.
Based on our current output, we obtain most (over 70% on average during the last five years) of the pet coke we need from CVR Energy’s adjacent crude oil refinery, and procure the remainder on the open market. The price that we pay CVR Energy for pet coke is based on the lesser of a pet coke price derived from the price we receive for UAN (subject to a UAN-based price ceiling and floor) and a pet coke index price. In most cases, the price we pay CVR Energy will be lower than the price which we would otherwise pay to third parties. Pet coke prices could significantly increase in the future. Should CVR Energy fail to perform in accordance with our existing agreement, we would need to purchase pet coke from third parties on the open market, which could negatively impact our results of operations to the extent third-party pet coke is unavailable or available only at higher prices.
We may not be able to maintain an adequate supply of pet coke. In addition, we could experience production delays or cost increases if alternative sources of supply prove to be more expensive or difficult to obtain. We currently purchase 100% of the pet coke produced by CVR Energy’s Coffeyville refinery. Accordingly, if we increase our production, we will be more dependent on pet coke purchases from third-party suppliers at open market prices. There is no assurance that we would be able to purchase pet coke on comparable terms from third parties or at all.
Under our pet coke agreement with CVR Energy, we may become obligated to provide security for our payment obligations if, in CVR Energy’s sole judgment, there is a material adverse change in our financial condition or liquidity position or in our ability to pay for our pet coke purchases. See “Certain Relationships and Related Transactions, and Director Independence – Agreements with CVR Energy – Coke Supply Agreement.”
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We rely on third-party providers of transportation services and equipment, which subjects us to risks and uncertainties beyond our control that may have a material adverse effect on our results of operations, financial condition and ability to make distributions.
We rely on railroad and trucking companies to ship finished products to our customers. We also lease railcars from railcar owners in order to ship our 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 our finished products. In addition, new regulations could be implemented affecting the equipment used to ship our finished products.
Any delay in our ability to ship our 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 ability to make cash distributions.
Our facility faces operating hazards and interruptions, including unplanned 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 our industry may cease to do so, may change the coverage provided or may substantially increase premiums in the future.
Our operations, located at a single location, are subject to significant operating hazards and interruptions. Any significant curtailing of production at our nitrogen fertilizer plant or individual units within our plant could result in materially lower levels of revenues and cash flow for the duration of any shutdown and materially adversely impact our ability to make cash distributions. Operations at our nitrogen fertilizer plant could be curtailed or partially or completely shut down, temporarily or permanently, as the result of a number of circumstances, most of which are not within our control, such as:
| • | unscheduled maintenance or catastrophic events such as a major accident or fire, damage by severe weather, flooding or other natural disaster; |
| • | labor difficulties that result in a work stoppage or slowdown; |
| • | environmental proceedings or other litigation that compel the cessation of all or a portion of the operations at our nitrogen fertilizer plant; |
| • | increasingly stringent environmental regulations; |
| • | a disruption in the supply of pet coke to our nitrogen fertilizer plant; and |
| • | a governmental ban or other limitation on the use of nitrogen fertilizer products, either generally or specifically those manufactured at our plant. |
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 plant requires a scheduled maintenance turnaround every two years, which generally lasts up to three weeks. A major accident, fire, flood, or other event could damage our facility 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 facility for approximately two weeks and required significant expenditures to repair damaged equipment, and our UAN plant was out of service for approximately six weeks after the rupture of a high pressure vessel in September 2010, which had a significant impact on our revenues and cash flows for the fourth quarter of 2010. Moreover, our facility is located adjacent
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to CVR Energy’s Coffeyville, Kansas refinery, and a major accident or disaster at the refinery could adversely affect our operations. Planned and unplanned maintenance could reduce our net income, cash flow and ability to make cash distributions during the period of time that any of our units is not operating. Any unplanned future downtime could have a material adverse effect on our ability to make cash distributions to our unitholders.
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. We are currently insured under CVR Energy’s casualty, environmental, property and business interruption insurance policies. The property and business interruption insurance policies have a $1.0 billion limit, with a $2.5 million deductible for physical damage and a 45- to 60-day waiting period (depending on the insurance carrier) before losses resulting from business interruptions are recoverable. 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 to 60 days.
The nitrogen fertilizer industry is highly capital intensive, and the entire or partial loss of facilities can result in significant costs to participants, such as us, and their insurance carriers. Market factors, including but not limited to catastrophic perils that impact our industry, significant changes in the investment returns of insurance companies, insurance company solvency trends and industry loss ratios and loss trends, can negatively impact the future cost and availability of insurance. There can be no assurance that CVR Energy or we will be able to buy and maintain insurance with adequate limits, reasonable pricing terms and conditions.
Deliberate, malicious acts, including terrorism, could damage our facilities, disrupt our operations or injure employees, contractors, customers or the public and result in liability to us.
Intentional acts of destruction could hinder our sales or production and disrupt our supply chain. Our facilities could be damaged or destroyed, reducing our operational production capacity and requiring us to repair or replace our facilities at substantial cost. Employees, contractors and the public could suffer substantial physical injury for which we could be liable. Governmental authorities may impose security or other requirements that could make our operations more difficult or costly. The consequences of any such actions could adversely affect our operating results, financial condition and ability to make distributions.
Our 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.
Our results of operations are highly dependent upon business and economic conditions and governmental policies affecting the agricultural industry, which we cannot control. The agricultural products business can be affected by a number of factors. The most important of these factors in the United States are:
| • | weather patterns and field conditions (particularly during periods of traditionally high nitrogen fertilizer consumption); |
| • | quantities of nitrogen fertilizers imported to and exported from North America; |
| • | current and projected grain inventories and prices, which are heavily influenced by U.S. exports and world-wide grain markets; and |
| • | U.S. governmental policies, including farm and biofuel policies, which may directly or indirectly influence the number of acres planted, the level of grain inventories, the mix of crops planted or crop prices. |
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International market conditions, which are also outside of our control, may also significantly influence our 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 or other products we produce or transport 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 ability to make cash distributions. In addition, the costs of transporting ammonia could increase significantly in the future.
We manufacture, process, store, handle, distribute and transport 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 our ability to produce or distribute our products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure our assets, which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. We periodically experience minor releases of ammonia related to leaks from our equipment. We experienced more significant ammonia releases in August 2007 due to the failure of a high-pressure pump and in August and September 2010 due to a heat exchanger leak and a UAN vessel rupture. Similar events may occur in the future.
In addition, we may incur significant losses or costs relating to the operation of our railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially toxic nature of the cargo, in particular ammonia, on board railcars, a railcar accident may result in fires, explosions and pollution. These circumstances may result in sudden, severe damage or injury to property, the environment and human health. In the event of pollution, we may be held responsible even if we are not at fault and we complied with the laws and regulations in effect at the time of the accident. Litigation arising from accidents involving ammonia and other products we produce or transport may result in our 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 ability to make cash distributions.
Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is most typically transported by pipeline and railcar. A number of initiatives are underway in the railroad and chemical industries that may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. In addition, in the future, laws may more severely restrict or eliminate our ability to transport ammonia via railcar. If any railcar design changes are implemented, or if accidents involving hazardous freight increase the insurance and other costs of railcars, our freight costs could significantly increase.
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 or facility shutdowns.
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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 ability to make cash distributions.
Our facility operates 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 facility is also required to comply with prescriptive limits and meet performance standards specific to 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 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 the occurrence of accidental spills, discharges or other releases of hazardous substances into the environment. Past or future spills related to our nitrogen fertilizer plant or transportation of products or hazardous substances from our facility may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, 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 the facility we currently own and operate (whether or not such contamination occurred prior to our acquisition thereof), facilities we formerly owned or operated (if any) and facilities to which we transported or arranged for the transportation of wastes or byproducts containing hazardous substances for treatment, storage, or disposal. The potential penalties and cleanup costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
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 facility. 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 facility to adjacent and other nearby properties.
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 nitrogen fertilizer facility. 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
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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 business, financial condition, results of operations and ability to make cash distributions.
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 our products. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit our ability to market and sell our 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 our fertilizer products in those states. Similarly, a new final Environmental Protection Agency (the “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. The rule has been challenged and may be replaced with a state rule imposing similar numeric nutrient criteria. Such laws, regulations or interpretations could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Climate change laws and regulations could have a material adverse effect on our results of operations, financial condition, and ability to make cash distributions.
Various legislative and regulatory measures to address greenhouse gas emissions (including CO2, methane and nitrous oxides) are in various phases of discussion or implementation. In the aftermath of its 2009 “endangerment finding” that greenhouse gas emissions pose a threat to human health and welfare, the EPA has begun to regulate greenhouse gas emissions under the authority granted to it under the Clean Air Act. In October 2009, the EPA finalized a rule requiring certain large emitters of greenhouse gases to inventory and annually report their greenhouse gas emissions to the EPA. In accordance with the rule, we began monitoring our greenhouse gas emissions from our nitrogen fertilizer plant and have already reported emissions to the EPA for the year ended 2011. In May 2010, the EPA finalized the “Greenhouse Gas Tailoring Rule,” which established new greenhouse gas emissions thresholds that determine when stationary sources, such as our nitrogen fertilizer plant, must obtain permits under the Prevention of Significant Deterioration, or PSD, and Title V programs of the federal Clean Air Act. The significance of the permitting requirement is that, in cases where a new source is constructed or an existing source undergoes a major modification, the facility would need to evaluate and install best available control technology, or BACT, for its greenhouse gas emissions. A major modification resulting in a significant expansion of production at our nitrogen fertilizer plant that causes a significant increase in greenhouse gas emissions could require the installation of BACT controls. However, we do not believe that our ongoing or anticipated expansion projects would trigger the need to install BACT controls. The EPA’s endangerment finding, Greenhouse Gas Tailoring Rule and certain other greenhouse gas emission rules have been challenged and will likely be subject to extensive litigation.
At the federal legislative level, Congressional passage of legislation adopting some form of federal mandatory greenhouse gas emission reduction, such as a nationwide cap-and-trade program, does not appear likely at this time, although it could be adopted at a future date. It is also possible that Congress may pass alternative climate change bills that do not mandate a nationwide cap-and-trade program and instead focus on promoting renewable energy and energy efficiency.
In addition to potential federal legislation, a number of states have adopted regional greenhouse gas initiatives to reduce CO2 and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas (where our nitrogen fertilizer facility is located), formed the Midwestern Greenhouse Gas Reduction Accord, which calls for the development of a cap-and-trade system to control greenhouse gas emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and it is unclear whether Kansas still intends to do so.
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The implementation of EPA greenhouse gas regulations or potential federal, state or regional programs to reduce greenhouse gas emissions will likely 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 ability to make cash distributions.
In addition, climate change legislation and regulations may result in increased costs not only for our business but also for agricultural producers that utilize our fertilizer products, thereby potentially decreasing demand for our fertilizer products. Decreased demand for our fertilizer products may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
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 future regulations relating to the transportation of hazardous chemicals and security associated with our nitrogen fertilizer facility may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. Targets such as chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. The chemical industry has responded to the issues that arose in response to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives that could result in a material adverse effect on our results of operations, financial condition and ability to make cash distributions .
Due to our lack of asset diversification, adverse developments in the nitrogen fertilizer industry could adversely affect our results of operations and our ability to make distributions to our unitholders.
We rely exclusively on the revenues generated from our nitrogen fertilizer business. An adverse development in the nitrogen fertilizer industry would have a significantly greater impact on our operations and cash available for distribution to holders of common units than it will on other companies with a more diverse asset and product base. The largest publicly traded companies with which we compete sell a more varied range of fertilizer products.
Our business depends on significant customers, and the loss of one or several significant customers may have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Our business has a high concentration of customers. In the aggregate, our top five ammonia customers represented 61.3% of our ammonia sales, and our top five UAN customers represented 49.0% of our UAN sales, for the year ended December 31, 2011. 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 ability to make cash distributions.
There can be no assurance that the transportation costs of our 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 fertilizers grow their crops. Many of our competitors produce fertilizer outside 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 could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
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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 ability to make cash distributions.
Our facility is subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA and certain environmental regulations require that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees and state and local governmental authorities. Failure to comply with 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 ability to make cash distributions if we are subjected to significant fines or compliance costs.
Instability and volatility in the global capital, credit and commodity markets could negatively impact our business, financial condition, results of operations and ability to make cash distributions.
The global capital and credit markets have experienced extreme volatility and disruption in recent years. Our business, results of operations, financial condition and ability to make cash distributions could be negatively impacted by difficult conditions and extreme volatility in the capital, credit and commodities markets and in the global economy. These factors, combined with declining business and consumer confidence and increased unemployment, precipitated an economic recession in the United States and globally. The difficult conditions in these markets and the overall economy affect us in a number of ways. For example:
| • | Although we believe we will have sufficient liquidity under our credit facility to run our business, under extreme market conditions there can be no assurance that such funds would be available or sufficient, and in such a case, we may not be able to successfully obtain additional financing on favorable terms, or at all. |
| • | Market volatility could exert downward pressure on the price of our common units, which may make it more difficult for us to raise additional capital and thereby limit our ability to grow. |
| • | Our credit facility contains various covenants that must be complied with, and if we are not in compliance, there can be no assurance that we would be able to successfully amend the agreement in the future. Further, any such amendment may be expensive. |
| • | Market conditions could result in our significant customers experiencing financial difficulties. We are exposed to the credit risk of our customers, and their failure to meet their financial obligations when due because of bankruptcy, lack of liquidity, operational failure or other reasons could result in decreased sales and earnings for us. |
Our acquisition and expansion strategy involves significant risks.
One of our business strategies is to pursue acquisitions and expansion projects (including the ongoing expansion of our UAN capacity). 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, tax consequences and risks associated with entry into new markets and lines of business.
We are in the process of expanding our nitrogen fertilizer plant, which is expected to allow us the flexibility to upgrade all of our ammonia production to UAN. This expansion is premised in large part on the historically higher margin that we have received for UAN compared to ammonia. If the premium that UAN currently earns over ammonia decreases, this expansion project may not yield the economic benefits and accretive effects that we currently anticipate.
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In addition to the risks involved in identifying and completing acquisitions described above, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:
| • | unforeseen difficulties in the acquired operations and disruption of the ongoing operations of our business; |
| • | failure to achieve cost savings or other financial or operating objectives with respect to an acquisition; |
| • | strain on the operational and managerial controls and procedures of our business, and the need to modify systems or to add management resources; |
| • | difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies; |
| • | assumption of unknown material liabilities or regulatory non-compliance issues; |
| • | amortization of acquired assets, which would reduce future reported earnings; |
| • | possible adverse short-term effects on our cash flows or operating results; and |
| • | diversion of management’s attention from the ongoing operations of our business. |
In addition, in connection with any potential acquisition or expansion project, we will need to consider whether the business we intend to acquire or expansion project we intend to pursue could affect our tax treatment as a partnership for U.S. federal income tax purposes. If we are otherwise unable to conclude that the activities of the business being acquired or the expansion project would not affect our treatment as a partnership for U.S. federal income tax purposes, we could seek a ruling from the Internal Revenue Service, or IRS. Seeking such a ruling could be costly or, in the case of competitive acquisitions, place us in a competitive disadvantage compared to other potential acquirers who do not seek such a ruling. If we are unable to conclude that an activity would not affect our treatment as a partnership for U.S. federal income tax purposes, we could 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. See “— Tax Risks — Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced, likely causing a substantial reduction in the value of our common units.”
Failure to manage acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. 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 rely on the executive officers of CVR Energy to manage many aspects of our business and affairs pursuant to a services agreement, which CVR Energy can terminate at any time after April 13, 2012, subject to a 180-day notice period.
Our future performance depends to a significant degree upon the continued contributions of CVR Energy’s senior management team. We have entered into a services agreement with our general partner and CVR Energy whereby CVR Energy has agreed to provide us with the services of its senior management team as well as accounting, business operations, legal, finance and other key back-office and mid-office personnel. At any time after April 13, 2012, CVR Energy can terminate this agreement, subject to a 180-day notice period. The loss or unavailability to us of any member of CVR Energy’s senior management team could negatively affect our ability to operate our business and pursue our business strategies. We do not have employment agreements with any of CVR Energy’s officers and we do not maintain any key person insurance. We can provide no assurance that CVR Energy will continue to provide us the officers that are necessary for the conduct of our business nor that such provision will be on terms that are acceptable. If CVR Energy elected to terminate the agreement on 180 days’ notice, we might not be able to find qualified individuals to serve as our executive officers within such 180-day period.
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In addition, pursuant to the services agreement we are responsible for a portion of the compensation expense of such executive officers according to the percentage of time such executive officers spent working for us. However, the compensation of such executive officers is set by CVR Energy, and we have no control over the amount paid to such officers. The services agreement does not contain any cap on the amounts we may be required to pay CVR Energy pursuant to this agreement.
A shortage of skilled labor, together with rising labor costs, could adversely affect our results of operations and cash available for distribution to our unitholders.
Efficient production of nitrogen fertilizer using modern techniques and equipment requires skilled employees. Our nitrogen fertilizer facility relies on gasification technology that requires special expertise to operate efficiently and effectively. To the extent that the services of our key technical personnel become unavailable to us for any reason, we would be required to hire other personnel. We may not be able to locate or employ such qualified personnel on acceptable terms or at all. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. If we are unable to find qualified employees, or if the cost to find qualified employees increases materially, our results of operations and cash available for distribution to our unitholders could be adversely affected.
If licensed technology were no longer available, our business may be adversely affected.
We have licensed, and may in the future license, a combination of patent, trade secret and other intellectual property rights of third parties for use in our business. In particular, the gasification process we use 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 us perpetual rights to use the pet coke gasification process on specified terms and conditions and is integral to the operations of our facility. If this license, or any other license agreements on which our 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 ability to make cash distributions.
Security breaches and other disruptions could compromise our information and expose us to liability, which would cause our business and reputation to suffer.
In the ordinary course of our business, we collect and store sensitive data, including intellectual property, our proprietary business information and that of our customers and suppliers, and personally identifiable information of our employees, in our facilities and on our networks. The secure processing, maintenance and transmission of this information is critical to our operations. Despite our security measures, our information technology and infrastructure may be vulnerable to attacks by hackers or breached due to employee error, malfeasance or other disruptions. Any such breach could compromise our networks and the information stored there could be accessed, publicly disclosed, lost or stolen. Any such access, disclosure or other loss of information could result in legal claims or proceedings, disrupt our operations, damage our reputation, and cause a loss of confidence, which could adversely affect our business.
We may face third-party claims of intellectual property infringement, which if successful could result in significant costs for our business.
There are currently no claims pending against us relating to the infringement of any third-party intellectual property rights. However, in the future we may face claims of infringement that could interfere with our ability to use technology that is material to our business operations. Any litigation of this type, whether successful or unsuccessful, could result in substantial costs to us and diversions of our resources, either of which could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions. In
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the event a claim of infringement against us is successful, we may be required to pay royalties or license fees for past or continued use of the infringing technology, or we may be prohibited from using the infringing technology altogether. If we are prohibited from using any technology as a result of such a claim, we may not be able to obtain licenses to alternative technology adequate to substitute for the technology we can no longer use, or licenses for such alternative technology may only be available on terms that are not commercially reasonable or acceptable to us. In addition, any substitution of new technology for currently licensed technology may require us to make substantial changes to our manufacturing processes or equipment or to our products, and could have a material adverse effect on our results of operations, financial condition and ability to make cash distributions.
Our 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, 2011, we had $125.0 million in outstanding term loan borrowings and borrowing availability of $25.0 million under our revolving credit facility. We and our subsidiary 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 level of indebtedness could have important consequences, such as:
| • | limiting our ability to obtain additional financing to fund our working capital needs, capital expenditures, debt service requirements, acquisitions or for other purposes; |
| • | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt; |
| • | limiting our ability to compete with other companies who are not as highly leveraged, as we may be less capable of responding to adverse economic and industry conditions; |
| • | restricting us from making strategic acquisitions, introducing new technologies or exploiting business opportunities; |
| • | restricting the way in which we conduct our business because of financial and operating covenants in the agreements governing our and our subsidiaries’ existing and future indebtedness, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us; |
| • | exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries’ debt instruments that could have a material adverse effect on our business, financial condition and operating results; |
| • | increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and |
| • | limiting our ability to react to changing market conditions in our industry and in our customers’ industries. |
In addition, borrowings under our 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 ability to make distributions. While we may enter into agreements limiting our exposure to higher interest rates, any such agreements may not offer complete protection from this risk.
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.
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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 (including restrictions on distributions to our unitholders), 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. Our credit facility provides that we can make distributions to holders of our common units, but only if we are in compliance with our leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution and there is no default or event of default under the facility. If we were unable to comply with any such covenant restrictions in any quarter, our ability to make distributions to unitholders would be curtailed. In addition, the termination or non-renewal of, or violation by CVR Energy of its covenants in, any of the intercompany agreements between us and CVR Energy that has a material adverse effect on us would trigger an event of 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, subject to the intercreditor agreements. In addition, any defaults 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.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under our indebtedness that may not be successful.
Our ability to satisfy our debt obligations will depend upon, among other things:
| • | our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, many of which are beyond our control; and |
| • | our future ability to borrow under our credit facility, the availability of which depends on, among other things, our complying with the covenants in the credit facility. |
We cannot offer any assurance that our business will generate sufficient cash flow from operations, or that we will be able to draw under our credit facility or otherwise, in an amount sufficient to fund our liquidity needs. In addition, our general partner’s current policy is to distribute all available cash we generate on a quarterly basis, and the board of directors of our general partner may in the future elect to pay a special distribution, engage in unit repurchases or pursue other strategic options including acquisitions of other business or asset purchases, which would reduce cash available to service our debt obligations.
If our cash flows and capital resources are insufficient to service our indebtedness, we may be forced to reduce or suspend distributions, reduce or delay capital expenditures, sell assets, seek additional capital or restructure or refinance our indebtedness or seek bankruptcy protection. These alternative measures may not be successful and may not permit us to meet our scheduled debt service obligations. Our ability to restructure or refinance our debt will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our debt could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. In addition, the terms of existing or future debt agreements may restrict us from adopting some of these alternatives. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations, sell equity, and/or negotiate with our lenders to restructure the applicable debt, in order to meet our debt service and other obligations. We may not be able to consummate those dispositions for fair market value or at all. Our credit facility or market or business conditions may limit our ability to avail ourselves of some or all of these options. Furthermore, any proceeds that we could realize from any such dispositions may not be adequate to meet our debt service obligations then due.
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Our debt agreements contain restrictions that will limit our flexibility in operating our business and our ability to make distributions to our unitholders.
Our credit facility contains, and any instruments governing future indebtedness of ours would likely contain, a number of covenants that impose significant operating and financial restrictions on us, including restrictions on our and our subsidiaries’ ability to, among other things:
| • | incur additional indebtedness or issue certain preferred units; |
| • | pay distributions in respect of our units or make other restricted payments; |
| • | make certain payments on debt that is subordinated or secured on a junior basis; |
| • | make certain investments; |
| • | sell certain assets; |
| • | create liens on certain assets; |
| • | consolidate, merge, sell or otherwise dispose of all or substantially all of our assets; |
| • | enter into certain transactions with our affiliates; and |
| • | designate our subsidiaries as unrestricted subsidiaries. |
Any of these restrictions could limit our ability to plan for or react to market conditions and could otherwise restrict partnership activities. 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 assets, and force us into bankruptcy or liquidation, subject to any applicable intercreditor agreements. In addition, a default under our credit facility would trigger a cross default under our other agreements and could trigger a cross default under the agreements governing our future indebtedness. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.
Despite our indebtedness, we may still be able to incur significantly more debt, including secured indebtedness. This could intensify the risks described above.
We may be able to incur substantially more debt in the future, including secured indebtedness. Although our credit facility contains restrictions on our incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions and, under certain circumstances, indebtedness incurred in compliance with these restrictions could be substantial. Also, these restrictions may not prevent us from incurring obligations that do not constitute indebtedness. To the extent such new debt or new obligations are added to our existing indebtedness, the risks described above could substantially increase.
We are a holding company and depend upon our subsidiary for our cash flow.
We are a holding company. All of our operations are conducted and all of our assets are owned by Coffeyville Resources Nitrogen Fertilizers, LLC, or CRNF, our wholly-owned subsidiary and our sole subsidiary. Consequently, our cash flow and our ability to meet our obligations or to make cash distributions in the future will depend upon the cash flow of our subsidiary and the payment of funds by our subsidiary to us in the form of dividends or otherwise. The ability of our subsidiary to make any payments to us will depend on its earnings, the terms of its indebtedness, including the terms of any credit facilities, and legal restrictions. In particular, future credit facilities incurred at our subsidiary may impose significant limitations on the ability of our subsidiary to make distributions to us and consequently our ability to make distributions to our unitholders.
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As a publicly traded partnership we qualify for certain exemptions from the New York Stock Exchange’s corporate governance requirements.
As a publicly traded partnership, we qualify for certain exemptions from the New York Stock Exchange’s corporate governance requirements, including:
| • | the requirement that a majority of the board of directors of our general partner consist of independent directors; |
| • | the requirement that the board of directors of our general partner have a nominating/corporate governance committee that is composed entirely of independent directors; and |
| • | the requirement that the board of directors of our general partner have a compensation committee that is composed entirely of independent directors. |
Our general partner’s board of directors has not and does not currently intend to establish a nominating/corporate governance committee. Additionally, we could avail ourselves of the additional exemptions available to publicly traded partnerships listed above at any time in the future. Accordingly, unitholders do not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the New York Stock Exchange.
We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.
We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We 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 our annual report for the year ended December 31, 2012. Furthermore, upon completion of this process, we 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 we produce our financial statements in accordance with U.S. Generally Accepted Accounting Principles (“GAAP”), our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. As a publicly traded partnership, we 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 controls 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 we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC. If we do not implement improvements to our disclosure controls and procedures or to our internal controls in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal controls over financial reporting pursuant to an audit of our internal controls over financial reporting. This may subject us to adverse regulatory consequences or a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our independent registered public accounting firm reports a material weakness in our internal controls, if we do not develop and maintain effective controls and procedures or if we are otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of our financial statements or other negative reaction to our failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of our common units. In addition, if we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and the price of our common units may be adversely affected.
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Our relationship with CVR Energy and its financial condition subjects us to potential risks that are beyond our control.
Due to our relationship with CVR Energy, adverse developments or announcements concerning CVR Energy could materially adversely affect our financial condition, even if we have not suffered any similar development. The ratings assigned to CVR Energy’s senior secured indebtedness are below investment grade. Downgrades of the credit ratings of CVR Energy could increase our cost of capital and collateral requirements, and could impede our access to the capital markets.
The credit and business risk profiles of CVR Energy may be factors considered in credit evaluations of us. This is because we rely on CVR Energy for various services, including management services and the supply of pet coke. Another factor that may be considered is the financial condition of CVR Energy, including the degree of its financial leverage and its dependence on cash flow from us to service its indebtedness. The credit and risk profile of CVR Energy could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.
If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of CVR Energy, as credit rating agencies may consider the leverage and credit profile of CVR Energy and its affiliates because of their ownership interest in and joint control of us and the strong operational links between CVR Energy’s refining business and us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make cash distributions to unitholders.
Risks Related to Our Limited Partnership Structure and Our Common Units
The board of directors of our general partner has adopted a policy to distribute all of the available cash we generate on a quarterly basis, which could limit our ability to grow and make acquisitions.
Our general partner’s current policy is to distribute all of the available cash we generate on a quarterly basis to our unitholders. As a result, we will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.
In addition, because of our general partner’s current distribution policy, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units will decrease the amount we distribute on each outstanding unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, would reduce the available cash that we have to distribute to our unitholders.
Our general partner, an indirect wholly-owned subsidiary of CVR Energy, has fiduciary duties to CVR Energy and its stockholders, and the interests of CVR Energy and its stockholders may differ significantly from, or conflict with, the interests of our public common unitholders.
Our general partner is responsible for managing us. Although our general partner has fiduciary duties to manage us in a manner that is in our best interests, the fiduciary duties are specifically limited by the express terms of our partnership agreement, and the directors and officers of our general partner also have fiduciary duties to manage our general partner in a manner beneficial to CVR Energy and its stockholders. The interests of CVR Energy and its stockholders may differ from, or conflict with, the interests of our common unitholders. In
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resolving these conflicts, our general partner may favor its own interests, the interests of Coffeyville Resources, its sole member, or the interests of CVR Energy and holders of CVR Energy’s common stock over our interests and those of our common unitholders.
The potential conflicts of interest include, among others, the following:
| • | Neither our partnership agreement nor any other agreement requires the owners of our general partner, including CVR Energy, to pursue a business strategy that favors us. The affiliates of our general partner, including CVR Energy, have fiduciary duties to make decisions in their own best interests and in the best interest of holders of CVR Energy’s common stock, which may be contrary to our interests. In addition, our general partner is allowed to take into account the interests of parties other than us or our unitholders, such as its owners or CVR Energy, in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to our unitholders. |
| • | Our general partner has limited its liability and reduced its fiduciary duties under our partnership agreement and has also restricted the remedies available to our unitholders for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
| • | The board of directors of our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness and issuances of additional partnership interests, each of which can affect the amount of cash that is available for distribution to our common unitholders. |
| • | Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf. There is no limitation on the amounts our general partner can cause us to pay it or its affiliates. |
| • | Our general partner may exercise its rights to call and purchase all of our common units if at any time it and its affiliates (including Coffeyville Resources) own more than 80% of the common units. |
| • | Our general partner controls the enforcement of obligations owed to us by it and its affiliates. In addition, our general partner decides whether to retain separate counsel or others to perform services for us. |
| • | Our general partner determines which costs incurred by it and its affiliates are reimbursable by us. |
| • | Most of the executive officers of our general partner also serve as executive officers of CVR Energy, and the executive chairman of our board of directors is the chairman and chief executive officer of CVR Energy. The executive officers who work for both CVR Energy and our general partner, including our chief financial officer, chief operating officer and general counsel, divide their time between our business and the business of CVR Energy. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or CVR Energy. |
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner and restricts the remedies available to us and our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our common unitholders for actions that, without these limitations and reductions, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. By purchasing common units, common unitholders consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example:
| • | Our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to its capacity as general partner. This entitles our general partner to consider only |
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| the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, our common unitholders. Decisions made by our general partner in its individual capacity are made by Coffeyville Resources as the sole member of our general partner, and not by the board of directors of our general partner. Examples include the exercise of the general partner’s call right, its voting rights with respect to any common units it may own, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to our partnership agreement. |
| • | Our partnership agreement provides that our general partner will not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning it believed that the decisions were in our best interests. |
| • | Our partnership agreement provides that our general partner and the officers and directors of our general partner will not be liable for monetary damages to us for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those persons acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal. |
| • | Our partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally provided to or available from unrelated third parties or be “fair and reasonable.” In determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationship between the parties involved, including other transactions that may be particularly advantageous or beneficial to us. |
By purchasing a common unit, a unitholder becomes bound by the provisions of our partnership agreement, including the provisions described above.
Our unitholders have limited voting rights, and CVR Energy has the power to appoint and remove our general partner’s directors.
Our general partner has control over all decisions related to our operations. Furthermore, CVR Energy, through its ownership of 100% of Coffeyville Resources, has the power to elect all of the members of the board of directors of our general partner. The goals and objectives of CVR Energy, as the indirect owner of our general partner, may not be consistent with those of our public unitholders.
Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Our public unitholders do not have an ability to influence any operating decisions and are not able to prevent us from entering into any transactions. Unlike publicly traded corporations, we do not hold annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders. Furthermore, even if our unitholders are dissatisfied with the performance of our general partner, they have no practical ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished.
Common units are subject to our general partner’s call right.
If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by public unitholders at a price not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, each holder of our common units may be required to sell such holder’s common units at an undesirable time or price and may not receive any return on investment. Each holder of our common units may also incur a tax liability upon a sale of such holder’s common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the call right. There is no restriction in our
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partnership agreement that prevents our general partner from issuing additional common units and then exercising its call right. Our general partner may use its own discretion, free of fiduciary duty restrictions, in determining whether to exercise this right.
Our public unitholders do not have sufficient voting power to remove our general partner without CVR Energy’s consent.
CVR Energy indirectly owns approximately 70% of our common units, which means holders of common units are not able to remove the general partner, under any circumstances, unless CVR Energy sells some of the common units that it owns or we sell additional units to the public, in either case, such that CVR Energy owns less than 50% of our common units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units (other than our general partner and its affiliates and permitted transferees).
Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, may not vote on any matter. Our partnership agreement also contains provisions limiting the ability of common unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the ability of our common unitholders to influence the manner or direction of management.
Cost reimbursements due to our general partner and its affiliates will reduce cash available for distribution to you.
Prior to making any distribution on our outstanding units, we will reimburse our general partner for all expenses it incurs on our behalf including, without limitation, our pro rata portion of management compensation and overhead charged by CVR Energy in accordance with our services agreement. The services agreement does not contain any cap on the amount we may be required to pay pursuant to this agreement. The payment of these amounts, including allocated overhead, to our general partner and its affiliates could adversely affect our ability to make distributions to you.
Limited partners may not have limited liability if a court finds that unitholder action constitutes control of our business.
A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and our subsidiary conducts business in a number of other states, including Kansas, Nebraska and Texas. Limited partners could be liable for our obligations as if such limited partners were general partners if a court or government agency determined that:
| • | we were conducting business in a state but had not complied with that particular state’s partnership statute; or |
| • | limited partners’ right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constituted “control” of our business. |
Unitholders may have liability to repay distributions.
In the event that: (i) we make distributions to our unitholders when our nonrecourse liabilities exceed the sum of (a) the fair market value of our assets not subject to recourse liability and (b) the excess of the fair market value of our assets subject to recourse liability over such liability, or a distribution causes such a result, and (ii) a unitholder knows at the time of the distribution of such circumstances, such unitholder will be liable for a period of three years from the time of the impermissible distribution to repay the distribution under Section 17-607 of the Delaware Act.
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Likewise, upon the winding up of the partnership, in the event that (a) we do not distribute assets in the following order: (i) to creditors in satisfaction of their liabilities; (ii) to partners and former partners in satisfaction of liabilities for distributions owed under our partnership agreement; (iii) to partners for the return of their contribution; and finally (iv) to the partners in the proportions in which the partners share in distributions and (b) a unitholder knows at the time of such circumstances, then such unitholder will be liable for a period of three years from the impermissible distribution to repay the distribution under Section 17-807 of the Delaware Act.
Our general partner’s interest in us and the control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest in us to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of CVR Energy to transfer its equity interest in our general partner to a third party. The new equity owner of our general partner would then be in a position to replace the board of directors and the officers of our general partner with its own choices and to influence the decisions taken by the board of directors and officers of our general partner.
If control of our general partner were transferred to an unrelated third party, the new owner of the general partner would have no interest in CVR Energy. We rely substantially on the senior management team of CVR Energy and have entered into a number of significant agreements with CVR Energy, including a services agreement pursuant to which CVR Energy provides us with the services of its senior management team and a long-term agreement for the provision of pet coke. If our general partner were no longer controlled by CVR Energy, CVR Energy could be more likely to terminate the services agreement which, beginning on April 13, 2012, it may do upon 180 days’ notice, or elect not to renew the pet coke agreement, which expires in 2027.
Our business could be negatively affected as a result of a threatened proxy contest and pending tender offer with respect to CVR Energy.
CVR Energy, which indirectly owns our general partner and approximately 70% of our common units, recently received a notice from certain funds affiliated with Carl Icahn that discloses their intent to nominate nine individuals for election to CVR Energy’s Board of Directors. In addition, on February 23, 2012, certain funds affiliated with Carl Icahn commenced a tender offer for control of CVR Energy with the intention, following completion of such tender offer, to seek to sell CVR Energy to a strategic acquiror. Our general partner is an indirect wholly-owned subsidiary of CVR Energy, and consequently CVR Energy has the right to nominate all of the members of the board of directors of our general partner.
The Partnership could be adversely affected by these events because, among other things:
| • | Perceived uncertainties as to CVR Energy’s and our future direction may result in the loss of potential business opportunities and may make it more difficult to attract and retain qualified personnel and business partners; and |
| • | If individuals with a specific agenda are elected to CVR Energy’s Board of Directors, or if a third party obtains control of CVR Energy, they may have a different view as to the future direction of the Partnership and CVR Energy’s ownership of our common units that may adversely affect our ability to implement our strategic objectives effectively and timely. |
CVR Energy provides us with the services of its senior management team as well as accounting, business operations, legal, finance and other key back-office and mid-office personnel pursuant to a services agreement which it can terminate at any time after April 13, 2012, subject to a 180-day notice period. CVR Energy also has the right under our partnership agreement to sell our general partner at any time to a third party, who would be able to replace our entire board of directors. Finally, CVR Energy currently owns the majority of our common units. A new board of directors at CVR Energy might have a different view as to whether to maintain any or all of the foregoing, which could have a material adverse effect on the Partnership.
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Increases in interest rates could adversely impact our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.
We cannot predict how interest rates will react to changing market conditions. Interest rates on our credit facility, future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Additionally, as with other yield-oriented securities, we expect that our unit price will be impacted by the level of our quarterly cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates may affect the yield requirements of investors who invest in our common units, and a rising interest rate environment could have a material adverse impact on our unit price and our ability to issue additional equity to make acquisitions or to incur debt as well as increasing our interest costs.
We may issue additional common units and other equity interests without your approval, which would dilute your existing ownership interests.
Under our partnership agreement, we are authorized to issue an unlimited number of additional interests without a vote of the unitholders. The issuance by us of additional common units or other equity interests of equal or senior rank will have the following effects:
| • | the proportionate ownership interest of unitholders immediately prior to the issuance will decrease; |
| • | the amount of cash distributions on each unit will decrease; |
| • | the ratio of our taxable income to distributions may increase; |
| • | the relative voting strength of each previously outstanding unit will be diminished; and |
| • | the market price of the common units may decline. |
In addition, our partnership agreement does not prohibit the issuance by our subsidiaries of equity interests, which may effectively rank senior to the common units.
Units eligible for future sale may cause the price of our common units to decline.
Sales of substantial amounts of our common units in the public market, or the perception that these sales may occur, could cause the market price of our common units to decline. This could also impair our ability to raise additional capital through the sale of our equity interests.
As of February 20, 2012, there were 73,030,936 common units outstanding. Of this amount, (i) 22,080,000 common units were sold to the public in our Initial Public Offering and are freely transferable without restriction or further registration under the Securities Act of 1933, or the Securities Act, by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act and (ii) CVR Energy, through Coffeyville Resources owns 50,920,000 common units, which may only be sold pursuant to a future registration statement or an exemption from registration such as Rule 144. On February 13, 2012, CVR Energy announced its intention to sell a portion of its common unit holdings in CVR Partners. There can be no assurance as to the terms, conditions, amount or timing of such offering, or whether such offering will take place at all. This announcement does not constitute an offer of any securities for sale and is being made pursuant to and in accordance with Rule 135 under the Securities Act.
Under our partnership agreement, our general partner and its affiliates (including Coffeyville Resources) have the right to cause us to register their units under the Securities Act and applicable state securities laws. We are also party to an amended and restated registration rights agreement with Coffeyville Resources pursuant to which we may be required to register the sale of the common units it holds.
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Tax Risks
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes, as well as our not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation, rather than as a partnership, for U.S. federal income tax purposes or if we were to become subject to additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders would be substantially reduced, likely causing a substantial reduction in the value of our common units.
The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for U.S. federal income tax purposes. From 2011, and in each taxable year thereafter, we are required to derive at least 90% of our annual gross income from specific activities to continue to be treated as a partnership, rather than as a corporation, for U.S. federal income tax purposes. We may not find it possible to meet this qualifying income requirement, or may inadvertently fail to meet this qualifying income requirement.
Although we do not believe based upon our current operations that we are treated as a corporation for U.S. federal income tax purposes, a change in our business or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. We may in the future enter into new activities or businesses. If our legal counsel were to be unable to opine that gross income from any such activity or business will count toward satisfaction of the 90% gross income, or qualifying income, requirement to be treated as a partnership for U.S. federal income tax purposes, we could seek a ruling from the IRS that gross income we earn from any such activity or business will be qualifying income. There can be no assurance, however, that the IRS would issue a favorable ruling under such circumstances. If we did not receive a favorable ruling, we could choose to engage in the activity or business through a corporate subsidiary, which would subject the income related to such activity or business to entity-level taxation. Except to the extent that we in the future request a ruling regarding the qualifying nature of our income from a particular activity or business, we do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us.
If we were treated as a corporation, rather than as a partnership, for U.S. federal income tax purposes, we would pay U.S. federal income tax on all of our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay additional state and local income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation, rather than as a partnership, for U.S. federal income tax purposes would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.
The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislation or judicial or administrative ruling or interpretation at any time. Current law may change to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity-level taxation. The current administration and, members of Congress have recently considered substantive changes to the existing U.S. federal income tax laws that would, adversely affect the tax treatment of publicly traded partnerships. Any modification to the U.S. federal income tax laws or interpretations thereof may or may not be applied retroactively and could make it more difficult or impossible for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax
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purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could cause a substantial reduction in the value of our common units.
At the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Specifically, we are required to pay Texas franchise tax each year at a maximum effective rate of 0.7% of our gross income apportioned to Texas in the prior year. Imposition of this or a similar tax by Texas and, if applicable, by any other state in which we do business will reduce our cash available for distribution to our unitholders. Although the considered legislation would not appear to affect our treatment as a partnership for U.S. federal income tax purposes, we are unable to predict whether any of these changes, or other proposals will ultimately be enacted. Any such changes could cause a substantial reduction in the value of our common units.
If the IRS contests the U.S. federal income tax positions we take, the market for our common units may be materially and adversely impacted, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.
Except to the extent that we, in the future, request a ruling regarding the qualifying nature of our income, we have not and do not intend to request a ruling from the IRS with respect to our treatment as a partnership for U.S. federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take, and the IRS’s positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders because the costs will reduce our cash available for distribution.
A unitholder’s share of our income is taxable for U.S. federal income tax purposes even if the unitholder does not receive any cash distributions from us.
Our unitholders are treated as partners to whom we allocate taxable income that could be different in amount than the cash we distribute. A unitholder’s allocable share of our taxable income is taxable to the unitholder, which may require the payment of U.S. federal income taxes and, in some cases, state and local income taxes on the unitholder’s share of our taxable income, even if no cash distributions are received from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our common units could be more or less than expected.
If our unitholders sell common units, they will recognize a gain or loss for U.S. federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units our unitholders sell will, in effect, become taxable income to our unitholders if they sell such common units at a price greater than their tax basis in those common units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if our unitholders sell common units, they may incur a tax liability in excess of the amount of cash the unitholders receive from the sale.
Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.
Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons, raises issues unique to them. For example, virtually
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all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income.
We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.
Due to our inability to match transferors and transferees of common units, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations promulgated under the Internal Revenue Code, referred to as “Treasury Regulations.” A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could cause a substantial reduction in the value of our common units or result in audit adjustments to our unitholders’ tax returns.
We prorate our items of income, gain, loss and deduction, for U.S. federal income tax purposes, between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of our common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued requiring a change, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Counsel has not rendered an opinion to us with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations.
A unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of those common units. If so, the unitholder would no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.
Because a unitholder whose common units are loaned to a “short seller” to cover a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for U.S. federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the common unitholder as to those common units could be fully taxable as ordinary income.
The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for U.S. federal income tax purposes.
We will be considered to have technically terminated for U.S. federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same common unit will
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be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than one year of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for U.S. federal income tax purposes, but instead, we would be treated as a new partnership for such tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby a publicly traded partnership that has technically terminated may request special relief that, if granted, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.
Unitholders are likely to be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.
In addition to U.S. federal income taxes, unitholders are likely to be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or control property now or in the future, even if they do not live in any of those jurisdictions. Unitholders are likely required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and conduct business in Kansas, Missouri, Nebraska and Texas. Kansas, Missouri and Nebraska currently impose a personal income tax on individuals. Kansas, Missouri and Nebraska also impose an income tax on corporations and other entities. Texas currently imposes a franchise tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax. It is the responsibility of each unitholder to file all U.S. federal, state, local and non-U.S. tax returns.
| Item 1B. | Unresolved Staff Comments |
None.
| Item 2. | Properties |
We own one facility, our 60-acre nitrogen fertilizer plant, which is located in Coffeyville, Kansas. Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas, with administrative office in Kansas City, Kansas. The offices in Sugar Land and Kansas City are leased by a subsidiary of CVR Energy and we pay a pro rata share of the rent on those offices. We believe that our owned facility, together with CVR Energy’s leased facilities, will be sufficient for our needs over the next twelve months.
We have entered into a cross-easement agreement with CVR Energy so that both we and CVR Energy are able to access and utilize each other’s land in certain circumstances in order to operate our respective businesses in a manner to provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party’s property. For more information on this cross-easement agreement, see “Certain Relationships and Related Transactions and Director Independence.”
In October 2011, the board of directors of our general partner approved a UAN terminal project, which will include the construction of a two million gallon UAN storage tank and related truck and rail car load-out facilities, to enable us to distribute up to approximately 20,000 tons of UAN fertilizer annually. The property that this terminal will be constructed on is located in Phillipsburg, Kansas and is owned by a subsidiary of CVR Energy who will also operate the terminal.
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| Item 3. | Legal Proceedings |
We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business. We are not party to any pending legal proceedings that we believe will have a material adverse effect on our business, and there are no existing legal proceedings where we believe that the reasonably possible loss or range of loss is material.
CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF’s annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county’s classification of its nitrogen fertilizer plant and has been disputing it before the Kansas Court of Tax Appeals, or COTA. However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008, and has fully accrued such amounts for the year ended December 31, 2011. The first payment in respect of CRNF’s 2011 property taxes was paid in December 2011 and the second payment will be made in May 2012. This property tax expense is reflected as a direct operating expense in our financial results. In January 2012 COTA issued a ruling indicating that the assessment in 2008 of CRNF’s fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling and filed a petition for reconsideration with COTA (which was denied) and plans to file an appeal to the Kansas Court of Appeals. CRNF is also protesting the valuation of the CRNF fertilizer plant for tax years 2009 through 2011, which cases remain pending before COTA. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on our results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then CRNF expects that it will continue to pay property taxes at elevated rates.
| Item 4. | Mine Safety Disclosures. |
Not applicable.
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PART II
Item 5. Market For Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Use of Proceeds from Initial Public Offering
On April 13, 2011, we completed the Initial Public Offering, pursuant to which 22,080,000 common units, representing approximately 30% of the limited partner interests in the Partnership, were sold to the public at a price of $16.00 per common unit. The net proceeds to CVR Partners from the Initial Public Offering were approximately $324.2 million, after deducting underwriting discounts and commissions and offering expenses. Approximately $104.0 million of the net proceeds were to be used to fund the approximately $135.0 million UAN expansion, of which approximately $43.6 million had been spent as of December 31, 2011.
Market Information
Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “UAN” and commenced trading on April 8, 2011. The table below sets forth, for the quarter indicated, the high and low sales prices per share of our common units:
| 2011: |
High | Low | ||||||
| Second Quarter |
$ | 23.37 | $ | 16.75 | ||||
| Third Quarter |
27.75 | 19.47 | ||||||
| Fourth Quarter |
26.49 | 18.66 | ||||||
There were 9 holders of record of UAN common units as of February 17, 2012.
Cash Distribution Policy
Our general partner’s current policy is to distribute all of the available cash we generate each quarter. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. We do not maintain excess distribution coverage for the purpose of maintaining stability or growth in our quarterly distribution or otherwise to reserve cash for distributions, nor do we intend to incur debt to pay quarterly distributions. We expect to finance substantially all of our growth externally, either by debt issuances or additional issuances of equity.
Because our policy is to distribute all available cash we generate each quarter, without reserving cash for future distributions or borrowing to pay distributions during periods of low cash flow from operations, our unitholders have direct exposure to fluctuations in the amount of cash generated by our business. We expect that the amount of our quarterly distributions, if any, will vary based on our operating cash flow during each quarter. Our quarterly cash distributions, if any, will not be stable and will vary from quarter to quarter as a direct result of variations in our operating performance and cash flow caused by fluctuations in the price of nitrogen fertilizers as well as forward and prepaid sales; see “Business – Distribution, Sales and Marketing.” Such variations may be significant. The board of directors of our general partner may change the foregoing distribution policy at any time and from time to time. Our partnership agreement does not require us to pay cash distributions on a quarterly or other basis.
From time to time, we make prepaid sales, whereby we receive cash during one quarter in respect of product to be produced and sold in a future quarter, but we do not record revenue in respect of the cash received until the quarter when product is delivered.
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We intend to pay our distributions on or about the 15th day of each February, May, August and November to holders of record on or about the 1st day of each such month.
On August 12, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on August 5, 2011 for the second quarter of 2011 in the amount of $0.407 per unit, or $29.7 million in aggregate.
On November 14, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on November 7, 2011 for the third quarter of 2011 in the amount of $0.572 per unit, or $41.8 million in aggregate.
On February 14, 2012, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on February 7, 2012 four the fourth quarter of 2011 in the amount of $0.588 per unit, or $42.9 million in aggregate.
The Partnership did not make quarterly distributions to unitholders prior to the closing of our initial public offering on April 13, 2012.
CVR Partners, LP, Long-Term Incentive Plan (“CVR Partners LTIP”)
In connection with the Offering, the board of directors of the general partner adopted the CVR Partners, LP Long-Term Incentive Plan, or CVR Partners LTIP . Individuals who are eligible to receive awards under the CVR Partners LTIP include employees, officers, consultants and directors of CVR Partners and the general partner and their respective subsidiaries and parents. The CVR Partners LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. A maximum of 5,000,000 common units are issuable under the CVR Partners LTIP.
Equity Compensation Plan
The table below contains information about securities authorized for issuance under our CVR Partners LTIP as of December 31, 2011. The CVR Partners LTIP was approved by the board of directors of our general partner in March 2011.
| Equity Compensation Plan Information |
||||||||||||
| Plan Category |
Number of Securities to be Issued Upon Vesting |
Weighted-Average Exercise Price of Outstanding Securities |
Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in (a) (c)) |
|||||||||
| Equity compensation plans approved by security holders: |
||||||||||||
| CVR Partners, LP Long- Term Incentive Plan |
164,571 | (1) | — | (2) | 4,799,353 | (3) | ||||||
| Equity compensation plans not approved by security holders: |
||||||||||||
| None |
— | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
164,571 | — | 4,799,353 | |||||||||
|
|
|
|
|
|
|
|||||||
| (1) | Represents common and phantom units awarded under the CVR Partners LTIP. |
| (2) | Units do not have an exercise price. Payout is based on completing a specified period of employment. |
| (3) | Represents units that remain available for future issuance pursuant to the CVR Partners LTIP in connection with awards of options, unit appreciation rights, distribution equivalent rights, restricted units and phantom units. As of December 31, 2011, 200,647 non-vested common and phantom units had been granted under the CVR Partners LTIP, of which no common or phantom units have been forfeited and 164,571 remain unvested. |
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Purchases of Equity Securities by the Issuer
The table below sets forth information regarding repurchases of our common units during the fiscal quarter ended December 31, 2011. These represent common units that employees and directors elected to surrender to the Company to satisfy certain minimum tax withholding and other tax obligations upon the vesting of units. The Company does not consider this to be a unit buyback program.
| Period |
Total Number of Units Purchased |
Average Price Paid per Units |
Total Number of
Units Purchased as Part of Publicly Announced Plans or Programs |
Maximum Number
(or Approximate Dollar Value) of Units that May Yet Be Purchased Under the Plans or Programs |
||||||||||||
| October 1, 2011 to October 31, 2011 |
4,412 | $ | 23.30 | — | — | |||||||||||
| November 1, 2011 to November 30, 2011 |
— | — | — | — | ||||||||||||
| December 1, 2011 to December 31, 2011 |
728 | $ | 24.82 | — | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total |
5,140 | $ | 23.52 | — | — | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
Item 6. Selected Financial Data
This data should be read in conjunction with, and is qualified in its entirety by reference to, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the consolidated financial statements and related notes included elsewhere in this Report.
The selected consolidated financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2011, 2010 and 2009 and the selected consolidated financial information presented below under the caption Balance Sheet Data as of December 31, 2011 and 2010, has been derived from our audited consolidated financial statements included elsewhere in this Report, which consolidated financial statements have been audited by KPMG LLP, independent registered public accounting firm. The selected consolidated financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2008 and 2007 and the selected consolidated financial information presented below under the caption Balance Sheet Data as of December 31, 2009, 2008 and 2007 have been derived from our audited consolidated financial statements that are not included in this Report.
The following schedules show our selected financial and operating data for the periods indicated, which are derived from our consolidated financial statements. On April 13, 2011, we completed our initial public offering of 22,080,000 common units. A portion of our fiscal year 2011 results prior to our initial public offering are included in the total 2011 results presented herein. The Partnership has omitted net income per unit for all periods other than the twelve months ended December 31, 2011, as the Partnership operated under a different capital structure prior to the closing of the Partnership’s initial public offering and, as a result, the per unit data would not be meaningful to investors. Per unit data for the twelve months ending December 31, 2011 is calculated since the closing of the Partnership’s initial public offering on April 13, 2011.
Our consolidated financial statements include certain costs of CVR Energy that were incurred on our behalf. These costs, which are reflected in selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization), are billed to us pursuant to a services agreement entered into in October 2007 that is a related party transaction. For the period of time prior to the services agreement, the consolidated financial statements include an allocation of costs and certain other amounts in order to account for a reasonable share of expenses, so that the accompanying
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consolidated financial statements reflect substantially all of our costs of doing business. The amounts charged or allocated to us are not necessarily indicative of the costs that we would have incurred had we operated as a stand-alone company for all periods presented.
| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
|
(dollars in millions, except per unit data and as otherwise indicated) |
||||||||||||||||||||
| Statement of Operations Data: |
||||||||||||||||||||
| Net sales(1) |
$ | 302.9 | $ | 180.5 | $ | 208.4 | $ | 263.0 | $ | 187.4 | ||||||||||
| Cost of product sold — Affiliates(2) |
11.7 | 5.8 | 9.5 | 11.1 | 4.5 | |||||||||||||||
| Cost of product sold — Third parties(2) |
30.8 | 28.5 | 32.7 | 21.5 | 28.6 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 42.5 | 34.3 | 42.2 | 32.6 | 33.1 | ||||||||||||||||
| Direct operating expenses — Affiliates(2)(3) |
1.2 | 2.3 | 2.1 | 0.4 | 2.2 | |||||||||||||||
| Direct operating expenses — Third parties(2) |
85.3 | 84.4 | 82.4 | 85.7 | 64.5 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 86.5 | 86.7 | 84.5 | 86.1 | 66.7 | ||||||||||||||||
| Insurance recovery – business interruption |
(3.4 | ) | — | — | — | — | ||||||||||||||
| Selling, general and administrative expenses — Affiliate (2)(3) |
16.5 | 16.7 | 12.3 | 1.1 | 18.1 | |||||||||||||||
| Selling, general and administrative expenses — Third parties(2) |
5.7 | 3.9 | 1.8 | 8.4 | 2.3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| 22.2 | 20.6 | 14.1 | 9.5 | 20.4 | ||||||||||||||||
| Net costs associated with flood(4) |
— | — | — | — | 2.4 | |||||||||||||||
| Depreciation and amortization(5) |
18.9 | 18.5 | 18.7 | 18.0 | 16.8 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Operating income |
$ | 136.2 | $ | 20.4 | $ | 48.9 | $ | 116.8 | $ | 48.0 | ||||||||||
| Interest expense and other financing costs |
(4.0 | ) | — | — | — | (23.6 | ) | |||||||||||||
| Interest income(6) |
— | 13.1 | 9.0 | 2.0 | 0.3 | |||||||||||||||
| Other income (expense), net(7) |
0.2 | (0.2 | ) | — | 0.1 | (0.1 | ) | |||||||||||||
| Loss on derivatives, net |
— | — | — | — | (0.5 | ) | ||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Income before income taxes |
$ | 132.4 | $ | 33.3 | $ | 57.9 | $ | 118.9 | $ | 24.1 | ||||||||||
| Income tax expense |
— | — | — | — | — | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Net income |
$ | 132.4 | $ | 33.3 | $ | 57.9 | $ | 118.9 | $ | 24.1 | ||||||||||
| Available cash for distribution(8) |
$ | 114.4 | — | — | — | — | ||||||||||||||
| Net income per common unit – basic(9) |
$ | 1.48 | — | — | — | — | ||||||||||||||
| Net income per common unit – diluted(9) |
$ | 1.48 | — | — | — | — | ||||||||||||||
| Weighted-average common units outstanding: |
||||||||||||||||||||
| Basic |
73,008 | — | — | — | — | |||||||||||||||
| Diluted |
73,073 | — | — | — | — | |||||||||||||||
| As of December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| (dollars in millions) | ||||||||||||||||||||
| Balance Sheet Data: |
||||||||||||||||||||
| Cash and cash equivalents |
$ | 237.0 | $ | 42.7 | $ | 5.4 | $ | 9.1 | $ | 14.5 | ||||||||||
| Working capital |
229.4 | 27.1 | 135.5 | 60.4 | 7.5 | |||||||||||||||
| Total assets |
659.3 | 452.2 | 551.5 | 499.9 | 429.9 | |||||||||||||||
| Total debt, including current portion |
125.0 | — | — | — | — | |||||||||||||||
| Partners capital |
489.5 | 402.2 | 519.9 | 458.8 | 400.5 | |||||||||||||||
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| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| Cash Flow and Other Data: |
||||||||||||||||||||
| Net cash flow provided by (used in): |
||||||||||||||||||||
| Operating activities |
$ | 139.8 | $ | 75.9 | $ | 85.5 | $ | 123.5 | $ | 46.5 | ||||||||||
| Investing activities |
(16.4 | ) | (9.0 | ) | (13.4 | ) | (23.5 | ) | (6.5 | ) | ||||||||||
| Financing activities |
70.8 | (29.6 | ) | (75.8 | ) | (105.3 | ) | (25.5 | ) | |||||||||||
| Capital expenditures for property, plant and equipment |
19.1 | 10.1 | 13.4 | 23.5 | 6.5 | |||||||||||||||
| Depreciation and amortization |
18.9 | 18.5 | 18.7 | 18.0 | 16.8 | |||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| Key Operating Data: |
||||||||||||||||||||
| Production volume (thousand tons): |
||||||||||||||||||||
| Ammonia (gross produced)(10) |
411.2 | 392.7 | 435.2 | 359.1 | 326.7 | |||||||||||||||
| Ammonia (net available for sale)(10) |
116.8 | 155.6 | 156.6 | 112.5 | 91.8 | |||||||||||||||
| UAN (tons in thousands) |
714.1 | 578.3 | 677.7 | 599.2 | 576.9 | |||||||||||||||
| Pet coke consumed (thousand tons) |
517.3 | 436.3 | 483.5 | 451.9 | 449.8 | |||||||||||||||
| Pet coke (cost per ton) |
$ | 33 | $ | 17 | $ | 27 | $ | 31 | $ | 30 | ||||||||||
| Sales (thousand tons): |
||||||||||||||||||||
| Ammonia |
112.8 | 164.7 | 159.9 | 99.4 | 92.1 | |||||||||||||||
| UAN |
709.3 | 580.7 | 686.0 | 594.2 | 555.4 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total sales |
822.1 | 745.4 | 845.9 | 693.6 | 647.5 | |||||||||||||||
| Product pricing (plant gate) (dollars per ton)(11): |
||||||||||||||||||||
| Ammonia |
579 | 361 | 314 | 557 | 376 | |||||||||||||||
| UAN |
284 | 179 | 198 | 303 | 211 | |||||||||||||||
| On-stream factors(12): |
||||||||||||||||||||
| Gasifier |
99.0 | % | 89.0 | % | 97.4 | % | 87.8 | % | 90.0 | % | ||||||||||
| Ammonia |
97.7 | % | 87.7 | % | 96.5 | % | 86.2 | % | 87.7 | % | ||||||||||
| UAN |
95.5 | % | 80.8 | % | 94.1 | % | 83.4 | % | 78.7 | % | ||||||||||
| Reconciliation to net sales (in millions): |
||||||||||||||||||||
| Freight in revenue |
22.1 | 17.0 | 21.3 | 18.9 | 13.9 | |||||||||||||||
| Hydrogen and other gases revenue |
14.2 | 0.1 | 0.8 | 9.0 | — | |||||||||||||||
| Sales net plant gate |
266.6 | 163.4 | 186.3 | 235.1 | 152.0 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total net sales |
302.9 | 180.5 | 208.4 | 263.0 | 165.9 | |||||||||||||||
| Market Indicators: |
||||||||||||||||||||
| Natural gas NYMEX (dollars per MMBtu) |
4.03 | 4.38 | 4.16 | 8.91 | 7.12 | |||||||||||||||
| Ammonia — Southern Plans (dollars per ton) |
619 | 437 | 306 | 707 | 409 | |||||||||||||||
| UAN — Mid Corn belt (dollars per ton) |
379 | 266 | 218 | 422 | 288 | |||||||||||||||
| (1) | Below are the components of Net sales: |
| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| Reconciliation to net sales (in millions): |
||||||||||||||||||||
| Sales net plant gate |
$ | 266.6 | $ | 163.4 | $ | 186.3 | $ | 235.1 | $ | 155.3 | ||||||||||
| Freight in revenue |
22.1 | 17.0 | 21.3 | 18.9 | 17.8 | |||||||||||||||
| Hydrogen and other gases revenue |
14.2 | 0.1 | 0.8 | 9.0 | 14.3 | |||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|||||||||||
| Total net sales |
$ | 302.9 | $ | 180.5 | $ | 208.4 | $ | 263.0 | $ | 187.4 | ||||||||||
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| (2) | Amounts are shown exclusive of depreciation and amortization. |
| (3) | Our direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization) for the years ended December 31, 2011, 2010, 2009, 2008 and 2007 include a charge related to CVR Energy’s share-based compensation expense allocated to us by CVR Energy for financial reporting purposes in accordance with ASC 718. These charges will continue to be attributed to us. We are not responsible for the payment of cash related to any share-based compensation allocated to us by CVR Energy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Share-Based Compensation.” The amounts were: |
| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) |
$ | 0.5 | $ | 0.7 | $ | 0.2 | $ | (1.6 | ) | $ | 1.2 | |||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) |
6.8 | 8.3 | 3.0 | (9.0 | ) | 9.7 | ||||||||||||||
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| Total |
$ | 7.3 | $ | 9.0 | $ | 3.2 | $ | (10.6 | ) | $ | 10.9 | |||||||||
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| (4) | Total gross costs recorded as a result of the flood damage to our nitrogen fertilizer plant for the year ended December 31, 2007 were approximately $5.8 million, including approximately $0.8 million recorded for depreciation for temporarily idle facilities, $0.7 million for internal salaries and $4.3 million for other repairs and related costs. An insurance receivable of approximately $3.3 million was also recorded for the year December 31, 2007 for the probable recovery of such costs under CVR Energy’s insurance policies. |
| (5) | Depreciation and amortization is comprised of the following components as excluded from direct operating expenses and selling, general and administrative expenses and as included in net costs associated with flood: |
| Year Ended December 31, | ||||||||||||||||||||
| 2011 | 2010 | 2009 | 2008 | 2007 | ||||||||||||||||
| (in millions) | ||||||||||||||||||||
| Depreciation and amortization excluded from direct operating expenses |
$ | 18.8 | $ | 18.5 | $ | 18.7 | $ | 18.0 | $ | 16.8 | ||||||||||
| Depreciation and amortization excluded from cost of product sold |
0.1 | — | — | — | — | |||||||||||||||
| Depreciation included in net costs associated with flood |
— | — | — | — | 0.8 | |||||||||||||||
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| Total depreciation and amortization |
$ | 18.9 | $ | 18.5 | $ | 18.7 | $ | 18.0 | $ | 17.6 | ||||||||||
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| (6) | Interest income for the years ended December 31, 2010, 2009 and 2008 is primarily attributable to a due from affiliate balance owed to us by Coffeyville Resources as a result of affiliate loans. The due from affiliate balance was distributed to Coffeyville Resources in December 2010. Accordingly, such amounts are no longer owed to us. |
| (7) | Includes loss on extinguishment of debt for the year December 31, 2007. |
| (8) | We define available cash for distribution generally as equal to our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that our board of directors of our general partner deems necessary or appropriate. For the year ended December 31, 2011, available cash for distribution is calculated for the period beginning at the closing of our Initial Public Offering (April 13, 2011) through December 31, 2011. The Partnership also retains the cash on hand associated with prepaid sales at each quarter end for future distribution to common unitholders based upon the recognition into income of the prepaid sales as product is delivered. |
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| (9) | We have omitted earnings per share through the date CRNF, our operating subsidiary, was contributed to us because during those periods we operated under a divisional equity structure. We have omitted net income per unitholder during the period we operated as a partnership through the closing of our Initial Public Offering because during those periods we operated under a different capital structure than what we are operating under following the closing of our Initial Public Offering, and, therefore, the information is not meaningful. Per unit data for the twelve months ending December 31, 2011 is calculated for the period beginning at the closing of our Initial Public Offering (April 13, 2011) through December 31, 2011. |
| (10) | The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN. |
| (11) | Plant gate sales per ton represent net sales less freight and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate pricing per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. |
| (12) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of the Linde air separation unit outage, the on-stream factors for the year ended December 31, 2011 was 99.2% for gasifier, 98.0% for ammonia and 95.7% for UAN. Excluding the impact of the Linde air separation unit outage, the rupture of the high-pressure UAN vessel and the major scheduled turnaround, the on-stream factors for the year ended December 31, 2010 would have been 97.6% for gasifier, 96.8% for ammonia and 96.1% for UAN. Excluding the Linde air separation unit outage in 2009, the on-stream factors would have been 99.3% for gasifier, 98.4% for ammonia and 96.1% for UAN for the year ended December 31, 2009. Excluding the turnaround performed in 2008, the on-stream factors would have been 91.7% for gasifier, 90.2% for ammonia and 87.4% for UAN for the year ended December 31, 2008. Excluding the impact of the flood in 2007, the on-stream factors would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN for the year ended December 31, 2007. |
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
You should read the following discussion and analysis of our financial condition, results of operations and cash flows in conjunction with our consolidated financial statements and related notes included elsewhere in this Report.
Forward-Looking Statements
This Annual Report on Form 10-K, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains “forward-looking statements” as defined by the SEC. Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:
| • | statements, other than statements of historical fact, that address activities, events or developments that we expect, believe or anticipate will or may occur in the future; |
| • | statements relating to future financial performance, future capital sources and other matters; and |
| • | any other statements preceded by, followed by or that include the words “anticipates,” “believes,” “expects,” “plans,” “intends,” “estimates,” “projects,” “could,” “should,” “may,” or similar expressions. |
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Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K, including this Management’s Discussion and Analysis of Financial Condition and Results of Operations, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under the section captioned “Risk Factors” and contained elsewhere in this report. Such factors include, among others:
| • | our ability to make cash distributions on the units; |
| • | the volatile nature of our business and the variable nature of our distributions; |
| • | the ability of our general partner to modify or revoke our distribution policy at any time; |
| • | the cyclical nature of our business; |
| • | adverse weather conditions, including potential floods and other natural disasters; |
| • | the seasonal nature of our business; |
| • | the dependence of our operations on a few third-party suppliers, including providers of transportation services and equipment; |
| • | our reliance on pet coke that we purchase from CVR Energy; |
| • | the supply and price levels of essential raw materials; |
| • | the risk of a material decline in production at our nitrogen fertilizer plant; |
| • | potential operating hazards from accidents, fire, severe weather, floods or other natural disasters; |
| • | the risk associated with governmental policies affecting the agricultural industry; |
| • | competition in the nitrogen fertilizer businesses; |
| • | capital expenditures and potential liabilities arising from environmental laws and regulations; |
| • | existing and proposed environmental laws and regulations, including those relating to climate change, alternative energy or fuel sources, and on the end-use and application of fertilizers; |
| • | new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities; |
| • | our lack of asset diversification; |
| • | our dependence on significant customers; |
| • | the potential loss of our transportation cost advantage over our competitors; |
| • | our potential inability to successfully implement our business strategies, including the completion of significant capital programs; |
| • | our reliance on CVR Energy’s senior management team and conflicts of interest they face operating both us and CVR Energy; |
| • | risks relating to evaluations of internal controls required by Section 404 of the Sarbanes-Oxley Act; |
| • | risks relating to our relationships with CVR Energy; |
| • | control of our general partner by CVR Energy; |
| • | our ability to continue to license the technology used in our operations; |
| • | restrictions in our debt agreements; |
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| • | our limited operating history as a stand-alone company; |
| • | changes in our treatment as a partnership for U.S. income or state tax purposes; and |
| • | instability and volatility in the capital and credit markets. |
All forward-looking statements contained in this Form 10-K speak only as of the date of this document. We undertake no obligation to publicly update or revise any forward-looking statements to reflect events or circumstances that occur after the date of this Form 10-K, or to reflect the occurrence of unanticipated events.
Overview and Executive Summary
We are a Delaware limited partnership formed by CVR Energy to own, operate and grow our nitrogen fertilizer business. Strategically located adjacent to CVR Energy’s refinery in Coffeyville, Kansas, our nitrogen fertilizer manufacturing facility is the only operation in North America that utilizes a petroleum coke, or pet coke, gasification process to produce nitrogen fertilizer.
We produce and distribute nitrogen fertilizer products, which are used primarily by farmers to improve the yield and quality of their crops. Our principal products are ammonia and UAN. These products are manufactured at our facility in Coffeyville, Kansas. Our product sales are heavily weighted toward UAN and all of our products are sold on a wholesale basis.
Our 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. Our gasifier is a dual-train facility, with each gasifier able to function independently of the other, thereby providing redundancy and improving our reliability. We upgrade a majority of the ammonia we produce to higher margin UAN fertilizer, an aqueous solution of urea and ammonium nitrate which has historically commanded a premium price over ammonia. In 2011, we produced 411,189 tons of ammonia, of which approximately 72% was upgraded into 714,130 tons of UAN.
We are expanding our existing asset base and utilizing the experience of our and CVR Energy’s management teams to execute our growth strategy, which includes expanding production of UAN and acquiring and building additional infrastructure and production assets. A significant two-year plant expansion designed to increase our UAN production capacity by 400,000 tons, or approximately 50%, per year, is underway. CVR Energy, a New York Stock Exchange listed company, which indirectly owns our general partner and approximately 70.0% of our outstanding common units, currently operates a 115,000 bpd oil refinery in Coffeyville, Kansas, a 70,000 bpd oil refinery in Wynnewood, Oklahoma, and ancillary businesses. On February 13, 2012, CVR Energy announced its intention to sell a portion of its common unit holdings in CVR Partners. There can be no assurance as to the terms, conditions, amount or timing of such offering, or whether such offering will take place at all. This announcement does not constitute an offer of any securities for sale and is being made pursuant to and in accordance with Rule 135 under the Securities Act.
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 our nitrogen fertilizer competitors use natural gas as their primary raw material feedstock. Historically, pet coke has been less expensive than natural gas on a per ton of fertilizer produced basis and pet coke prices have been more stable when compared to natural gas prices. By using pet coke as the primary raw material feedstock instead of natural gas, we believe our nitrogen fertilizer business has historically been one of the lower cost producers and marketers of ammonia and UAN fertilizers in North America. We currently purchase most of our pet coke from CVR Energy 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 consumed by our plant was produced and supplied by CVR Energy’s Coffeyville, Kansas crude oil refinery.
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Our History
We were formed by CVR Energy in June 2007 in order to hold its nitrogen fertilizer business in a structure that might be separately financed in the future as a limited partnership. In October 2007, in consideration for CVR Energy contributing nitrogen fertilizer business to us, CVR Special GP, LLC, a subsidiary of CVR Energy, acquired 30,303,000 special GP units and CVR GP, a subsidiary of CVR Energy at that time, acquired the general partner interest and the Partnership’s Incentive Distribution Rights (IDRs), CVR Energy concurrently sold our general partner, together with the IDRs to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by funds affiliated with Goldman Sachs & Co, Kelso & Company, L.P. and certain members of CVR Energy’s senior management team, for its fair market value on the date of sale.
Our Initial Public Offering
On April 13, 2011, we completed our Initial Public Offering of 22,080,000 common units priced at $16.00 per unit. The net proceeds to us from the Initial Public Offering were approximately $324.2 million, after deducting underwriting discounts and commissions and offering expenses. The net proceeds from our Initial Public Offering were used as follows: approximately $18.4 million was used to make a distribution to CRLLC in satisfaction of the Partnership’s obligation to reimburse CRLLC for certain capital expenditures it made on our behalf; approximately $117.1 million was used to make a special distribution to CRLLC in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of our Initial Public Offering; approximately $26.0 million was used to purchase (and subsequently extinguish) the IDRs owned by our general partner; approximately $4.8 million was used to pay financing fees and associated legal and professional fees resulting from our credit facility; and the balance was used for or will be used for general partnership purposes, including approximately $104.0 million to fund the expected capital costs of the continuation of our $135.0 million UAN expansion. As of December 31, 2011, approximately $43.6 million had been spent on this UAN expansion.
Major Influences on Results of Operations
Our earnings and cash flows from operations are primarily affected by the relationship between nitrogen fertilizer product prices, on-stream factors and direct operating expenses. Unlike our competitors, we do not use natural gas as a feedstock and use a minimal amount of natural gas as an energy source in our operations. As a result, volatile swings in natural gas prices have a minimal impact on our results of operations. Instead, CVR Energy’s adjacent refinery supplies us with most of the pet coke feedstock we need pursuant to a long-term pet coke supply agreement entered into in October 2007. The price at which our products are ultimately sold depends on numerous factors, including the global supply and demand for nitrogen fertilizer products which, in turn, depends on, among other factors, world grain demand and production levels, changes in world population, the cost and availability of fertilizer transportation infrastructure, weather conditions, the availability of imports, and the extent of government intervention in agriculture markets.
Nitrogen fertilizer prices are also affected by local factors, including local market conditions and the operating levels of competing facilities. An expansion or upgrade of competitors’ facilities, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.
In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.
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Natural gas is the most significant raw material required in our competitors’ production of nitrogen fertilizers. Over the past several years, natural gas prices have experienced high levels of price volatility although natural gas prices are currently substantially lower than historical highs. This pricing and volatility has a direct impact on our competitors’ cost of producing nitrogen fertilizer.
In order to assess our operating performance, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs.
We and other competitors in the U.S. farm belt share a significant transportation cost advantage when compared to our out-of-region competitors in serving the U.S. farm belt agricultural market. In 2011, approximately 56% of the corn planted in the United States was grown within a $40/UAN ton freight train rate of the nitrogen fertilizer plant. We are therefore able to cost-effectively sell substantially all of our products in the higher margin agricultural market, whereas a significant portion of our competitors’ revenues is derived from the lower margin industrial market. Our location on Union Pacific’s main line increases our transportation cost advantage by lowering the costs of bringing our products to customers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Our products leave the plant either in trucks for direct shipment to customers or in railcars for destinations located principally on the Union Pacific Railroad and we do not currently incur any intermediate transfer, storage, barge freight or pipeline freight charges. We estimate that our plant enjoys a transportation cost advantage of approximately $25 per ton over competitors located in the U.S. Gulf Coast. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.
The value of nitrogen fertilizer products is also an important consideration in understanding our results. For the year ended December 31, 2011, we upgraded approximately 72% of our ammonia production into UAN, a product that presently generates greater profit than ammonia. During 2010, we upgraded approximately 60% of our ammonia production into UAN. UAN production is a major contributor to our profitability.
The high fixed cost of our direct operating expense structure also directly affects our profitability. Our facility’s pet coke gasification process results in a significantly higher percentage of fixed costs than a natural gas-based fertilizer plant. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These fixed costs averaged approximately 87% of direct operating expenses over the 24 months ended December 31, 2011.
Our largest raw material expense is pet coke, which we purchase from CVR Energy and third parties. For the years ended December 31, 2011, 2010 and 2009, we spent approximately $16.8 million, $7.4 million and $12.8 million, respectively, for pet coke, which equaled an average cost per ton of $33, $17 and $27, respectively.
Consistent, safe, and reliable operations at our nitrogen fertilizer plant are critical to our financial performance and results of operations. Unplanned downtime of the plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. The nitrogen fertilizer plant generally undergoes a facility turnaround every two years. The turnaround typically lasts 13-15 days each turnaround year and costs approximately $3 million to $5 million per turnaround. The nitrogen fertilizer plant underwent a turnaround in the fourth quarter of 2010, at a cost of approximately $3.5 million. The next turnaround is currently scheduled for the fourth quarter of 2012. In connection with the most recent biennial turnaround, the nitrogen fertilizer business also wrote-off approximately $1.4 million of fixed assets.
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Agreements with CVR Energy
In connection with our formation and the initial public offering of CVR Energy in October 2007, we entered into several agreements with CVR Energy and its affiliates that govern the business relations among us, CVR Energy and its affiliates, and our general partner. In connection with our Initial Public Offering in April 2011, we amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Energy and its affiliates. These include the pet coke supply agreement under which we buy the pet coke we use in our nitrogen fertilizer plant; a services agreement, under which CVR Energy and its affiliates provide us with management services including the services of its senior management team; 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 from CVR Energy.
We obtain most (over 70% on average during the last five years) of the pet coke we need from CVR Energy pursuant to the pet coke supply agreement, and procure the remainder on the open market. The price we pay pursuant to the pet coke supply agreement is based on the lesser of a pet coke price derived from the price received by us for UAN, or the UAN-based price, and a pet coke price index. The UAN-based price begins with a pet coke price of $25 per ton based on a price per ton for UAN (exclusive of transportation cost), or netback price, of $205 per ton, and adjusts up or down $0.50 per ton for every $1.00 change in the netback price. The UAN-based price has a ceiling of $40 per ton and a floor of $5 per ton.
The services agreement, which became effective in October 2007, resulted in charges of approximately $8.2 million, $8.5 million and $9.3 million for the fiscal years ended December 31, 2011, 2010 and 2009, respectively (excluding share-based compensation), included in selling, general and administrative expenses (exclusive of depreciation and amortization) in our Consolidated Statements of Operations.
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.
Corporate Allocations
Our consolidated financial statements included elsewhere in this report include certain costs of CVR Energy that were incurred on our behalf. These costs, which are reflected in selling, general and administrative expenses (exclusive of depreciation and amortization) and direct operating expenses (exclusive of depreciation and amortization), are billed to us pursuant to a services agreement entered into in October 2007 (and amended and restated in April 2011) that is a related party transaction. For the period of time prior to the services agreement, the consolidated financial statements include an allocation of costs and certain other amounts in order to account for a reasonable share of expenses, so that the accompanying consolidated financial statements reflect substantially all of our costs of doing business.
Our financial statements reflect all of the expenses that Coffeyville Resources incurred on our behalf. Our financial statements therefore include certain expenses incurred by our parent which may include, but are not necessarily limited to, officer and employee salaries and share-based compensation, rent or depreciation, advertising, accounting, tax, legal and information technology services, other selling, general and administrative expenses, costs for defined contribution plans, medical and other employee benefits, and financing costs, including interest, marked-to-market changes in interest rate swap and losses on extinguishment of debt.
Selling, general and administrative expense allocations were based primarily on total fertilizer payroll as a percentage of the total fertilizer and petroleum segment payrolls. Property insurance costs were allocated based upon specific valuations.
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Publicly Traded Partnership Expenses
Our general and administrative expenses have increased due to the costs of operating as a publicly traded partnership, including costs associated with SEC reporting requirements, including annual and quarterly reports to unitholders, tax return and Schedule K-1 preparation and distribution, independent auditor fees, investor relations activities and registrar and transfer agent fees. We estimate that these incremental general and administrative expenses approximate $5.5 million per year, excluding the costs of the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing. Our financial statements do not reflect the impact of these expenses, except for the period subsequent to April 12, 2011, which affects the comparability of our post-Initial Public Offering results with our financial statements from periods prior to the completion of our Initial Public Offering.
September 2010 UAN Vessel Rupture
On September 30, 2010, our nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at our nitrogen fertilizer facility were immediately shut down. No one was injured in the incident.
Our nitrogen fertilizer facility had previously scheduled a major turnaround to begin on October 5, 2010. To minimize disruption and impact to the production schedule, the turnaround was accelerated. The turnaround was completed on October 29, 2010 with the gasification and ammonia units in operation. The fertilizer facility restarted production of UAN on November 16, 2010 and, as of December 31, 2010, repairs to the facility as a result of the rupture were substantially complete. In addition to adversely impacting UAN sales in the fourth quarter of 2010, the outage caused us to shift delivery of lower priced tons from the fourth quarter of 2010 to the first and second quarters of 2011.
Total gross costs recorded as of December 31, 2011 due to the incident were approximately $11.4 million for repairs and maintenance and other associated costs. As of December 31, 2011, approximately $7.0 million of insurance proceeds have been received related to the property damage insurance claim. Of the costs incurred, approximately $4.6 million were capitalized. We also recognized income of approximately $3.4 million during 2011 from insurance proceeds received related to our business interruption policy. Approximately $0.5 million was received during the third quarter, with the remainder received in March and April 2011.
2010 and 2008 Turnarounds
During the fourth quarter of each of 2010 and 2008, we completed planned turnarounds of the nitrogen fertilizer plant at a total cost of approximately $3.5 million and $3.3 million, respectively. The majority of these costs were expensed in the fourth quarter of each year. In connection with the nitrogen fertilizer plant’s biennial turnaround, we also expensed approximately $1.4 million and $2.3 million associated with fixed assets retired with the turnarounds for the years ended December 31, 2010 and 2008, respectively. No planned major turnaround activities occurred in 2011.
Fertilizer Plant Property Taxes
CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF’s annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county’s classification of its nitrogen fertilizer plant and is currently disputing it before the Kansas Court of Tax Appeals, or COTA.
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However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008, and has fully accrued such amounts for the year ended December 31, 2011. The first payment in respect of CRNF’s 2011 property taxes was paid in December 2011 and the second payment will be made in May 2012. This property tax expense is reflected as a direct operating expense in our financial results. In January 2012 COTA issued a ruling indicating that the assessment in 2008 of CRNF’s fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling and filed a petition for reconsideration with COTA (which was denied) and plans to file an appeal to the Kansas Court of Appeals. CRNF is also protesting the valuation of the CRNF fertilizer plant for tax years 2009 – 2011, which cases remain pending before COTA. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on our results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then CRNF expects that it will continue to pay property taxes at elevated rates.
Distributions to Unitholders
Our general partner’s current policy is to distribute all of the available cash we generate each quarter beginning with the quarter ended June 30, 2011. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. Additionally, the Partnership also retains the cash on hand associated with prepaid sales at each quarter end, which is recorded on the balance sheet as deferred revenue, for future distributions to common unitholders as it is recognized into income. The board of directors of our general partner may modify our cash distribution policy at any time, and our partnership agreement does not require us to make distributions at all.
Credit Facility
On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million which was undrawn as of December 31, 2011. There is no scheduled amortization and the credit facility matures in April 2016.
Borrowings under the credit facility bear interest, at the Partnership’s option, at either the Eurodollar Rate, plus a margin that ranges from 3.50% to 4.25%, or the Base Rate, plus a margin that ranges from 2.50% to 3.25%. The applicable interest rate margin is determined based on the Partnership’s leverage ratio for the trailing four quarters. The average interest rate for the term loan for the year ended December 31, 2011 was 4.72%. See Note 11 for more information regarding the credit facility. In periods prior to the Initial Public Offering, we did not incur interest expense.
Interest Rate Swap
Our profitability and cash flows are affected by changes in interest rates on our credit facility borrowings, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates by using interest rate derivatives to convert some or all of the interest rates we pay on our borrowings from a floating rate to a fixed interest rate.
On June 30 and July 1, 2011, CRNF entered into two Interest Rate Swap agreements. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. The Interest Rate Swap agreements commenced on August 12, 2011; therefore, the impact recorded for the twelve months ended December 31, 2011 is $0.4 million in interest expense. For the twelve months ended December 31, 2011, the Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $2.4 million, which is unrealized, in accumulated other comprehensive income.
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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. In order to effectively review and assess our historical financial information below, we have also included supplemental operating measures and industry measures that we believe are material to understanding our business.
The tables below provide an overview of our results of operations, relevant market indicators and our key operating statistics during the fiscal years ended December 31, 2011, 2010 and 2009:
| Year Ended December 31, | ||||||||||||
| Financial Results |
2011 | 2010 | 2009 | |||||||||
| (in millions) | ||||||||||||
| Net sales(1) |
$ | 302.9 | $ | 180.5 | $ | 208.4 | ||||||
| Cost of product sold — Affiliates(2) |
11.7 | 5.8 | 9.5 | |||||||||
| Cost of products sold — Third Parties(2) |
30.8 | 28.5 | 32.7 | |||||||||
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|||||||
| 42.5 | 34.3 | 42.2 | ||||||||||
| Direct operating expenses — Affiliates(2) |
1.2 | 2.3 | 2.1 | |||||||||
| Direct operating expenses — Third Parties(2) |
85.3 | 84.4 | 82.4 | |||||||||
|
|
|
|
|
|
|
|||||||
| 86.5 | 86.7 | 84.5 | ||||||||||
| Insurance recovery — business interruption |
(3.4 | ) | — | — | ||||||||
| Selling, general and administrative expenses — Affiliates(2) |
16.5 | 16.7 | 12.3 | |||||||||
| Selling, general and administrative expenses — Third Parties(2) |
5.7 | 3.9 | 1.8 | |||||||||
|
|
|
|
|
|
|
|||||||
| 22.2 | 20.6 | 14.1 | ||||||||||
| Depreciation and amortization(3) |
18.9 | 18.5 | 18.7 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
$ | 136.2 | $ | 20.4 | $ | 48.9 | ||||||
| Interest expense and other financing costs |
(4.0 | ) | — | — | ||||||||
| Interest income |
— | 13.1 | 9.0 | |||||||||
| Other income (expense) |
0.2 | (0.2 | ) | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Total other income (expense) |
(3.8 | ) | 12.9 | 9.0 | ||||||||
|
|
|
|
|
|
|
|||||||
| Income before income tax expense |
132.4 | 33.3 | 57.9 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income(4) |
$ | 132.4 | $ | 33.3 | $ | 57.9 | ||||||
| Adjusted EBITDA(5) |
$ | 162.6 | $ | 52.6 | $ | 70.8 | ||||||
| Available cash for distribution(6) |
$ | 114.4 | $ | — | $ | — | ||||||
| As of December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Balance Sheet Data |
||||||||||||
| Cash and cash equivalents |
$ | 237.0 | $ | 42.7 | $ | 5.4 | ||||||
| Working capital |
229.4 | 27.1 | 135.5 | |||||||||
| Total assets |
659.3 | 452.2 | 551.5 | |||||||||
| Total debt, including current portion |
125.0 | — | — | |||||||||
| Partners’ capital |
489.5 | 402.2 | 519.9 | |||||||||
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) |
||||||||||||
| Cash Flow and Other Data |
||||||||||||
| Net cash flow provided by (used in): |
||||||||||||
| Operating activities |
$ | 139.8 | $ | 75.9 | $ | 85.5 | ||||||
| Investing activities |
(16.4 | ) | (9.0 | ) | (13.4 | ) | ||||||
| Financing activities |
70.8 | (29.6 | ) | (75.8 | ) | |||||||
| Capital expenditures for property, plant and equipment |
19.1 | 10.1 | 13.4 | |||||||||
| Depreciation and amortization |
18.9 | 18.5 | 18.7 | |||||||||
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Table of Contents
| (1) | Below are the components of Net sales: |
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (unaudited) | ||||||||||||
| Reconciliation to net sales (dollars in millions): |
||||||||||||
| Sales net plant gate |
$ | 266.6 | $163.4 | $186.3 | ||||||||
| Freight in revenue |
22.1 | 17.0 | 21.3 | |||||||||
| Hydrogen revenue |
14.2 | 0.1 | 0.8 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total net sales |
$ | 302.9 | $180.5 | $208.4 | ||||||||
| (2) | Our direct operating expenses and selling, general and administrative expenses for the years ended December 31, 2011, 2010 and 2009 are shown exclusive of depreciation and amortization and include a charge related to CVR Energy’s share-based compensation expense allocated to us by CVR Energy and share-based compensation incurred under the CVR Partners LTIP for financial reporting purposes in accordance with ASC 718. We are not responsible for the payment of cash related to any share- based compensation allocated to us by CVR Energy. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Share-Based Compensation.” The charges for share-based compensation were: |
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Direct operating expenses |
$ | 0.5 | $ | 0.7 | $ | 0.2 | ||||||
| Selling, general and administrative expenses |
6.8 | 8.3 | 3.0 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
$ | 7.3 | $ | 9.0 | $ | 3.2 | ||||||
|
|
|
|
|
|
|
|||||||
| (3) | Depreciation and amortization is comprised of the following components: |
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Depreciation and amortization excluded from direct operating expenses |
$ | 18.8 | $ | 18.5 | $ | 18.7 | ||||||
| Depreciation and amortization excluded from cost of product sold |
0.1 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Total depreciation and amortization |
$ | 18.9 | $ | 18.5 | $ | 18.7 | ||||||
|
|
|
|
|
|
|
|||||||
| (4) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance: |
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Share-based compensation expense(a) |
$ | 7.3 | $ | 9.0 | $ | 3.2 | ||||||
|
|
|
|
|
|
|
|||||||
| (a) | Represents the impact of share-based compensation awards allocated from CVR Energy and CALLC III and share-based compensation associated with awards from our CVR Partners LTIP. Subsequent to June 30, 2011, no additional amounts will be allocated to us by CALLC III. We are not responsible for payment of share-based compensation awards allocated from CVR Energy and CALLC III and all such expense amounts are reflected as an increase or decrease to Partners’ capital. |
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Table of Contents
| (5) | Adjusted EBITDA is defined as net income before income tax expense, net interest (income) expense, depreciation and amortization expense and the impact of share-based compensation, major scheduled turnaround expenses and loss on disposition of assets which are items that management believes affect the comparability of operating results. Adjusted EBITDA is not a recognized term under GAAP and should not be substituted for net income as a measure of performance but should be utilized as a supplemental measure of performance in evaluating our business. Management believes that adjusted EBITDA provides relevant and useful information that enables external users of our financial statements, such as industry analysts, investors, lenders and rating agencies to better understand and evaluate our ongoing operating results and allows for greater transparency in the review of our overall financial, operational and economic performance. |
A reconciliation of our net income to adjusted EBITDA is as follows:
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in millions) | ||||||||||||
| Net income |
$ | 132.4 | $ | 33.3 | $ | 57.9 | ||||||
| Add: |
||||||||||||
| Interest expense and other financing costs |
4.0 | — | — | |||||||||
| Interest income |
— | (13.1 | ) | (9.0 | ) | |||||||
| Income tax expense |
— | — | — | |||||||||
| Depreciation and amortization |
18.9 | 18.5 | 18.7 | |||||||||
| Loss on disposition of assets |
— | 1.4 | — | |||||||||
| Turnaround |
— | 3.5 | — | |||||||||
| Share-based compensation |
7.3 | 9.0 | 3.2 | |||||||||
|
|
|
|
|
|
|
|||||||
| Adjusted EBITDA |
$ | 162.6 | $ | 52.6 | $ | 70.8 | ||||||
|
|
|
|
|
|
|
|||||||
| (6) | We define available cash for distribution generally as equal to our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that our board of directors of our general partner deems necessary or appropriate. For the year ended December 31, 2011, available cash for distribution is calculated for the period beginning at the closing of the Initial Public Offering (April 13, 2011) through December 31, 2011. The Partnership also retains the cash on hand associated with prepaid sales at each quarter end for future distribution to common unitholders based upon the recognition into income of the prepaid sales. |
Below is a table reconciling the available cash for distribution for the three months ended December 31, 2011:
| Three Months
Ended December 31, 2011 |
||||
| (in millions, except per unit amount) | ||||
| (unaudited) | ||||
| Cash flows from operations |
$ | 31.9 | ||
| Adjustments: |
||||
| Plus: Deferred revenue balance at September 30, 2011 |
20.6 | |||
| Less: Deferred revenue balance at December 31, 2011 |
(9.0 | ) | ||
| Plus: Insurance proceeds included in investing activities |
— | |||
| Less: Maintenance capital expenditures |
(0.6 | ) | ||
|
|
|
|||
| Available cash for distribution |
$ | 42.9 | ||
| Available cash for distribution, per unit |
$ | 0.588 | ||
| Common units outstanding |
73,031 | |||
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Table of Contents
The following tables show selected information about key market indicators and certain operating statistics for our business:
| Year Ended December 31, | ||||||||||||
| Key Operating Statistics |
2011 | 2010 | 2009 | |||||||||
| Production (thousand tons): |
||||||||||||
| Ammonia (gross produced)(1) |
411.2 | 392.7 | 435.2 | |||||||||
| Ammonia (net available for sale)(1) |
116.8 | 155.6 | 156.6 | |||||||||
| UAN |
714.1 | 578.3 | 677.7 | |||||||||
| Pet coke consumed (thousand tons) |
517.3 | 436.3 | 483.5 | |||||||||
| Pet coke (cost per ton)(2) |
$ | 33 | $ | 17 | $ | 27 | ||||||
| Sales (thousand tons): |
||||||||||||
| Ammonia |
112.8 | 164.7 | 159.9 | |||||||||
| UAN |
709.3 | 580.7 | 686.0 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total |
822.1 | 745.4 | 845.9 | |||||||||
| Product price (plant gate) (dollars per ton)(3): |
||||||||||||
| Ammonia |
$ | 579 | $ | 361 | $ | 314 | ||||||
| UAN |
$ | 284 | $ | 179 | $ | 198 | ||||||
| On-stream factor(4): |
||||||||||||
| Gasifier |
99.0 | % | 89.0 | % | 97.4 | % | ||||||
| Ammonia |
97.7 | % | 87.7 | % | 96.5 | % | ||||||
| UAN |
95.5 | % | 80.8 | % | 94.1 | % | ||||||
| Annual Average For Year Ended December 31, |
||||||||||||
| Market Indicators |
2011 | 2010 | 2009 | |||||||||
| Natural gas (dollars per MMbtu) |
$ | 4.03 | $ | 4.38 | $ | 4.16 | ||||||
| Ammonia — Southern Plains (dollars per ton) |
619 | 437 | 306 | |||||||||
| UAN — corn belt (dollars per ton) |
379 | 266 | 218 | |||||||||
| (1) | The gross tons produced for ammonia represent the total ammonia produced, including ammonia produced that was upgraded into UAN. The net tons available for sale represent the ammonia available for sale that was not upgraded into UAN. |
| (2) | Our pet coke cost per ton purchased from CVR Energy averaged $28, $11 and $22 for the years ended December 31, 2011, 2010 and 2009, respectively. Third-party pet coke prices averaged $45, $40 and $37 for the years ended December 31, 2011, 2010 and 2009, respectively. |
| (3) | Plant gate price per ton represents net sales less freight revenue and hydrogen revenue divided by product sales volume in tons in the reporting period. Plant gate price per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. |
| (4) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period and is included as a measure of Operating efficiency. Excluding the impact of the Linde air separation unit outage, the on-stream factors for the year ended December 31, 2011 would have been 99.2% for gasifier, 98.0% for ammonia and 95.7% for UAN. Excluding the impact of the downtime associated with the Linde air separation unit outage, the rupture of the high pressure UAN vessel and the major scheduled turnaround, the on-stream factors for the year ended December 31, 2010 would have been 97.6% for gasifier, 96.8% for ammonia and 96.1% for UAN. Excluding the Linde air separation unit outage in 2009, the on-stream factors would have been 99.3% for gasifier, 98.4% for ammonia and 96.1% for UAN for the year ended December 31, 2009. |
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Table of Contents
Year Ended December 31, 2011 compared to the Year Ended December 31, 2010
Net Sales. Nitrogen fertilizer net sales were $302.9 million for the year ended December 31, 2011, compared to $180.5 million for the year ended December 31, 2010. For the year ended December 31, 2011, ammonia, UAN and hydrogen made up $67.2 million, $221.5 million and $14.2 million of our net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $63.0 million, $117.4 million and $0.1 million, respectively, for the year ended December 31, 2010. The net sales increase of $122.4 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was the result of higher UAN sales volumes coupled with increased ammonia and UAN plant gate prices. This increase was partially offset by lower ammonia sales volumes. Both UAN and ammonia sales for the year ended December 31, 2010 were negatively impacted by the downtime associated with the major scheduled turnaround during 2010, and UAN sales were impacted additionally by the downtime associated with the rupture of a high-pressure UAN vessel during 2010. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia, UAN and hydrogen for the year ended December 31, 2011 compared to the year ended December 31, 2010.
| Year Ended December 31, 2011 | Year Ended December 31, 2010 | Total Variance | Price Variance |
Volume Variance |
||||||||||||||||||||||||||||||||||||||||
| Volume (1) | $ per ton (2) | Sales $ (3) | Volume (1) | $ per ton (2) | Sales $ (3) | Volume (1) | Sales $ (3) | |||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||
| Ammonia |
112,775 | $ | 596 | $ | 67.2 | 164,668 | $ | 382 | $ | 63.0 | (51,893 | ) | $ | 4.2 | $ | 35.2 | $ | (31.0 | ) | |||||||||||||||||||||||||
| UAN |
709,280 | $ | 312 | $ | 221.5 | 580,684 | $ | 202 | $ | 117.4 | 128,596 | $ | 104.1 | $ | 63.9 | $ | 40.2 | |||||||||||||||||||||||||||
| Hydrogen |
1,389,796 | $ | 10 | $ | 14.2 | 20,583 | $ | 7 | $ | 0.1 | 1,369,213 | $ | 14.1 | $ | 0.1 | $ | 14.0 | |||||||||||||||||||||||||||
| (1) | Sales volume in tons. |
| (2) | Includes freight charges. |
| (3) | Sales dollars in millions. |
In regard to product sales volumes for the year ended December 31, 2011, our nitrogen fertilizer operations experienced a decrease of 31.5% in ammonia sales unit volumes and an increase of 22.1% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2011 compared to 2010 were higher for all units of our nitrogen fertilizer operations, primarily due to the major scheduled turnaround, the rupture of a high pressure UAN vessel and unscheduled downtime associated with the Linde air separation unit outage all in 2010. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.
Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the year ended December 31, 2011 for ammonia were higher than plant gate prices for the year ended December 31, 2010 by approximately 60.3% and plant gate prices for UAN were approximately 58.6% higher during the year ended December 31, 2011 than the plant gate prices for the year ended December 31, 2010.
Insurance Recovery - Business Interruption. During the year ended December 31, 2011, we recorded and received insurance proceeds under insurance coverage for interruption of business of $3.4 million related to the September 30, 2010 UAN vessel rupture.
Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2011 was
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$42.5 million, compared to $34.3 million for the year ended December 31, 2010. Of this $8.2 million increase, $5.9 million resulted from higher costs from transactions with affiliates and $2.3 million from higher costs from third parties. Besides increased costs associated with higher UAN sales volumes and $4.8 million increased freight expenses, we experienced an increase in pet coke costs of $9.5 million ($6.7 million from transactions with affiliates). These increased costs were partially offset by a decrease in costs associated with lower ammonia sales and a decrease in hydrogen costs ($0.8 million).
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for our nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2011 were $86.5 million, as compared to $86.7 million for the year ended December 31, 2010. The total decrease of $0.2 million for the year ended December 31, 2011, as compared to the year ended December 31, 2010, was comprised of a $1.1 million decrease in costs from transactions with affiliates, coupled with $0.9 million increased direct operating costs from third parties. The $0.2 million net decrease was primarily the result of decreases in expenses associated with the 2010 biennial turnaround ($3.5 million), net UAN reactor repairs and maintenance expense ($3.4 million), equipment rent ($0.5 million), labor ($0.4 million) and increased reimbursed expenses ($1.5 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ($5.4 million), repairs and maintenance ($3.1 million), catalyst ($0.3 million) and environmental ($0.3 million)
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business as well as certain expenses incurred by our affiliates, CVR Energy and Coffeyville Resources, on our behalf and billed or allocated to us. Certain of our expenses are subject to the services agreement with CVR Energy and our general partner. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $22.2 million for the year ended December 31, 2011, as compared to $20.6 million for the year ended December 31, 2010. The increase of $1.6 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was the result of an increase in costs from transactions with third parties ($1.8 million) coupled with a decrease in costs from transactions with affiliates ($0.2 million). This variance was primarily the result of increases in outside services ($2.0 million) and expenses related to the services agreement ($1.2 million). These increases were partially offset by decreases in share-based compensation ($1.4 million).
Operating Income. Nitrogen fertilizer operating income was $136.2 million for the year ended December 31, 2011, as compared to operating income of $20.4 million for the year ended December 31, 2010. The increase of $115.8 million for the year ended December 31, 2011 as compared to the year ended December 31, 2010 was the result of the increase in nitrogen fertilizer margins ($114.2 million) coupled with business interruption recoveries recorded ($3.4 million) and decreased direct operating costs ($0.2 million). These favorable increases were partially offset by an increase in selling, general and administrative expenses (exclusive of depreciation and amortization) ($1.6 million) and depreciation and amortization ($0.4 million).
Interest Income. We had no interest income for the year ended December 31, 2011, as compared to $13.1 million for the year ended December 31, 2010. Interest income for the year ended December 31, 2010 was primarily the result of interest income resulting from the balance owed to us by Coffeyville Resources. The due from affiliate balance was distributed to Coffeyville Resources in December 2010. Accordingly, no interest income was generated from a due from affiliate balance in 2011.
Income Tax Expense. Income tax expense for the year ended December 31, 2011 and 2010 was immaterial and consisted of amounts payable pursuant to a Texas state franchise tax.
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Net Income. For the year ended December 31, 2011, net income was $132.4 million, as compared to $33.3 million of net income for the year ended December 31, 2010, an increase of $99.1 million. The increase in net income was primarily due to the increase in our profit margin offset by an increase in interest expense and a reduction in interest income.
Year Ended December 31, 2010 compared to the Year Ended December 31, 2009
Net Sales. Nitrogen fertilizer net sales were $180.5 million for the year ended December 31, 2010, compared to $208.4 million for the year ended December 31, 2009. For the year ended December 31, 2010, ammonia, UAN and hydrogen made up $63.0 million, $117.4 million and $0.1 million of our net sales, respectively. This compared to ammonia, UAN and hydrogen net sales of $54.6 million, $153.0 million and $0.8 million, respectively, for the year ended December 31, 2009. The decrease of $27.9 million from the year ended December 31, 2010 as compared to the year ended December 31, 2009 was the result of a decline in average UAN plant gate prices coupled with lower UAN sales volume. This decrease was partially offset by higher ammonia sales volumes coupled with higher ammonia prices on a year-over-year basis. Both UAN and ammonia sales in 2010 were negatively impacted by the downtime associated with the scheduled 2010 turnaround. Additionally, UAN sales were negatively impacted by the downtime associated with the rupture of a high-pressure UAN vessel. The UAN vessel ruptured on September 30, 2010 and production of UAN did not recommence until November 16, 2010. The following table demonstrates the impact of changes in sales volumes and sales price for ammonia and UAN for the year ended December 31, 2010 compared to the year ended December 31, 2009.
| Year Ended December 31, 2010 | Year Ended December 31, 2009 | Total Variance | Price Variance |
Volume Variance |
||||||||||||||||||||||||||||||||||||||||
| Volume (1) | $ per ton (2) | Sales $ (3) | Volume (1) | $ per ton (2) | Sales $ (3) | Volume (1) | Sales $ (3) | |||||||||||||||||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||||||||||||||||||
| Ammonia |
164,668 | $ | 382 | $ | 63.0 | 159,860 | $ | 342 | $ | 54.6 | 4,808 | $ | 8.4 | $ | 6.5 | $ | 1.9 | |||||||||||||||||||||||||||
| UAN |
580,684 | $ | 202 | $ | 117.4 | 686,009 | $ | 223 | $ | 153.0 | (105,325 | ) | $ | (35.6 | ) | $ | (14.2 | ) | $ | (21.4 | ) | |||||||||||||||||||||||
| (1) | Sales volume in tons. |
| (2) | Includes freight charges. |
| (3) | Sales dollars in millions. |
In regard to product sales volumes for the year ended December 31, 2010, our nitrogen fertilizer operations experienced an increase of 3% in ammonia sales unit volumes and a decrease of 15% in UAN sales unit volumes. On-stream factors (total number of hours operated divided by total hours in the reporting period) for 2010 compared to 2009 were lower for all units of our nitrogen fertilizer operations, primarily due to unscheduled downtime associated with the Linde air separation unit outage, the UAN vessel rupture and the completion of the biennial scheduled turnaround for the nitrogen fertilizer plant completed in the fourth quarter of 2010. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.
Plant gate prices are prices at the designated delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both at our plant gate (sold plant) and delivered to the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the year ended December 31, 2010 for ammonia were greater than plant gate prices for the year ended December 31, 2009 by approximately 15%. Conversely, UAN plant gate prices for UAN were approximately 10% lower during the year ended December 31, 2010 than the plant gate prices for the year ended December 31, 2009. The fertilizer industry experienced an unusual pricing cycle starting in 2008. Significant increases in average plant gate prices for 2008 had a carryover effect on 2009 average UAN prices primarily for the first half of 2009, before they began to decrease in the second half of 2009 and into the first half of 2010. Average ammonia plant gate prices for 2009 were negatively impacted by reduced demand resulting from the lack of a fall planting season and rebounded in 2010 due to increased fall planting season demand. Prices for UAN and ammonia recovered in the second half of 2010.
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Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold (exclusive of depreciation and amortization) is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2010 was $34.3 million, compared to $42.2 million for the year ended December 31, 2009. Of this $7.9 million decrease, $3.8 million resulted from lower costs from transactions with affiliates and $4.1 million from lower costs from transactions with third parties. A $5.5 million decline in pet coke costs ($3.9 million from transactions with affiliates) was the principal contributor to the decrease, with the remaining decrease of $2.4 million primarily attributable to lower UAN sales volume (105,325 tons) driven by downtime associated with the major scheduled turnaround and the UAN vessel rupture.
Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses (exclusive of depreciation and amortization) for our nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, property taxes, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2010 were $86.7 million, as compared to $84.5 million for the year ended December 31, 2009. The increase of $2.2 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009, was comprised of a $2.0 million increase in costs from transactions with third parties coupled with a $0.2 million increase in direct operating costs from transactions with affiliates. The $2.2 million net increase was primarily the result of increases in expenses associated with the turnaround ($3.5 million), property taxes ($2.5 million), net UAN reactor repairs and maintenance expense ($1.5 million), labor ($1.4 million) and refractory brick amortization ($0.7 million). The turnaround expenses for 2010 are the result of the nitrogen fertilizers business’ biennial turnaround. The increase in property taxes for the year ended December 31, 2010 was the result of an increased valuation assessment on the nitrogen fertilizer plant as well as the expiration of a tax abatement for the Linde air separation unit for which we pay taxes in accordance with our agreement with Linde. These increases in direct operating expenses were partially offset by decreases in expenses associated with energy and utilities ($6.0 million), catalyst ($1.1 million) and insurance ($0.7 million). The majority of the decrease in energy and utilities expenses reflects a $4.8 million settlement of an electric rate case with the City of Coffeyville in the third quarter of 2010. This $4.8 million refund of amounts paid between August 2008 through July 2010 was a one-time event.
Selling, General and Administrative Expenses (Exclusive of Depreciation and Amortization). Selling, general and administrative expenses include the direct selling, general and administrative expenses of our business as well as certain expenses incurred by our affiliates, CVR Energy and Coffeyville Resources, on our behalf and billed or allocated to us. Certain of our expenses are subject to the services agreement with CVR Energy and our general partner. Selling, general and administrative expenses (exclusive of depreciation and amortization) were $20.6 million for the year ended December 31, 2010, as compared to $14.2 million for the year ended December 31, 2009. This variance was primarily the result of increases in share based compensation expense of $5.3 million, asset write-offs of $1.5 million and outside services of $0.6 million. These increases were partially offset by lower costs from affiliates that resulted from decreased expenses related to the services agreement.
Operating Income. Nitrogen fertilizer operating income was $20.4 million for the year ended December 31, 2010, or 11% of net sales, as compared to $48.9 million for the year ended December 31, 2009, or 23% of net sales. This decrease of $28.5 million for the year ended December 31, 2010, as compared to the year ended December 31, 2009, was the result of a decline in the nitrogen fertilizer margin ($20.0 million), increases in selling, general and administrative expenses ($6.4 million), primarily attributable to an increase in share-based compensation expense, and an increase in direct operating expenses (exclusive of depreciation and amortization) ($2.2 million).
Interest Income. Interest income for the year ended December 31, 2010 and 2009 was primarily the result of interest income resulting from the outstanding balance owed to us by Coffeyville Resources. Interest income was $13.1 million for the year ended December 31, 2010, as compared to $9.0 million for the year ended December 31, 2009. The due from affiliate balance was distributed to Coffeyville Resources in December, 2010.
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Income Tax Expense. Income tax expense for the year ended December 31, 2010 and 2009 was immaterial and consisted of amounts payable pursuant to a Texas state franchise tax.
Net Income. For the year ended December 31, 2010, net income was $33.3 million as compared to $57.9 million of net income for the year ended December 31, 2009, a decrease of $24.6 million. The decrease in net income was primarily due to the decrease in our profit margin, coupled with an increase in selling, general and administrative expenses (exclusive of depreciation and amortization). These impacts were partially offset by a decrease in direct operating expenses (exclusive of depreciation and amortization) and an increase in interest income.
Liquidity and Capital Resources
Our principal source of liquidity has historically been cash from operations, which includes cash advances from customers resulting from forward sales. Our liquidity was enhanced during the second quarter of 2011 by the receipt of $324.2 million in net proceeds from our Initial Public Offering after the payment of underwriting discounts and commissions. The net proceeds from the Initial Public Offering were used as follows: approximately $18.4 million was used to make a distribution to CRLLC to satisfy our obligation to reimburse it for certain capital expenditures CRLLC made on our behalf; approximately $117.1 million was used to make a special distribution to CRLLC in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Initial Public Offering; approximately $26.0 million was used to purchase (and subsequently extinguish) the IDRs owned by our general partner prior to the Initial Public Offering; approximately $4.8 million was used to pay financing fees and associated legal and professional fees resulting from our credit facility; and the balance was used or will be used for general partnership purposes, including approximately $104.0 million to fund the expected capital costs of the continuation of our $135.0 million UAN expansion. As of December 31, 2011, approximately $43.6 million had been spent on this UAN expansion. In addition, in conjunction with the completion of the Initial Public Offering, we entered into a new $125 million term loan and $25 million revolving credit facility and were removed as a guarantor or obligor, as applicable, under CRLLC’s ABL credit facility, 9.0% First Lien Senior Secured Notes due 2015 and 10.875% Second Lien Senior Secured Notes due 2017.
Our principal uses of cash are expected to be operations, distributions to common unitholders, capital expenditures and funding our debt service obligations. We believe that our cash from operations will be adequate to satisfy anticipated commitments for the next twelve months and that the net proceeds from our Initial Public Offering and borrowings under our credit facility will be adequate to fund our planned capital expenditures, including the UAN expansion, for the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive, and other factors beyond our control.
Cash Balance and Other Liquidity
As of December 31, 2011, we had cash and cash equivalents of $237.0 million including $9.0 million of customer advances. Working capital at December 31, 2011 was $229.4 million, consisting of $271.9 million in current assets and $42.5 million in current liabilities. Working capital at December 31, 2010 was $27.1 million, consisting of $73.2 million in current assets and $46.1 million in current liabilities. As of February 20, 2012, we had cash and cash equivalents of $216.8 million.
Credit Facility
On April 13, 2011 in conjunction with the completion of our Initial Public Offering, we entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility
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of $25.0 million with an uncommitted incremental facility of up to $50.0 million. There is no scheduled amortization and the credit facility matures in April 2016. The credit facility is used to finance on-going working capital, capital projects, letter of credit issuances and general needs of the Partnership.
Borrowings under the credit facility bear interest based on a pricing grid determined by a trailing four quarter leverage ratio. Pricing for borrowings under the credit facility is currently the Eurodollar rate plus a margin of 3.50%, or, for base rate loans, the prime rate plus 2.50%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CVR Partners and CRNF and all of the capital stock of CRNF and each domestic subsidiary owned by CVR Partners or CRNF. CRNF is the borrower under the credit facility. All obligations under the credit facility are unconditionally guaranteed by CVR Partners and substantially all of our future, direct and indirect, domestic subsidiaries.
As of December 31, 2011, no amounts were drawn under the $25.0 million revolving credit facility.
Mandatory Prepayments
We are required to prepay outstanding amounts under our term facility in an amount equal to the net proceeds from the sale of assets or from insurance or condemnation awards related to collateral, in each case subject to certain reinvestment rights. In addition, we are required to prepay outstanding amounts under our term facility with the net proceeds from certain issuances of debt (other than debt permitted to be incurred under our credit facility).
Voluntary Prepayments/Commitment Reductions
At any time, we may voluntarily reduce the unutilized portion of the revolving commitment amount, and prepay, in whole or in part, outstanding amounts under our credit facility without premium or penalty other than customary “breakage” costs with respect to Eurodollar rate loans.
Amortization and Final Maturity
There is no scheduled amortization under our credit facility. All outstanding amounts under our credit facility are due and payable in full in April 2016.
Restrictive Covenants and Other Matters
Our credit facility requires us to maintain (i) a minimum interest coverage ratio (ratio of Consolidated Adjusted EBITDA to interest) as of any fiscal quarter of 3.0 to 1.0 and (ii) a maximum leverage ratio (ratio of debt to Consolidated Adjusted EBITDA) of any fiscal quarter ending on or after December 31, 2011, 3.0 to 1.0 in all cases calculated on a trailing four quarter basis. In addition, the credit facility includes negative covenants that, subject to significant exceptions, limit our ability and the ability of certain of our subsidiaries to, among other things:
| • | incur, assume or permit to exist additional indebtedness, guarantees and other contingent obligations; |
| • | incur liens; |
| • | make negative pledges; |
| • | pay dividends or make other distributions; |
| • | make payments to our subsidiary; |
| • | make certain loans and investments; |
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| • | consolidate, merge or sell all or substantially all of our assets; |
| • | enter into sale-leaseback transactions; and |
| • | enter into transactions with affiliates. |
The credit facility provides that we can make distributions to holders of our common units, but only if we are in compliance with our leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to any distribution and there is no default or event of default under the facility.
The credit facility contains certain customary representations and warranties, affirmative covenants and events of default, including, among other things, payment defaults, breach of representations and warranties, covenant defaults, cross-defaults to certain indebtedness, certain events of bankruptcy, certain events under ERISA, material judgments, actual or asserted failure of any guaranty or security document supporting the credit facility to be in force and effect, and change of control. An event of default will also be triggered if CVR Energy or any of its subsidiaries (other than us and CRNF) terminates or violates any of its covenants in any of the intercompany agreements between us and CVR Energy and its subsidiaries (other than us and CRNF) and such action has a material adverse effect on us. If an event of default occurs, the administrative agent under the credit facility would be entitled to take various actions, including the acceleration of amounts due under the credit facility and all actions permitted to be taken by a secured creditor.
Interest Rate Swap
Our profitability and cash flows are affected by changes in interest rates, specifically LIBOR and prime rates. The primary purpose of our interest rate risk management activities is to hedge our exposure to changes in interest rates.
On June 30 and July 1, 2011, CRNF entered into two Interest Rate Swap agreements with J. Aron. These agreements commenced on August 12, 2011. We have determined that the Interest Rate Swaps qualify as a hedge for hedge accounting treatment. The impact recorded for the twelve months ended December 31, 2011 is $0.4 million in interest expense. For the year ended December 31, 2011, the Partnership recorded a decrease in fair market value on the Interest Rate Swap agreements of $2.4 million, which is unrealized in accumulated other comprehensive income.
Capital Spending
We divide our capital spending needs into two categories: maintenance and growth. Maintenance capital spending includes only non-discretionary maintenance projects and projects required to comply with environmental, health and safety regulations. We also treat maintenance capital spending as a reduction of cash available for distribution to unitholders. Growth capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. Major scheduled turnaround expenses are expensed when incurred.
Our future capital spending will be determined by the board of directors of our general partner. The data contained in the table below represents our current estimates for 2012, but these estimates may change as a result of unforeseen circumstances and a change in our plans. These estimates may be revised from time to time or amounts may not be spent in the manner allocated below.
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The following table summarizes our total actual capital expenditures for 2011 and estimated capital expenditures for 2012:
| Year Ended December 31 | ||||||||
| 2011 Actual | 2012 Estimate | |||||||
| ($ in millions) | ||||||||
| UAN expansion |
$ | 12.6 | $ | 85.0 | ||||
| Other |
0.3 | 15.1 | ||||||
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| Growth capital expenditures |
12.9 | 100.1 | ||||||
| Maintenance capital expenditures |
$ | 6.2 | $ | 9.7 | ||||
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| Total estimated capital spending before turnaround expenses |
19.1 | 109.8 | ||||||
| Major scheduled turnaround expenses |
— | 5.0 | ||||||
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| Total estimated capital spending including major scheduled turnaround expense |
$ | 19.1 | $ | 114.8 | ||||
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Our growth strategy includes expanding production of UAN and acquiring additional infrastructure and production assets. We are moving forward with a significant two-year plant expansion designed to increase our UAN production capacity by 400,000 tons, or approximately 50% per year. We anticipate that the total capital spend associated with the UAN expansion will approximate $135.0 million. As of December 31, 2011, approximately $43.6 million had been spent, including $12.6 million, which was spent during the year ended December 31, 2011. The UAN expansion is expected to be completed in the first quarter of 2013.
Capital expenditure plans for 2012 also include the construction of a two million gallon UAN storage tank and related truck and rail car load-out facilities, to enable us to distribute up to approximately 20,000 tons of UAN fertilizer annually. The property that this terminal will be constructed on is located in Phillipsburg, Kansas. The expected cost of this project is approximately $2.0 million. These capital expenditures, along with other growth projects are expected to be funded primarily with proceeds from our Initial Public Offering and term loan borrowings.
Planned capital expenditures for 2012 are subject to change due to unanticipated increases in the cost, scope and completion time for our capital projects. For example, we may experience increases in labor or equipment costs necessary to comply with government regulations or to complete projects that sustain or improve the profitability of our nitrogen fertilizer plant. Capital spending for our business has been and will be determined by our general partner.
Distributions to Unitholders
Our general partner’s current policy is to distribute all of the available cash we generate on a quarterly basis. Available cash for each quarter is determined by the board of directors of our general partner following the end of such quarter. Available cash for each quarter generally equals our cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. The Partnership also retains the cash on hand associated with prepaid sales at each quarter end for future distributions to common unitholders based upon the recognition into income of the prepaid sales. The partnership agreement does not require the Partnership to make any distributions, and the board of directors of our general partner could change our distribution policy at any time, including reducing the amount or frequency of distributions we make or eliminating all distributions.
On August 12, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on August 5, 2011 for the second quarter of 2011 in the amount of $0.407 per unit, or $29.7 million in aggregate.
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On November 14, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on November 7, 2011 for the third quarter of 2011 in the amount of $0.572 per unit, or $41.8 million in aggregate.
On February 14, 2012, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on February 7, 2012 for the fourth quarter of 2011 in the amount of $0.588 per unit, or $42.9 million in aggregate.
The Partnership did not make quarterly distributions to unitholders prior to the closing of the Initial Public Offering.
Cash Flows
The following table sets forth our cash flows for the periods indicated below (in millions):
| For the Year
Ended December 31, |
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| 2011 | 2010 | 2009 | ||||||||||
| Net cash provided by (used in): |
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| Operating activities |
$ | 139.8 | $ | 75.9 | $ | 85.5 | ||||||
| Investing activities |
(16.4 | ) | (9.0 | ) | (13.4 | ) | ||||||
| Financing activities |
70.8 | (29.6 | ) | (75.8 | ) | |||||||
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| Net increase (decrease) in cash and cash equivalents |
$ | 194.2 | $ | 37.3 | $ | (3.7 | ) | |||||
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Cash Flows Provided by Operating Activities
For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital.
Net cash flows provided by operating activities for the year ended December 31, 2011 were $139.8 million. The positive cash flow from operating activities generated over this period was primarily attributable to net income of $132.4 million, which was driven by a strong fertilizer price environment and high on-stream factors, partially offset by unfavorable impacts to working capital. For the year ended December 31, 2011, trade working capital decreased our operating cash flow by $13.6 million and was primarily attributable to a decrease in accounts payable of $5.9 million, an increase in accounts receivable of $4.3 million and an increase in inventory of $3.4 million. With respect to other working capital for the year ended December 31, 2011, the primary uses of cash were a $9.6 million decrease in deferred revenue and a $3.3 million decrease in prepaid expenses, partially offset by the receipt of business interruption proceeds of $3.4 million. Deferred revenue represents customer prepaid deposits for the future delivery of our nitrogen fertilizer products.
Net cash flows provided by operating activities for the year ended December 31, 2010 were $75.9 million. This positive cash flow from operating activities was primarily attributable to net income and increased cash flow from trade and other working capital. Net income was driven by a strong fertilizer price environment, which was partially offset by a decline in overall sales volume that resulted from downtime associated with the major scheduled turnaround and the rupture of a high pressure UAN vessel in the fourth quarter of 2010. Trade working capital for the year ended December 31, 2010 increased our operating cash flow by $9.3 million and was attributable to a $2.1 million decrease in inventory and a $9.4 million increase in accounts payable partially offset by a $2.2 million increase in accounts receivable. With respect to other working capital for the year ended December 31, 2010, the primary source of cash was an $8.4 million increase in deferred revenue. Deferred revenue represents customer prepaid deposits for the future delivery of our nitrogen fertilizer products. Additionally, we received insurance proceeds of approximately $4.3 million related to the repairs, maintenance
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and other associated costs of the UAN vessel rupture, of which approximately $3.2 million is included in cash flows from operating activities and the remaining balance is included in cash flows from investing activities. This was partially offset by the establishment of a $4.5 million insurance receivable associated with the UAN vessel rupture and a $2.7 million increase in prepaid expenses and other current assets.
Net cash flows from operating activities for the year ended December 31, 2009 were $85.5 million. The positive cash flow from operating activities generated over this period was primarily driven by strong sales volumes and a favorable fertilizer price environment. Also positively impacting cash flows from operations were favorable changes in other working capital. These positive cash flows were partially offset by net decreases in cash from trade working capital. Trade working capital for the year ended December 31, 2009 reduced our operating cash flow by $0.3 million. For the year ended December 31, 2009, accounts receivable decreased by $3.2 million and inventory decreased by $5.7 million resulting in a net inflow of cash of $8.9 million. These inflows of cash due to changes in trade working capital were offset by a decrease in accounts payable, or a use of cash, of $9.2 million. With respect to other working capital, the primary source of cash during the year ended December 31, 2009 was a $4.5 million increase in deferred revenue and a $1.5 million decrease in prepaid expenses and other current assets. Deferred revenue represents customer prepaid deposits for the future delivery of our nitrogen fertilizer products.
Cash Flows Used In Investing Activities
Net cash flows used in investing activities for the years ended December 31, 2011, 2010 and 2009 were $16.4 million, $9.0 million, and $13.4 million, respectively. For the year ended December 31, 2011, the increase in capital expenditures to $19.1 million was primarily related to the UAN expansion. For the years ended December 31, 2011 and 2010, capital expenditures were partially offset by approximately $2.7 million and $1.1 million, respectively, of insurance proceeds received in connection with the rupture of the high-pressure UAN vessel.
Cash Flows Used In Financing Activities
Net cash flows provided by financing activities for the year ended December 31, 2011 was $70.8 million, compared to net cash flows used in financing activities for the years ended December 2010 and 2009 of $29.6 million and $75.8 million, respectively. The net cash provided by financing activities for the year ended December 31, 2011 was attributable to the issuance of $125.0 million of long-term debt and the $324.9 million of proceeds from the Initial Public Offering, offset by the $276.7 million distributed to our affiliates on or before the Initial Public Offering, as well as the quarterly cash distributions paid subsequent to the Initial Public Offering of $71.4 million, and the $26.0 million used to purchase our general partners’ incentive distribution rights from an affiliate. For the year ended December 31, 2010, $29.0 million of the net cash used in financing activities was primarily attributable to amounts loaned to our affiliate. For the year ended December 31, 2009, net cash used in financing activities was entirely attributable to amounts loaned to our affiliates.
Capital and Commercial Commitments
We are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of December 31, 2011 relating to operating leases and unconditional purchase obligations for the five years ending December 31, 2016 and thereafter.
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Contractual Obligations
| Payments Due by Period | ||||||||||||||||||||||||||||
| Total | 2012 | 2013 | 2014 | 2015 | 2016 | Thereafter | ||||||||||||||||||||||
| (in millions) | ||||||||||||||||||||||||||||
| Long-term debt(1) |
$ | 125.0 | $ | — | $ | — | $ | — | $ | — | $ | 125.0 | $ | — | ||||||||||||||
| Operating leases(2) |
32.4 | 5.5 | 6.0 | 4.7 | 4.2 | 3.8 | 8.2 | |||||||||||||||||||||
| Unconditional purchase obligations(3) |
50.2 | 5.9 | 6.0 | 6.1 | 6.2 | 6.3 | 19.7 | |||||||||||||||||||||
| Unconditional purchase obligations with affiliates(4) |
268.9 | 15.8 | 16.8 | 17.0 | 16.5 | 16.9 | 185.9 | |||||||||||||||||||||
| Interest payments (5) |
21.1 | 4.9 | 4.9 | 4.9 | 4.9 | 1.5 | — | |||||||||||||||||||||
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| Total |
$ | 497.6 | $ | 32.1 | $ | 33.7 | $ | 32.7 | $ | 31.8 | $ | 153.5 | $ | 213.8 | ||||||||||||||
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| (1) | We entered into a new credit facility. The new credit facility included a $125.0 million term loan on April 13, 2011 and a $25.0 million revolving credit facility. The table assumes no amounts are outstanding under the revolving credit facility. |
| (2) | We lease various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods. |
| (3) | The amounts include commitments under an electric supply agreement with the city of Coffeyville and a product supply agreement with Linde. |
| (4) | The amounts include commitments under our long-term pet coke supply agreement with CVR Energy having an initial term that ends in 2027, subject to renewal. The Partnership’s purchase obligations for pet coke from CVR Energy has been derived from a calculation of the average pet coke price paid to CVR Energy over the preceding two year period. |
| (5) | Interest payments are based on the current interest rate on December 31, 2011. |
Under our long-term pet coke supply agreement with CVR Energy, we may become obligated to provide security for our payment obligations under the agreement if in CVR Energy’s sole judgment there is a material adverse change in our financial condition or liquidity position or in our ability to make payments. This security may not exceed an amount equal to 21 times the average daily dollar value of pet coke we purchase for the 90-day period preceding the date on which CVR Energy gives us notice that it has deemed that a material adverse change has occurred. Unless otherwise agreed by CVR Energy and us, we can provide such security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If we do not provide such security, CVR Energy may require us to pay for future deliveries of pet coke on a cash-on-delivery basis, failing which it may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days’ prior written notice. Additionally, we may terminate the agreement within 60 days of providing security, so long as we provide five days’ prior written notice.
Our ability to make payments on and to refinance our indebtedness, to make distributions, to fund planned capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to nitrogen fertilizer margins, natural gas prices and general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.
Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our credit facility, in an amount sufficient to enable us to make quarterly distributions, finance necessary capital expenditures, service our indebtedness or fund our other liquidity needs. We may seek to sell assets or issue debt securities or additional equity securities to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
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Off-Balance Sheet Arrangements
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.
Recently Issued Accounting Standards
In May 2011, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. We believe that the adoption of this standard will not materially expand our consolidated financial statement footnote disclosures.
In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,” (“ASU 2011-05”) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Partnership must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for interim and annual periods beginning after December 15, 2011. In November 2011, FASB decided to defer the effective date of the changes in ASU 2011-05 that relate to the presentation of reclassification adjustments to again consider whether to present the effects of reclassifications out of accumulated other comprehensive income on the face of the financials. This deferral does not impact the other requirements as of ASU 2011-05. We believe that the adoption of ASU 2011-05 will not have a material impact on the consolidated financial statements.
In September 2011, FASB issued ASU No. 2011-08, “Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment,” (“ASU 2011-08”). ASU 2011-08 permits an entity to make a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. This new guidance is to be applied prospectively. ASU 2011-08 is effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. We adopted this standard on October 1, 2011. The adoption of this standard did not impact our financial position or results of operations.
Critical Accounting Policies
We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited financial statements included elsewhere in this report. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.
Impairment of Long-Lived Assets
The Partnership accounts for impairment of long-lived assets in accordance with ASC 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets, or ASC 360. In accordance with ASC 360, the
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Partnership reviews long-lived assets (excluding goodwill and intangible assets with indefinite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
Goodwill
To comply with ASC 350, Intangibles — Goodwill and Other, or ASC 350, we perform a test for goodwill impairment annually, or more frequently in the event we determine that a triggering event has occurred. Our annual testing is performed in the fourth quarter of each year. Goodwill and other intangible accounting standards provide that goodwill and other intangible assets with indefinite lives are not amortized but instead are tested for impairment on an annual basis. In accordance with these standards, we completed our annual test for impairment of goodwill as of November 1, 2011 and November 1, 2010, respectively. For 2011, 2010 and 2009, the annual test of impairment indicated that goodwill was not impaired.
In 2011, we elected to early adopt ASU 2011 – 08, which allows an alternative in certain situations that simplifies the impairment testing of goodwill. The new guidance allows an entity the option to first perform a qualitative evaluation to determine whether it is necessary to perform the quantitative two-step goodwill impairment analysis.
We began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in order to determine if any significant events, transactions or other factors had occurred or are expected to occur that would impair earnings or competitiveness therefore impairing the fair value of the Partnership. After assessing the totality of events and circumstances, it was determined that it was not more likely than not that the fair value of the Partnership was less than the carrying value ,and so it was not necessary to perform the two-step valuation. The key drivers that were considered in the evaluation of the Partnership’s fair value included:
| • | general economic conditions; |
| • | fertilizer pricing; |
| • | input costs; and |
| • | customer outlook. |
In 2010, the annual review of impairment was performed by comparing the carrying value of the partnership to its estimated fair value. The valuation analysis used both income and market approaches as described below:
| • | Income Approach: To determine fair value, we discounted the expected future cash flows for the reporting unit utilizing observable market data to the extent available. The discount rate used for the 2010 impairment test was 14.6%, representing the estimated weighted-average costs of capital, which reflects the overall level of inherent risk involved in the reporting unit and the rate of return an outside investor would expect to earn. |
| • | Market-Based Approach: To determine the fair value of the reporting unit, we also utilized a market-based approach. We used the guideline company method, which focuses on comparing our risk profile and growth prospects to select reasonably similar publicly traded companies. |
We assigned an equal weighting of 50% to the result of both the income approach and market based approach based upon the reliability and relevance of the data used in each analysis. This weighting was deemed reasonable as the guideline public companies have a high-level of comparability with the reporting unit and the projections used in the income approach were prepared using current estimates.
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Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assumed. Sales are recognized when the product is delivered and all significant obligations of the Partnership have been satisfied. Deferred revenue represents customer prepayments under contracts to guarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business. Taxes collected from customers and remitted to governmental authorities are not included in reported revenues. Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciation and amortization).
Allocation of Costs
Our consolidated financial statements include an allocation of costs that have been incurred by CVR Energy or Coffeyville Resources on our behalf. The allocation of such costs is governed by the services agreement entered into by CVR Energy and us and affiliated companies in October 2007. The services agreement provides guidance for the treatment of certain general and administrative expenses and certain direct operating expenses incurred on our behalf. Such expenses incurred include, but are not limited to, salaries, benefits, share-based compensation expense, insurance, accounting, tax, legal and technology services. Prior to the services agreement such costs were allocated to us based upon certain assumptions and estimates that were made in order to allocate a reasonable share of such expenses to us, so that the consolidated financial statements reflect substantially all costs of doing business. The authoritative guidance to allocate such costs is set forth in Staff Accounting Bulletin, or SAB Topic 1-B “Allocations of Expenses and Related Disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity.”
Fair Value of Financial Instruments
The Partnership uses forward swap contracts primarily to reduce the exposure to changes in interest rates on our debt and to provide a cash flow hedge. These derivative instruments have been designated as hedges for accounting purposes. Accordingly, these instruments are recorded in the Consolidated Balance Sheets at fair value, at each reporting period end; the actual measurement of the cash flow hedge ineffectiveness will be recognized in earnings. The effective portion of the gain or loss on the swaps will be reported in Other Comprehensive Income (“OCI”), in accordance with Accounting Standards Codification (“ASC”) Topic 815-20-25, Derivatives and Hedging.
Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments.
Share-Based Compensation
We have been allocated non-cash share-based compensation expense from CVR Energy and from Coffeyville Acquisition III LLC. CVR Energy accounts for share-based compensation in accordance with ASC 718 Compensation — Stock Compensation, or ASC 718, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. In accordance with ASC 718, CVR Energy and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. We recognize the costs of the share-based compensation incurred by CVR Energy and CALLC III on our behalf primarily in selling, general and administrative expenses (exclusive of depreciation and amortization), and a corresponding increase or decrease to partners’ capital, as the costs are incurred on our behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees for acquiring, or in conjunction with selling goods or services, which require remeasurement at each reporting period through the performance commitment period, or in our case, through the
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vesting period. Costs are allocated by CVR Energy and CALLC III based upon the percentage of time a CVR Energy employee provides services to us. In the event an individual’s roles and responsibilities change with respect to services provided to us, a reassessment is performed to determine if the allocation percentages should be adjusted. In accordance with the services agreement, we will not be responsible for the payment of cash related to any share-based compensation allocated to us by CVR Energy.
There has been considerable judgment in the significant assumptions used in determining the fair value of the share-based compensation allocated to us from CALLC III and from CVR Energy associated with share-based compensation derived from Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC override units. There will be no further allocations of share-based compensation expense associated with CALLC III or with share-based compensation related to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC override units subsequent to June 30, 2011.
The Partnership’s grant of awards pursuant to the CVR Partners LTIP to employees or directors of its general partner are considered non-employee awards and the awards will be marked-to-market each reporting period until they vest.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
On June 30 and July 1, 2011 CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commenced on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (“AOCI”), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense.
Commodity Price, Foreign Currency Exchange and Non-Operating Risks
We do not currently use derivative financial instruments to manage risks related to changes in prices of commodities (e.g., ammonia, UAN or pet coke). Given that our business is currently based entirely in the United States, we are not directly exposed to foreign currency exchange rate risk. We do not engage in activities that expose us to speculative or non-operating risks, including derivative trading activities. In the opinion of our management, there is no derivative financial instrument that correlates effectively with, and has a trading volume sufficient to hedge, our firm commitments and forecasted commodity purchase or sales transactions. Our management will continue to monitor whether financial derivatives become available which could effectively hedge identified risks and management may in the future elect to use derivative financial instruments consistent with our overall business objectives to avoid unnecessary risk and to limit, to the extent practical, risks associated with our operating activities.
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Item 8. Financial Statements and Supplementary Data
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
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Report of Independent Registered Public Accounting Firm
The Board of Directors of CVR GP, LLC
and
The Unitholders of CVR Partners, LP
and
The General Partner of CVR Partners, LP:
We have audited the accompanying consolidated balance sheets of CVR Partners, LP and subsidiary (the Company), as of December 31, 2011 and 2010 and the related consolidated statements of operations, partners’ capital, and cash flows for each of the years in the three-year period ended December 31, 2011. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the consolidated financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of CVR Partners, LP and subsidiary as of December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2011, in conformity with U.S. generally accepted accounting principles.
/s/ KPMG LLP
Houston, Texas
February 23, 2012
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CONSOLIDATED BALANCE SHEETS
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| (dollars in thousands) | ||||||||
| ASSETS | ||||||||
| Current assets: |
||||||||
| Cash and cash equivalents |
$ | 236,975 | $ | 42,745 | ||||
| Accounts receivable, net of allowance for doubtful accounts of $76 and $43, respectively |
9,322 | 5,036 | ||||||
| Inventories |
23,255 | 19,830 | ||||||
| Prepaid expenses and other current assets including $572 and $2,587 from affiliates at December 31, 2011 and 2010, respectively |
2,311 | 5,557 | ||||||
|
|
|
|
|
|||||
| Total current assets |
271,863 | 73,168 | ||||||
| Property, plant, and equipment, net of accumulated depreciation |
341,495 | 337,938 | ||||||
| Intangible assets, net |
36 | 46 | ||||||
| Goodwill |
40,969 | 40,969 | ||||||
| Deferred financing cost, net |
3,164 | — | ||||||
| Other long-term assets, including $1,495 and $0 with affiliates at December 31, 2011 and 2010, respectively |
1,782 | 44 | ||||||
|
|
|
|
|
|||||
| Total assets |
$ | 659,309 | $ | 452,165 | ||||
|
|
|
|
|
|||||
| LIABILITIES AND PARTNERS’ CAPITAL | ||||||||
| Current liabilities: |
||||||||
| Accounts payable, including $2,064 and $3,323 due to affiliates at December 31, 2011 and 2010, respectively |
$ | 15,869 | $ | 17,758 | ||||
| Personnel accruals, including $812 and $0 with affiliates at December 31, 2011 and 2010, respectively |
2,744 | 1,848 | ||||||
| Deferred revenue |
9,019 | 18,660 | ||||||
| Accrued expenses and other current liabilities, including $549 and $0 with affiliates at December 31, 2011 and 2010, respectively |
14,822 | 7,810 | ||||||
|
|
|
|
|
|||||
| Total current liabilities |
42,454 | 46,076 | ||||||
| Long-term liabilities: |
||||||||
| Long-term debt, net of current portion |
125,000 | — | ||||||
| Other long-term liabilities, including $850 and $0 with affiliates at December 31, 2011 and 2010, respectively |
2,366 | 3,886 | ||||||
|
|
|
|
|
|||||
| Total long-term liabilities |
127,366 | 3,886 | ||||||
| Commitments and contingencies |
||||||||
| Partners’ capital: |
||||||||
| Special general partner’s interest, 30,303,000 units issued and outstanding at December 31, 2010 |
— | 397,951 | ||||||
| Limited partner’s interest, 30,333 units issued and outstanding at December 31, 2010 |
— | 398 | ||||||
| Managing general partner’s interest |
— | 3,854 | ||||||
| Common unitholders, 73,030,936 units issued and outstanding at December 31, 2011 |
491,876 | — | ||||||
| General partner’s interest |
1 | — | ||||||
| Accumulated other comprehensive loss |
(2,388 | ) | — | |||||
|
|
|
|
|
|||||
| Total partners’ capital |
489,489 | 402,203 | ||||||
|
|
|
|
|
|||||
| Total liabilities and partners’ capital |
$ | 659,309 | $ | 452,165 | ||||
|
|
|
|
|
|||||
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENTS OF OPERATIONS
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in thousands, except per unit data) | ||||||||||||
| Net sales |
$ | 302,867 | $ | 180,468 | $ | 208,371 | ||||||
| Operating costs and expenses: |
||||||||||||
| Cost of product sold (exclusive of depreciation and amortization) — Affiliates |
11,657 | 5,764 | 9,506 | |||||||||
| Cost of product sold (exclusive of depreciation and amortization) — Third parties |
30,854 | 28,564 | 32,652 | |||||||||
|
|
|
|
|
|
|
|||||||
| 42,511 | 34,328 | 42,158 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Direct operating expenses (exclusive of depreciation and amortization) — Affiliates |
1,167 | 2,308 | 2,136 | |||||||||
| Direct operating expenses (exclusive of depreciation and amortization) — Third parties |
85,324 | 84,371 | 82,317 | |||||||||
|
|
|
|
|
|
|
|||||||
| 86,491 | 86,679 | 84,453 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Insurance recovery – business interruption |
(3,360 | ) | — | — | ||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) — Affiliates |
16,449 | 16,748 | 12,310 | |||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) — Third parties |
5,709 | 3,894 | 1,902 | |||||||||
|
|
|
|
|
|
|
|||||||
| 22,158 | 20,642 | 14,212 | ||||||||||
|
|
|
|
|
|
|
|||||||
| Depreciation and amortization |
18,869 | 18,463 | 18,685 | |||||||||
|
|
|
|
|
|
|
|||||||
| Total operating costs and expenses |
166,669 | 160,112 | 159,508 | |||||||||
|
|
|
|
|
|
|
|||||||
| Operating income |
136,198 | 20,356 | 48,863 | |||||||||
| Other income (expense): |
||||||||||||
| Interest expense and other financing costs |
(4,007 | ) | — | — | ||||||||
| Interest income |
79 | 13,124 | 8,999 | |||||||||
| Other income, net |
205 | (148 | ) | 31 | ||||||||
|
|
|
|
|
|
|
|||||||
| Total other income (expense) |
(3,723 | ) | 12,976 | 9,030 | ||||||||
|
|
|
|
|
|
|
|||||||
| Income before income tax expense |
132,475 | 33,332 | 57,893 | |||||||||
| Income tax expense |
28 | 26 | 15 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net income |
$ | 132,447 | $ | 33,306 | $ | 57,878 | ||||||
|
|
|
|
|
|
|
|||||||
| Net income subsequent to initial public offering |
$ | 108,351 | ||||||||||
| Net income per common unit – basic (1) |
$ | 1.48 | ||||||||||
| Net income per common unit – diluted (1) |
$ | 1.48 | ||||||||||
| Weighted-average common units outstanding: |
||||||||||||
| Basic |
73,008 | |||||||||||
| Diluted |
73,073 | |||||||||||
| (1) | Represents net income per common unit since closing the Partnership’s Initial Public Offering on April 13, 2011. See Note 13 to the consolidated financial statements. |
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL
| Common Units | ||||||||||||||||||||||||||||||||
| Special General Partners’ Interest |
Limited Partners’ Interest |
Managing General Partners’ Interest |
Units Issued |
Amount | General Partner Interest |
Accumulated Other Comprehensive Income/(Loss) |
Total | |||||||||||||||||||||||||
| (in thousands, except unit data) | ||||||||||||||||||||||||||||||||
| Balance at December 31, 2008 |
$ | 454,499 | $ | 455 | $ | 3,854 | — | $ | — | $ | — | $ | — | $ | 458,808 | |||||||||||||||||
| Net income |
57,820 | 58 | — | — | — | — | — | 57,878 | ||||||||||||||||||||||||
| Share-based compensation Affiliates |
3,195 | 3 | — | — | — | — | — | 3,198 | ||||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Balance at December 31, 2009 |
515,514 | 516 | 3,854 | — | — | — | — | 519,884 | ||||||||||||||||||||||||
| Net income |
33,273 | 33 | — | — | — | — | — | 33,306 | ||||||||||||||||||||||||
| Share-based compensation –Affiliates |
9,004 | 9 | — | — | — | — | — | 9,013 | ||||||||||||||||||||||||
| Property distribution |
(159,840 | ) | (160 | ) | — | — | — | — | — | (160,000 | ) | |||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Balance at December 31, 2010 |
397,951 | 398 | 3,854 | — | — | — | — | 402,203 | ||||||||||||||||||||||||
| Conversion of Special General Partners’ Interest and Limited Partners’ Interest to Common Units |
(372,699 | ) | (373 | ) | — | — | 373,072 | — | — | — | ||||||||||||||||||||||
| Issuance of common units to public, net of offering and other costs |
— | — | — | 73,000,000 | 324,206 | — | — | 324,206 | ||||||||||||||||||||||||
| Purchase of Managing General Partner Incentive Distribution Rights |
— | — | (3,854 | ) | — | (22,147 | ) | 1 | — | (26,000 | ) | |||||||||||||||||||||
| Cash distributions to affiliates |
(53,928 | ) | (54 | ) | — | — | (272,545 | ) | — | — | (326,527 | ) | ||||||||||||||||||||
| Cash distributions to public unitholders |
— | — | — | — | (21,630 | ) | — | — | (21,630 | ) | ||||||||||||||||||||||
| Issuance of units under LTIP – Affiliates |
— | — | — | 36,076 | 845 | — | — | 845 | ||||||||||||||||||||||||
| Share-based compensation – Affiliates |
4,604 | 5 | — | — | 1,845 | — | — | 6,454 | ||||||||||||||||||||||||
| Redemption of common units |
— | — | — | (5,140 | ) | (121 | ) | — | — | (121 | ) | |||||||||||||||||||||
| Comprehensive income: |
||||||||||||||||||||||||||||||||
| Net income attributable to the period from January 1, 2011 through April 12, 2011 |
24,072 | 24 | — | — | — | — | — | 24,096 | ||||||||||||||||||||||||
| Net income attributable to the period from April 13, 2011 thru December 31, 2011 |
— | — | — | — | 108,351 | — | — | 108,351 | ||||||||||||||||||||||||
| Net unrealized gains (losses) on interest rate swaps |
— | — | — | — | — | — | (2,388 | ) | (2,388 | ) | ||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Comprehensive income (loss) |
24,072 | 24 | — | — | 108,351 | — | (2,388 | ) | 130,059 | |||||||||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
| Balance at December 31, 2011 |
$ | — | $ | — | $ | — | 73,030,936 | $ | 491,876 | $ | 1 | $ | (2,388 | ) | $ | 489,489 | ||||||||||||||||
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|||||||||||||||||
See accompanying notes to consolidated financial statements.
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CONSOLIDATED STATEMENTS OF CASH FLOWS
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in thousands) | ||||||||||||
| Cash flows from operating activities: |
||||||||||||
| Net income |
$ | 132,447 | $ | 33,306 | $ | 57,878 | ||||||
| Adjustments to reconcile net income to net cash provided by operating activities: |
||||||||||||
| Depreciation and amortization |
18,869 | 18,463 | 18,685 | |||||||||
| Allowance for doubtful accounts |
33 | (39 | ) | 20 | ||||||||
| Amortization of deferred financing costs |
694 | — | — | |||||||||
| Loss on disposition of fixed assets |
782 | 1,897 | 16 | |||||||||
| Share-based compensation - Affiliates |
7,299 | 9,013 | 3,198 | |||||||||
| Change in assets and liabilities: |
||||||||||||
| Accounts receivable |
(4,319 | ) | (2,218 | ) | 3,191 | |||||||
| Inventories |
(3,425 | ) | 2,106 | 5,695 | ||||||||
| Insurance receivable |
(5,880 | ) | (4,500 | ) | — | |||||||
| Business interruption insurance proceeds |
3,360 | — | — | |||||||||
| Insurance proceeds |
— | 3,161 | — | |||||||||
| Prepaid expenses and other current assets |
3,312 | (2,689 | ) | 1,549 | ||||||||
| Other long-term assets |
(1,784 | ) | 1 | (128 | ) | |||||||
| Accounts payable |
(5,871 | ) | 9,394 | (9,224 | ) | |||||||
| Deferred revenue |
(9,641 | ) | 8,395 | 4,517 | ||||||||
| Accrued expenses and other current liabilities |
3,478 | (306 | ) | 110 | ||||||||
| Other long-term liabilities |
499 | (39 | ) | 27 | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by operating activities |
139,853 | 75,945 | 85,534 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash flows from investing activities: |
||||||||||||
| Capital expenditures |
(19,145 | ) | (10,082 | ) | (13,388 | ) | ||||||
| Insurance proceeds from UAN reactor rupture |
2,745 | 1,114 | — | |||||||||
| Proceeds from sale of assets |
— | — | 18 | |||||||||
|
|
|
|
|
|
|
|||||||
| Net cash used in investing activities |
(16,400 | ) | (8,968 | ) | (13,370 | ) | ||||||
|
|
|
|
|
|
|
|||||||
| Cash flows from financing activities: |
||||||||||||
| Proceeds from issuance of long-term debt |
125,000 | — | — | |||||||||
| Payment of financing costs |
(4,825 | ) | (674 | ) | — | |||||||
| Due from affiliate |
— | (28,998 | ) | (75,799 | ) | |||||||
| Distributions to affiliates |
(326,527 | ) | — | — | ||||||||
| Cash distribution to public unitholders – non-affiliates |
(21,630 | ) | — | — | ||||||||
| Purchase of managing general partner incentive distribution rights |
(26,000 | ) | — | — | ||||||||
| Proceeds from issuances of common units, net of offering costs |
324,880 | — | — | |||||||||
| Redemption of common units |
(121 | ) | — | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Net cash provided by (used in) financing activities |
70,777 | (29,672 | ) | (75,799 | ) | |||||||
|
|
|
|
|
|
|
|||||||
| Net increase (decrease) in cash and cash equivalents |
194,230 | 37,305 | (3,635 | ) | ||||||||
| Cash and cash equivalents, beginning of period |
42,745 | 5,440 | 9,075 | |||||||||
|
|
|
|
|
|
|
|||||||
| Cash and cash equivalents, end of period |
$ | 236,975 | $ | 42,475 | $ | 5,440 | ||||||
|
|
|
|
|
|
|
|||||||
| Supplemental disclosures: |
||||||||||||
| Cash paid for income taxes |
$ | 15 | $ | 35 | $ | — | ||||||
| Cash paid for interest, net of capitalized interest of $1,335, $0 and $0 in 2011, 2010 and 2009, respectively |
$ | 2,428 | $ | — | $ | — | ||||||
| Non-cash investing and financing activities: |
||||||||||||
| Accrual of construction in progress additions |
$ | 3,982 | $ | 888 | $ | (4,872 | ) | |||||
| Partners’ property distribution |
$ | — | $ | (160,000 | ) | $ | — | |||||
See accompanying notes to consolidated financial statements.
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| (1) | Formation of the Partnership, Organization and Nature of Business |
CVR Partners, LP (referred to as “CVR Partners”, the “Partnership” or the “Company”) is a Delaware limited partnership, formed in June 2007 by CVR Energy, Inc. (together with its subsidiaries, but excluding the Partnership and its subsidiary, “CVR Energy”) to own Coffeyville Resources Nitrogen Fertilizers, LLC (“CRNF”), previously a wholly-owned subsidiary of CVR Energy. CRNF is an independent producer and marketer of upgraded nitrogen fertilizer products sold in North America. CRNF operates a dual-train coke gasifier plant that produces high-purity hydrogen, most of which is subsequently converted to ammonia and upgraded to urea ammonium nitrate (“UAN”).
CRNF produces and distributes nitrogen fertilizer products, which are used primarily by farmers to improve the yield and quality of their crops. CRNF’s principal products are ammonia and UAN. These products are manufactured at CRNF’s facility in Coffeyville, Kansas. CRNF’s product sales are heavily weighted toward UAN, and all of its products are sold on a wholesale basis.
In October 2007, CVR Energy, Inc., through its wholly-owned subsidiary, Coffeyville Resources, LLC (“CRLLC”), transferred CRNF, CRLLC’s nitrogen fertilizer business, to the Partnership. This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. The Partnership became the sole member of CRNF. In consideration for CRLLC transferring its nitrogen fertilizer business to the Partnership, (1) CRLLC directly acquired 30,333 special LP units, representing a 0.1% limited partner interest in the Partnership, (2) the Partnership’s special general partner, a wholly-owned subsidiary of CRLLC, acquired 30,303,000 special GP units, representing a 99.9% general partner interest in the Partnership, and (3) the managing general partner, then owned by CRLLC, acquired a managing general partner interest and incentive distribution rights (“IDRs”) of the Partnership. Immediately prior to CVR Energy’s Initial Public Offering, CVR Energy sold the managing general partner interest (together with the IDRs) to Coffeyville Acquisition III LLC (“CALLC III”), an entity owned by funds affiliated with Goldman, Sachs & Co. (the “Goldman Sachs Funds”) and Kelso & Company, L.P. (the “Kelso Funds”) and members of CVR Energy’s management team, for its fair market value on the date of sale. As a result of CVR Energy’s indirect ownership of the Partnership’s special general partner, it initially owned all of the interests in the Partnership (other than the managing general partner interest and the IDRs) and initially was entitled to all cash distributed by the Partnership.
Initial Public Offering of CVR Partners, LP
On April 13, 2011, CVR Partners completed its Initial Public Offering (the “Initial Public Offering”) of 22,080,000 common units priced at $16.00 per unit. The common units, which are listed on the New York Stock Exchange, began trading on April 8, 2011 under the symbol “UAN.”
The net proceeds to CVR Partners from the Initial Public Offering were approximately $324.2 million, after deducting underwriting discounts and commissions and offering expenses. The net proceeds from the Initial Public Offering were used as follows: approximately $18.4 million was used to make a distribution to CRLLC in satisfaction of the Partnership’s obligation to reimburse CRLLC for certain capital expenditures CRLLC made with respect to the nitrogen fertilizer business prior to October 24, 2007; approximately $117.1 million was used to make a special distribution to CRLLC in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Initial Public Offering; approximately $26.0 million was used to purchase (and subsequently extinguish) the IDRs owned by the general partner; approximately $4.8 million was used to pay financing fees and associated legal and professional fees resulting from the new credit facility; and the balance was used or will be used for general partnership purposes, including approximately $104.0 million to fund the continuation of the UAN expansion at the nitrogen fertilizer plant.
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Immediately prior to the closing of the Initial Public Offering, the Partnership distributed approximately $54.0 million of cash on hand to CRLLC. In connection with the Initial Public Offering, the Partnership’s special LP units were converted into common units, the Partnership’s special GP units were converted into common units, and the Partnership’s special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. Additionally, in conjunction with CVR GP, LLC selling its IDRs to the Partnership, which were then extinguished, CALLC III sold CVR GP, LLC to CRLLC for a nominal amount.
Subsequent to the closing of the Initial Public Offering, common units held by public security holders represented approximately 30% of all outstanding limited partner interests and CRLLC held common units approximating 70% of all outstanding limited partner interests.
The general partner manages and operates the Partnership. Common unitholders have only limited voting rights on matters affecting the Partnership. In addition, common unitholders have no right to elect the general partner’s directors on an annual or continuing basis.
The Partnership is operated by a combination of the general partner’s senior management team and CVR Energy’s senior management team pursuant to a services agreement among CVR Energy, CVR GP, LLC and the Partnership. In October 2007, the Partnership’s partners at that time entered into an amended and restated limited partnership agreement setting forth their various rights and responsibilities. The Partnership also entered into a number of agreements with CVR Energy and CVR GP, LLC to regulate certain business relations between the Partnership and the other parties thereto. See Note 18 (“Related Party Transactions”) for further discussion. In connection with the Initial Public Offering, certain of these agreements, including the amended and restated limited partnership agreement, were amended and/or restated. Additionally, in connection with the Initial Public Offering, the Partnership and CRNF were released from their obligations as guarantors under CRLLC’s asset-backed revolving credit facility (“ABL credit facility”) and the indentures which govern CRLLC’s senior secured notes, as described further in Note 17 (“Commitments and Contingencies”).
| (2) | Summary of Significant Accounting Policies |
Principles of Consolidation
The accompanying Partnership consolidated financial statements include the accounts of CVR Partners and CRNF, its wholly-owned subsidiary. All intercompany accounts and transactions have been eliminated in consolidation.
Cash and Cash Equivalents
The Partnership considers all highly liquid money market account and debt instruments with original maturities of three months or less to be cash equivalents.
Accounts Receivable, net
CVR Partners grants credit to its customers. Credit is extended based on an evaluation of a customer’s financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding longer than their contractual payment terms are considered past due. CVR Partners determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer’s ability to pay its obligations to CVR Partners, and the condition of the general economy and the industry as a whole. CVR Partners writes off accounts receivable when they become uncollectible, and payments
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subsequently received on such receivables are credited to the allowance for doubtful accounts. Amounts collected on accounts receivable are included in net cash provided by operating activities in the Consolidated Statements of Cash Flows. At December 31, 2011, three customers individually represented greater than 15% and collectively represented approximately 53% of the total accounts receivable balance (excluding accounts receivable with affiliates). At December 31, 2010, one customer represented approximately 21% of the total accounts receivable balance (excluding accounts receivable with affiliates). The largest concentration of credit for any one customer at December 31, 2011 and 2010 was approximately 22% and 21%, respectively, of the accounts receivable balance (excluding accounts receivable with affiliates).
Inventories
Inventories consist of fertilizer products which are valued at the lower of first-in, first-out (“FIFO”) cost, or market. Inventories also include raw materials, catalysts, parts and supplies, which are valued at the lower of moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.
Due From Affiliate
CVR Partners historically maintained a lending relationship with its affiliate CRLLC in order to supplement CRLLC’s working capital needs. As of December 31, 2010, the Partnership’s due from affiliate balance was $0 as a result of the $160.0 million receivable being distributed to CRLLC and the special general partner in accordance with their respective percentage interests. Amounts loaned to CRLLC are included on the Consolidated Balance Sheets as a due from affiliate. CVR Partners had the right to receive amounts owed from CRLLC upon request. CVR Partners charged interest on these borrowings at an interest rate equal to the applicable rate of under CRLLC’s first priority revolving credit facility. See Note 18 (“Related Party Transactions”) for further discussion of the due from affiliate. At December 31, 2011 and December 31, 2010, included in prepaid expense and other current assets on the Consolidated Balance Sheet are receivables of $0 and $2.3 million, respectively, for accrued interest with respect to amounts due from affiliate. For the year ended December 31, 2011, the Partnership recognized no income associated with the due from affiliate balance compared to approximately $13.1 million for the year ended December 31, 2010.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments, non-trade accounts receivables, affiliates’ receivables and other general current assets. Prepaid expenses and other current assets were as follows:
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| (in thousands) | ||||||||
| Accrued interest receivable(1) |
$ | — | $ | 2,318 | ||||
| Deferred financing cost |
966 | — | ||||||
| Deferred initial public offering costs |
— | 2,089 | ||||||
| Other(1) |
1,345 | 1,150 | ||||||
|
|
|
|
|
|||||
| $ | 2,311 | $ | 5,557 | |||||
|
|
|
|
|
|||||
| (1) | The accrued interest receivable represents amounts due from CRLLC, a related party, in connection with the due from affiliate balance. Additionally, included in the table above are amounts owed to the Partnership related to activities associated with the feedstock and shared services agreement. See Note 18 (“Related Party Transactions”) for additional discussion of amounts owed to the Partnership related to the due from affiliate balance and detail of amounts owed to the Partnership related to the feedstock and shared services agreement. |
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Property, Plant, and Equipment
Additions to property, plant and equipment, including certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1,000,000 in costs which is expected to take more than six months to complete. Depreciation is computed using principally the straight-line method over the estimated useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:
| Asset |
Range of Useful Lives, in Years | |
| Improvements to land |
30 | |
| Buildings |
30 | |
| Machinery and equipment |
5 to 30 | |
| Automotive equipment |
5 | |
| Furniture and fixtures |
3 to 7 | |
| Railcars |
25 to 40 |
The Company’s leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease term or the estimated useful life. Expenditures for routine maintenance and repair costs are expensed when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Company’s Consolidated Statements of Operations.
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. The Partnership uses November 1 of each year as its annual valuation date for the impairment test. The annual review of impairment is performed by comparing the carrying value of its assets to its estimated fair value. The Company performed its annual impairment review of goodwill and concluded there was no impairment in 2011, 2010 and 2009. See Note 8 (“Goodwill and Intangible Assets”) for further discussion.
Deferred Financing Costs
In connection with the credit facility, the Partnership has incurred lender and other third party costs. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.
Planned Major Maintenance Costs
The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. During the year ended December 31, 2010, the nitrogen fertilizer facility completed a major scheduled turnaround. Costs of approximately $3.5 million, associated with the 2010 turnaround, are included in direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2010. In connection with the 2010 nitrogen fertilizer plant’s turnaround, the Company wrote off fixed assets with a net book value of approximately $1.4 million.
Planned major maintenance activities generally occur every two years, and the next turnaround is scheduled for 2012.
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Cost Classifications
Cost of product sold (exclusive of depreciation and amortization) includes cost of pet coke expense and freight and distribution expenses. There was $58,000 in depreciation expense incurred related to the cost of product sold for the year ended December 31, 2011. There were no amounts in depreciation expense incurred for the years ended December 31, 2010 and 2009.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, property taxes, environmental compliance costs as well as chemical and catalyst and other direct operating expenses. Direct operating expenses also include allocated non-cash share-based compensation expenses from CVR Energy and CALLC III as discussed in Note 3 (“Share-Based Compensation”). Direct operating expenses exclude depreciation and amortization of approximately $18.8 million, $18.5 million and $18.7 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of direct and allocated legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses also include allocated non-cash share-based compensation expense from CVR Energy and CALLC III as discussed in Note 3 (“Share-Based Compensation”). Selling, general and administrative expenses exclude depreciation and amortization of approximately $10,000, $10,000 and $11,000 for the years ended December 31, 2011, 2010 and 2009, respectively.
Income Taxes
CVR Partners is a recognized partnership required to file a federal income tax return with each partner separately taxed on its share of CVR Partner’s taxable income. The Partnership is not subject to income taxes except for a franchise tax in the state of Texas. The income tax liability of the individual partners is not reflected in the consolidated financial statements of the Partnership.
Segment Reporting
The Financial Accounting Standards Board (“FASB”) Accounting Standards Codification (“ASC”) ASC Topic 280 — Segment Reporting, established standards for entities to report information about the operating segments and geographic areas in which they operate. CVR Partners only operates one segment and all of its operations are located in the United States.
Impairment of Long-Lived Assets
The Partnership accounts for impairment of long-lived assets in accordance with ASC 360, Property, Plant and Equipment — Impairment or Disposal of Long-Lived Assets, or ASC 360. In accordance with ASC 360, the Partnership reviews long-lived assets (excluding goodwill and intangible assets with indefinite lives) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Revenue Recognition
Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assumed, indicating that all significant obligations of CRNF have been satisfied. Deferred revenue represents customer prepayments under contracts to guarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business. Taxes collected from customers and remitted to governmental authorities are not included in reported revenues.
Shipping Costs
Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciation and amortization).
Derivative Instruments and Fair Value of Financial Instruments
On June 30 and July 1, 2011, CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commenced on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (“AOCI”), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense.
Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments.
Share-Based Compensation
We have been allocated non-cash share-based compensation expense from CVR Energy and from CALLC III. CVR Energy accounts for share-based compensation in accordance with ASC 718 Compensation — Stock Compensation, or ASC 718, as well as guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. In accordance with ASC 718, CVR Energy and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. We recognize the costs of the share-based compensation incurred by CVR Energy and CALLC III on our behalf primarily in selling, general and administrative expenses (exclusive of depreciation and amortization), and a corresponding increase or decrease to partners’ capital, as the costs are incurred on our behalf, following the guidance issued by the FASB regarding the accounting for equity instruments that are issued to other than employees for acquiring, or in conjunction with selling goods or services, which require remeasurement at each reporting period through the performance commitment period, or in our case, through the vesting period. Costs are allocated by CVR Energy and CALLC III based upon the percentage of time a CVR Energy employee provides services to us. In the event an individual’s roles and responsibilities change with respect to services provided to us, a reassessment is
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
performed to determine if the allocation percentages should be adjusted. In accordance with the services agreement, we will not be responsible for the payment of cash related to any share-based compensation allocated to us by CVR Energy.
The Partnership’s grant of awards pursuant to its long-term incentive plan to employees or directors of its general partner are considered non-employee awards and the awards will be marked–to-market each reporting period until they vest.
Environmental Matters
Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, internal and third-party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.
Use of Estimates
Preparing consolidated financial statements in conformity with U.S. GAAP requires management to make certain estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities in the consolidated financial statements and the reported amounts of revenues and expenses. Actual results could differ materially from those estimates.
Estimates made in preparing these consolidated financial statements include, among other things, estimates of depreciation and amortization expense, allocations of selling, general and administrative costs, including share-based awards, the economic useful life of assets, the fair value of assets, liabilities, provisions for uncollectible accounts receivable, the results of litigation, and various other recorded or disclosed amounts. Future changes in the assumptions used could have a significant impact on reported results in future periods.
Related Party Transactions
CVR Energy, a related party, provides a variety of services to the Partnership, including cash management and financing services, employee benefits provided through CVR Energy’s benefit plans, administrative services provided by CVR Energy’s employees and management, insurance and office space leased in CVR Energy’s headquarters building and other locations. As such, the accompanying consolidated financial statements include costs that have been incurred by CVR Energy on behalf of the Partnership. These amounts incurred by CVR Energy are then billed or allocated to the Partnership and are properly classified on the Consolidated Statements of Operations as either direct operating expenses (exclusive of depreciation and amortization) or as selling, general and administrative expenses (exclusive of depreciation and amortization). The billing and allocation of such costs are governed by the Services Agreement (the “Agreement”) originally entered into by CVR Energy, Inc. and CVR Partners, LP and affiliated companies in October 2007 and amended and restated in connection with the Initial Public Offering. The Agreement provides guidance for the treatment of certain general and administrative expenses and certain direct operating expenses incurred on the Partnership’s behalf. Such expenses include, but are not limited to, salaries, benefits, share-based compensation expense, insurance, accounting, tax, legal and technology services. Where costs are specifically incurred on behalf of the Partnership, the costs are billed directly to the Partnership. See Note18 (“Related Party Transactions”) for a detailed discussion of the billing procedures and the basis for calculating the charges for specific products and services.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The Partnership’s general partner manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person to perform services for the Partnership or for its general partner in connection with operating the Partnership). See Note 18 (“Related Party Transactions”)
The table below reflects amounts billed in accordance with the Agreement by CVR Energy to the Partnership and the Partnership’s limited partnership agreement with the general partner for the years ended December 31, 2011, 2010 and 2009. Additionally, see Note 3 (“Share-Based Compensation”) for amounts incurred by CVR Energy and allocated to the Partnership with respect to share-based compensation arrangements.
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in thousands) | ||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) |
$ | 2,022 | $ | 2,145 | $ | 2,811 | ||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) |
9,629 | 8,485 | 9,310 | |||||||||
|
|
|
|
|
|
|
|||||||
| $ | 11,651 | $ | 10,630 | $ | 12,121 | |||||||
|
|
|
|
|
|
|
|||||||
Subsequent Events
The Partnership evaluated subsequent events, if any, that would require an adjustment to the Partnership’s consolidated financial statements or require disclosure in the notes to the consolidated financial statements through the date of issuance of the consolidated financial statements.
New Accounting Pronouncements
In May 2011, the FASB issued Accounting Standards Update (“ASU”) No. 2011-04, “Fair Value Measurements (Topic 820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRS,” (“ASU 2011-04”). ASU 2011-04 changes the wording used to describe many of the requirements in U.S. GAAP for measuring fair value and for disclosing information about fair value measurements to ensure consistency between U.S. GAAP and International Financial Reporting Standards (“IFRS”). ASU 2011-04 also expands the disclosures for fair value measurements that are estimated using significant unobservable (Level 3) inputs. This new guidance is to be applied prospectively. ASU 2011-04 will be effective for interim and annual periods beginning after December 15, 2011. The Partnership believes that the adoption of this standard will not materially expand its consolidated financial statement footnote disclosures.
In June 2011, the FASB issued ASU No. 2011-05, “Comprehensive Income (ASC Topic 220): Presentation of Comprehensive Income,” (“ASU 2011-05”) which amends current comprehensive income guidance. This ASU eliminates the option to present the components of other comprehensive income as part of the statement of shareholders’ equity. Instead, the Partnership must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. ASU 2011-05 will be effective for interim and annual periods beginning after December 15, 2011. In November 2011, FASB decided to defer the effective date of the changes in ASU 2011-05 that relate to the presentation of reclassification adjustments to again consider whether to present the effects of reclassifications out of accumulated other comprehensive income on the face of the financials. This deferral does not impact the other requirements as of ASU 2011-05. The Partnership believes that the adoption of ASU 2011-05 will not have a material impact on the consolidated financial statements.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In September 2011, the FASB issued ASU No. 2011-08, “Intangibles – Goodwill and Other (Topic 350): Testing Goodwill for Impairment,” (“ASU 2011-08”). ASU 2011-08 permits an entity to make a qualitative assessment of whether it is more likely than not that a reporting unit’s fair value is less than its carrying amount before applying the two-step goodwill impairment test. This new guidance is to be applied prospectively. ASU 2011-08 is effective for interim and annual periods beginning after December 15, 2011, with early adoption permitted. The Partnership adopted this standard on October 1, 2011. The adoption of this standard did not impact the Partnership’s financial position of results of operations.
| (3) | Share-Based Compensation |
Certain employees of CVR Partners and employees of CVR Energy who perform services for the Partnership under the services agreement with CVR Energy participate in equity compensation plans of CVR Partners’ affiliates. Accordingly, CVR Partners has recorded compensation expense for these plans in accordance with Staff Accounting Bulletin, or SAB Topic 1-B “Allocations of Expenses and Related disclosures in Financial Statements of Subsidiaries, Divisions or Lesser Business Components of Another Entity” and in accordance with guidance regarding the accounting for share-based compensation granted to employees of an equity method investee. All compensation expense related to these plans for full-time employees of CVR Partners has been allocated 100% to CVR Partners. For employees covered by the services agreement with CVR Energy, the Partnership records share-based compensation relative to the percentage of time spent by each employee providing services to the Partnership as compared to the total calculated share-based compensation by CVR Energy. The Partnership is not responsible for payment of share-based compensation and all expense amounts are reflected as an increase or decrease to Partners’ Capital.
Prior to its initial public offering, CVR Energy was owned by Coffeyville Acquisition LLC (“CALLC”), which was principally owned by the Goldman Sachs Funds, the Kelso Funds and members of CVR Energy’s management team. In connection with CVR Energy’s initial public offering, CALLC was split into two entities: CALLC and Coffeyville Acquisition II LLC (“CALLC II”). In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, were split so that half of management’s equity interest was in CALLC and half was in CALLC II.
In February 2011, CALLC and CALLC II sold into the public market 11,759,023 shares and 15,113,254 shares, respectively, of CVR Energy’s common stock, pursuant to a registered public offering. As a result of the offering, CALLC II was no longer a stockholder of CVR Energy. Subsequent to CALLC II’s divestiture of its ownership interest in CVR Energy, no additional share-based compensation expense has been incurred with respect to override units of CALLC II.
In May 2011, CALLC sold its remaining shares of CVR Energy, pursuant to a registered public offering. As a result of this offering, CALLC was no longer a stockholder of CVR Energy. Subsequent to CALLC’s divestiture of its ownership interest in CVR Energy, no additional share-based compensation expense has been incurred with respect to override units of CALLC.
The final fair values of the CALLC and CALLC II override units were derived based upon the values resulting from the proceeds received associated with CALLC and CALLC II’s divestitures of their remaining shares of CVR Energy and attributable to the unvested units on the associated dates.
The final fair value of the CALLC III override units was derived based upon the value resulting from the proceeds received by the managing GP upon the purchase of the IDR’s by the Partnership. These proceeds were subsequently distributed to the owners of CALLC III which included the override unitholders. This value was utilized to determine the related compensation expense for the unvested units. Subsequent to June 30, 2011, no
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additional share-based compensation will be incurred with respect to override units of CALLC III due to the complete distribution of the value prior to July 1, 2011. For the years ended December 31, 2010 and 2009, the estimated fair value of the override units of CALLC III was determined using a probability-weighted expected return method which utilized CALLC III’s cash flow projections, which were considered representative of the nature of interests held by CALLC III in the Partnership.
The following table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II and CALLC III.
| Benchmark Value (per Unit) |
Original Awards Issued |
Compensation Expense Increase (Decrease) for the Years Ended December 31, |
||||||||||||||||||||||
| Award Type |
Grant Date | 2011 | 2010 | 2009 | ||||||||||||||||||||
| (in thousands) | ||||||||||||||||||||||||
| Override Operating Units(a) |
$ | 11.31 | 919,630 | June 2005 | $ | — | $ | 56 | $ | 346 | ||||||||||||||
| Override Operating Units(b) |
$ | 34.72 | 72,492 | December 2006 | — | 1 | 18 | |||||||||||||||||
| Override Value Units(c) |
$ | 11.31 | 1,839,265 | June 2005 | 1,495 | 4,751 | 1,207 | |||||||||||||||||
| Override Value Units(d) |
$ | 34.72 | 144,966 | December 2006 | 225 | 217 | 64 | |||||||||||||||||
| Override Units(e) |
$ | 10.00 | 642,219 | February 2008 | 143 | 473 | 5 | |||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
| Total | $ | 1,863 | $ | 5,498 | $ | 1,640 | ||||||||||||||||||
|
|
|
|
|
|
|
|||||||||||||||||||
Due to the divestiture of all ownership in CVR Energy by CALLC and CALLC II and due to the purchase of the IDRs from CVR GP, LLC and the distribution to CALLC III, there is no associated unrecognized compensation expense as of December 31, 2011.
Valuation Assumptions
Significant assumptions used in the valuation of the Override Operating Units (a) and (b) were as follows:
| (a) Override Operating Units December 31, |
(b) Override Operating Units December 31, |
|||||||
| 2009 | 2009 | |||||||
| Estimated forfeiture rate |
None | None | ||||||
| Derived service period |
6 years | 6 years | ||||||
| CVR Energy’s closing stock price |
$ | 6.86 | $ | 6.86 | ||||
| Estimated fair value (per unit) |
$ | 11.95 | $ | 1.40 | ||||
| Marketability and minority interest discounts |
20.0 | % | 20.0 | % | ||||
| Volatility |
50.7 | % | 50.7 | % | ||||
On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. As of December 31, 2010, these units were fully vested.
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Significant assumptions used in the valuation of the Override Value Units (c) and (d) were as follows:
| (c) Override Value Units December 31, |
(d) Override Value
Units December 31, |
|||||||||||||||
| 2010 | 2009 | 2010 | 2009 | |||||||||||||
| Estimated forfeiture rate |
None | None | None | None | ||||||||||||
| Derived service period |
6 years | 6 years | 6 years | 6 years | ||||||||||||
| CVR Energy’s closing stock price |
$ | 15.18 | $ | 6.86 | $ | 15.18 | $ | 6.86 | ||||||||
| Estimated fair value (per unit) |
$ | 22.39 | $ | 5.63 | $ | 6.56 | $ | 1.39 | ||||||||
| Marketability and minority interest discounts |
20.0 | % | 20.0 | % | 20.0 | % | 20.0 | % | ||||||||
| Volatility |
43.0 | % | 50.7 | % | 43.0 | % | 50.7 | % | ||||||||
(e) Override Units — Using a probability-weighted expected return method that utilized CALLC III’s cash flow projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. As a non-contributing investor, CVR Energy also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation cost. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units were subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:
| December 31, | ||||||||
| 2010 | 2009 | |||||||
| Estimated forfeiture rate |
None | None | ||||||
| Derived Service Period |
Forfeiture schedule | Forfeiture schedule | ||||||
| Estimated fair value (per unit) |
$2.60 | $0.08 | ||||||
| Marketability and minority interest discounts |
10.0 | % | 20.0 | % | ||||
| Volatility |
47.6 | % | 59.7 | % | ||||
Phantom Unit Plans
CVR Energy, through CRLLC, has two Phantom Unit Appreciation Plans (the “Phantom Unit Plans”) whereby directors, employees and service providers were awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points had rights to receive distributions when holders of override operating units received distributions. Holders of performance phantom points had rights to receive distributions when CALLC and CALLC II holders of override value units received distributions.
Compensation expense for the years ended December 31, 2011, 2010 and 2009, related to the Phantom Unit Plans was approximately $2.0 million, $3.2 million and $1.5 million, respectively.
Due to the divestiture of all ownership of CVR Energy by CALLC and CALLC II, there is no unrecognized compensation expense associated with the Phantom Units Plans at December 31, 2011.
Long-Term Incentive Plan – CVR Energy
CVR Energy has a Long-Term Incentive Plan (“CVR Energy LTIP”) that permits the grant of options, stock appreciation rights, restricted shares, restricted share units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance based restricted
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stock). As of December 31, 2011, only restricted shares of CVR Energy common stock and stock options had been granted under the CVR Energy LTIP. Individuals who are eligible to receive awards and grants under the CVR Energy LTIP include CVR Energy’s or its subsidiaries’ (including CRNF) employees, officers, consultants and directors.
Restricted Shares
Through the CVR Energy LTIP, shares of restricted common stock have been granted to employees of CVR Energy and CRNF. Restricted shares, when granted, are valued at the closing market price of CVR Energy’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the common stock. These shares generally vest over a three-year period. Assuming the allocation of costs from CVR Energy remains consistent with the allocation percentages in place at December 31, 2011, there was approximately $2.4 million of total unrecognized compensation cost related to restricted shares to be recognized over a weighted-average period of approximately two years. Inclusion of the vesting table is not considered meaningful due to changes in allocation percentages that occur from time to time. The unrecognized compensation expense has been determined by the number of restricted shares and respective allocation percentage for individuals for whom, as of December 31, 2011, compensation expense has been allocated to the Partnership.
Compensation expense recorded for the years ended December 31, 2011, 2010 and 2009, related to the restricted shares, was approximately $2.0 million, $0.3 million and $0.1 million, respectively.
Long-Term Incentive Plan – CVR Partners
In connection with the Initial Public Offering, the board of directors of the general partner adopted the CVR Partners, LP Long-Term Incentive Plan (“CVR Partners LTIP”). Individuals who are eligible to receive awards under the CVR Partners LTIP include employees, officers, consultants and directors of CVR Partners and the general partner and their respective subsidiaries and parents. The CVR Partners LTIP provides for the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units. The maximum number of common units issuable under the CVR Partners LTIP is 5,000,000.
In connection with the Initial Public Offering, 23,448 phantom units were granted to certain board members of the Partnership’s general partner. These phantom unit awards granted to the directors of the general partner are considered non-employee equity-based awards since the directors are not elected by unitholders. These phantom unit director awards were required to be marked-to-market each reporting period until they vested on October 12, 2011.
In June 2011, 50,659 phantom units were granted to an employee of the general partner. These phantom units are expected to vest over three years on the basis of one-third of the award each year. As these phantom unit awards were made to an employee of the general partner, they are considered non-employee equity-based awards and are required to be marked-to-market each reporting period until they vest.
In June 2011, 2,956 fully vested common units were granted to certain board members of the general partner. The fair value of these awards was calculated using the closing price of the Partnership’s common units on the date of grant. This amount was fully expensed at the time of grant.
In August 2011, 12,815 phantom units were granted to an employee of the general partner. These phantom units are expected to vest over three years on the basis of one-third of the award each year. As these phantom unit awards were made to an employee of the general partner, they are considered non-employee equity-based awards and are required to be marked-to-market each reporting period until they vest.
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In December 2011, 9,672 fully vested common units were granted to certain board members of the general partner. The fair value of these awards was calculated using the closing price of the Partnership’s common units on the date of the grant. The amount was fully expensed at the time of the grant.
In December 2011, 101,097 phantom units were granted to certain employees of the general partner and CRNF. These phantom units are expected to vest over three years on the basis of one-third of the award each year. For the phantom unit awards made to employees of the general partner, they are considered a non-employee equity based award and are required to be marked-to-market each reporting period until they vest. Awards made to employees of CRNF are valued on the grant date and amortized over the vesting period.
A summary of the status of the Partnership’s non-vested units as of December 31, 2011 and any changes during the year ended December 31, 2011 is presented below:
| Units | Weighted-Average Grant Date Fair Value |
Aggregate Intrinsic Value |
||||||||||
| (in thousands) | ||||||||||||
| Non-vested at April 13, 2011 |
— | $ | — | $ | — | |||||||
| Granted |
200,647 | 22.34 | ||||||||||
| Vested |
(36,076 | ) | 19.36 | |||||||||
| Forfeited |
— | — | ||||||||||
|
|
|
|
|
|
|
|||||||
| Non-vested at December 31, 2011 |
164,571 | $ | 22.99 | $ | 4,085 | |||||||
|
|
|
|
|
|
|
|||||||
Compensation expense recorded for the years ended December 31, 2011, 2010 and 2009, related to the awards under the CVR Partners LTIP was approximately $1.4 million, $0 and $0, respectively. Compensation expense associated with the awards under the CVR Partners LTIP has been recorded in selling, general and administrative expenses (exclusive of depreciation and amortization) – affiliates as the expense has been incurred for the benefit of directors or employees of the general partner.
As of December 31, 2011, there were 4,799,353 common units available for issuance under CVR Partners LTIP.
Unrecognized compensation expense associated with the unvested phantom units at December 31, 2011 was approximately $3.6 million.
| (4) | Inventories |
Inventories consisted of the following:
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| (in thousands) | ||||||||
| Finished goods |
$ | 6,130 | $ | 3,645 | ||||
| Raw materials and precious metals |
4,578 | 4,077 | ||||||
| Parts and supplies |
12,547 | 12,108 | ||||||
|
|
|
|
|
|||||
| $ | 23,255 | $ | 19,830 | |||||
|
|
|
|
|
|||||
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| (5) | Property, Plant, and Equipment |
A summary of costs for property, plant, and equipment is as follows:
| December 31, | ||||||||
| 2011 | 2010 | |||||||
| (in thousands) | ||||||||
| Land and improvements |
$ | 2,563 | $ | 2,492 | ||||
| Buildings |
815 | 724 | ||||||
| Machinery and equipment |
397,433 | 397,236 | ||||||
| Automotive equipment |
391 | 391 | ||||||
| Furniture and fixtures |
261 | 245 | ||||||
| Railcars |
2,496 | — | ||||||
| Construction in progress |
51,410 | 32,776 | ||||||
|
|
|
|
|
|||||
| $ | 455,369 | $ | 433,864 | |||||
| Accumulated depreciation |
113,874 | 95,926 | ||||||
|
|
|
|
|
|||||
| Total net, property, plant, and equipment |
$ | 341,495 | $ | 337,938 | ||||
|
|
|
|
|
|||||
Capitalized interest recognized as a reduction of interest expense for the years ended December 31, 2011 and 2010 totaled approximately $1.3 million and $0, respectively.
| (6) | Partners’ Capital and Partnership Distributions |
In connection with the Initial Public Offering that closed on April 13, 2011, the Partnership’s special LP units were converted into common units, the Partnership’s special GP units were converted into common units, and the Partnership’s special general partner was merged with and into CRLLC, with CRLLC continuing as the surviving entity. In addition, CVR GP, LLC sold its IDRs to the Partnership and the IDRs were extinguished, and CALLC III sold CVR GP, LLC to CRLLC. Following the Initial Public Offering, the Partnership has two types of partnership interests outstanding:
| • | common units; and |
| • | a general partner interest, which is not entitled to any distributions, and which is held by CVR GP, LLC, the general partner. |
At December 31, 2011, the Partnership had a total of 73,030,936 common units issued and outstanding, of which 50,920,000 common units were owned by CRLLC, representing approximately 70% of the total Partnership units outstanding.
The board of directors of the Partnership’s general partner has adopted a policy for the Partnership to distribute all available cash we generate on a quarterly basis. Cash distributions will be made to the common unitholders of record on the applicable record date, generally within 45 days after the end of each quarter. See Note 22 (“Subsequent Events”) for additional discussion of the cash distributions. Available cash for each quarter will be determined by the board of directors of the general partner following the end of such quarter. Available cash for each quarter will generally equal the Partnership’s cash flow from operations for the quarter, less cash needed for maintenance capital expenditures, debt service and other contractual obligations, and reserves for future operating or capital needs that the board of directors of our general partner deems necessary or appropriate. The Partnership also retains the cash on hand associated with prepaid sales at each quarter end for future distributions to common unitholders based upon the recognition into income of the prepaid sales.
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On August 12, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders for the second quarter of 2011 (calculated for the period beginning April 13, 2011 through June 30, 2011) in the amount of $0.407 per unit or $29.7 million in aggregate.
On November 14, 2011, the Partnership paid out a cash distribution to the Partnership’s unitholders for the third quarter of 2011 in the amount of $0.572 per unit or $41.8 million in aggregate.
On February 14, 2012, the Partnership paid out a cash distribution to the Partnership’s unitholders of record at the close of business on February 7, 2012 four the fourth quarter of 2011 in the amount of $0.588 per unit, or $42.9 million in aggregate.
There were no cash distributions paid in 2010 and 2009, as the IPO did not occur until 2011.
| (7) | Nitrogen Fertilizer Incident |
On September 30, 2010, the nitrogen fertilizer plant experienced an interruption in operations due to a rupture of a high-pressure UAN vessel. All operations at the nitrogen fertilizer facility were immediately shut down. No one was injured in the incident. Repairs to the facility as a result of the rupture were substantially complete as of December 31, 2010.
Total gross costs incurred as of December 31, 2011 due to the incident were approximately $11.4 million for repairs and maintenance and other associated costs. Approximately $10.5 million of these costs was recognized during the year ended December 31, 2010, and approximately $0.9 million of these costs was recognized during the year ended December 31, 2011. The repairs and maintenance costs incurred are included in direct operating expenses (exclusive of depreciation and amortization). Of the gross costs incurred, approximately $4.5 million was capitalized in 2010 and approximately $0.1 million was capitalized in 2011.
The Partnership maintains property damage insurance under CVR Energy’s insurance policies which have an associated deductible of $2.5 million. The Partnership anticipates that substantially all of the repair costs in excess of the $2.5 million deductible should be covered by insurance. As of December 31, 2011, approximately $7.0 million of insurance proceeds have been received under the property damage insurance related to this incident. Approximately $2.7 million of these proceeds were received during the year ended December 31, 2011. The remaining $4.3 million was received during December 2010. The recording of the insurance proceeds resulted in a reduction of direct operating expenses (exclusive of depreciation and amortization).
The insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Partnership has incurred relating to the damage and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. A partial business interruption claim was filed during 2011 resulting in receipt of proceeds totaling $3.4 million for the year ended December 31, 2011. The proceeds associated with the business interruption claim are included on the Consolidated Statements of Operations under Insurance recovery—business interruption.
| (8) | Goodwill and Intangible Assets |
Goodwill
In connection with the 2005 acquisition by CALLC of all outstanding stock owned by Coffeyville Holdings Group, LLC, CRNF recorded goodwill of approximately $40,969,000. Goodwill and other intangible assets
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accounting standards provide that goodwill and other intangible assets with indefinite lives shall not be amortized but shall be tested for impairment on an annual basis. In accordance with these standards, CVR Partners completed its annual test for impairment of goodwill as of November 1, 2011 and 2010. Based on the results of the test, no impairment of goodwill was recorded as of December 31, 2011, 2010 or 2009.
In 2011, the Partnership elected early adoption of ASU 2011 – 08, which allows an alternative in certain situations that simplifies the impairment testing of goodwill. The new guidance allows an entity the option to first perform a qualitative evaluation to determine whether it is necessary to perform the quantitative two-step goodwill impairment analysis.
The Partnership began the qualitative assessment by analyzing the key drivers and other external factors that impact the business in an attempt to determine if any significant events, transactions or other factors had occurred, or were expected to occur, that would impair earnings or competitiveness; therefore impairing the fair value of the Partnership. After assessing the totality of events and circumstances, it was determined that it was not more likely than not that the fair value of the Partnership was less than the carrying value, and so it was not necessary to perform the two-step valuation. The key drivers that were considered in the evaluation of the Partnership’s fair value included:
| • | general economic conditions; |
| • | fertilizer pricing; |
| • | input costs; and |
| • | customer outlook. |
In 2010, the annual review of impairment was performed by comparing the carrying value of the Partnership to its estimated fair value using a combination of the discounted cash flow analysis and market approach.
The valuation analysis used in the analysis utilized a 50% weighting of both income and market approaches as described below:
| • | Income Approach: To determine fair value, the Company discounted the expected future cash flows for the reporting unit utilizing observable market data to the extent available. For the 2010 valuation, the discount rate used was 14.6%, representing the estimated weighted-average costs of capital, which reflects the overall level of inherent risk involved in the reporting unit and the rate of return an outside investor would expect to earn. |
| • | Market-Based Approach: To determine the fair value of the reporting unit, the Company also utilized a market-based approach. The Company used the guideline company method, which focuses on comparing the Company’s risk profile and growth prospects to select reasonably similar companies. |
Other Intangible Assets
Contractual agreements with a fair market value of $145,000 were acquired in 2005 in connection with the acquisition of CALLC of all outstanding stock owned by Coffeyville Holdings Group, LLC. The intangible value of these agreements is amortized over the life of the agreements through September 2019. Amortization expense of $10,000, $10,000 and $10,000, was recorded in depreciation and amortization for the years ended December 31, 2011, 2010 and 2009, respectively.
| (9) | Deferred Financing Costs |
On April 13, 2011, CRNF, as borrower, and the Partnership, as guarantor, entered into a new credit facility with a group of lenders. The credit facility includes a term loan facility of $125.0 million and a revolving credit
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facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. The credit facility matures in April 2016. The credit facility will be used to finance on-going working capital, capital projects, letter of credit issuances and general needs of the Partnership. In connection with the credit facility, the Partnership incurred lender and other third party costs of approximately $4.8 million. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.
For the year ended December 31, 2011, amortization of deferred financing costs reported as interest expense and other financing costs totaled approximately $0.7 million.
Deferred financing costs consisted of the following:
| Year Ended December 31, 2011 | ||||
| (in thousands) | ||||
| Deferred financing costs |
$ | 4,824 | ||
| Less accumulated amortization |
694 | |||
|
|
|
|||
| Unamortized deferred financing costs |
4,130 | |||
| Less current portion |
966 | |||
|
|
|
|||
| $ | 3,164 | |||
|
|
|
|||
| (10) | Accrued Expenses and Other Current Liabilities |
Accrued expenses and other current liabilities were as follows:
| December 31, 2011 |
December 31, 2010 |
|||||||
| (in thousands) | ||||||||
| Property taxes |
$ | 7,025 | $ | 7,025 | ||||
| Capital asset and dismantling obligation |
4,187 | 250 | ||||||
| Other current liabilities (interest rate swap) |
905 | — | ||||||
| Accrued interest |
885 | — | ||||||
| Other accrued expenses and liabilities(1) |
1,820 | 535 | ||||||
|
|
|
|
|
|||||
| $ | 14,822 | $ | 7,810 | |||||
|
|
|
|
|
|||||
| (1) | Other accrued expenses and liabilities include amounts owed by the Partnership to Coffeyville Resources Refining & Marketing, LLC (“CRRM”), a related party, under the feedstock and shared services agreement. See Note 18 (“Related Party Transactions”) for additional discussion of amounts the Partnership owes related to the feedstock and shared services agreement. |
| (11) | Credit Facility |
Concurrently with the closing of the Initial Public Offering, on April 13, 2011, CRNF as borrower and CVR Partners as guarantor, entered into a new credit facility with a group of lenders including Goldman Sachs Lending Partners LLC, as administrative and collateral agent. The credit facility includes a term loan facility of $125.0 million and a revolving credit facility of $25.0 million with an uncommitted incremental facility of up to $50.0 million. No amounts were outstanding under the revolving credit facility at December 31, 2011. There is no scheduled amortization and the credit facility matures in April 2016. The credit facility is used to finance on-going working capital, capital expenditures, letters of credit issuances and general needs of the Partnership.
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The Partnership, upon the closing of the new credit facility, made a special distribution to CRLLC of approximately $87.2 million in order to, among other things, fund the offer to purchase CRLLC’s senior secured notes required upon consummation of the Initial Public Offering.
Borrowings under the credit facility bear interest based on a pricing grid determined by the trailing four quarter leverage ratio. The initial pricing for borrowings under the credit facility was the Eurodollar rate plus a margin of 3.75%, or, for base rate loans, the prime rate plus 2.75%, based on the schedule below. Currently, the pricing is the Eurodollar rate plus a margin of 3.5%, or, for base rate loans, the prime rate plus 2.5%. Under its terms, the lenders under the credit facility were granted a perfected, first priority security interest (subject to certain customary exceptions) in substantially all of the assets of CVR Partners and CRNF and all of the capital stock of CRNF and each domestic subsidiary owned by CVR Partners or CRNF.
| Leverage Ratio |
Applicable Margin for Base Rate Loans |
Applicable Margin
for Eurodollar Rate Loans |
||||||
| ³ 3.00:1.00 |
3.25 | % | 4.25 | % | ||||
| < 3.00:1.00 ³ 2.00:1.00 |
3.00 | % | 4.00 | % | ||||
| < 2.00:1.00 ³ 1.00:1.00 |
2.75 | % | 3.75 | % | ||||
| < 1.00:1.00 |
2.50 | % | 3.50 | % | ||||
The credit facility requires CVR Partners to maintain a minimum interest coverage ratio and a maximum leverage ratio and contains customary covenants for a financing of this type that limit, subject to certain exceptions, the incurrence of additional indebtedness or guarantees, creation of liens on assets, and the ability to dispose assets, make restricted payments, investments or acquisitions, enter into sale-leaseback transactions or enter into affiliate transactions. The credit facility provides that the Partnership can make distributions to holders of the Partnership’s common units provided the Partnership is in compliance with our leverage ratio and interest coverage ratio covenants on a pro forma basis after giving effect to such distribution and there is no default or event of default under the facility.
As of December 31, 2011, CRNF was in compliance with the covenants of the credit facility.
In connection with the credit facility, through December 31, 2011, the Partnership has incurred lender and other third party costs of approximately $4.8 million. The costs associated with the credit facility have been deferred and are being amortized over the term of the credit facility as interest expense using the effective-interest amortization method for the term loan facility and the straight-line method for the revolving credit facility.
| (12) | Interest Rate Swap |
On June 30 and July 1, 2011 CRNF entered into two floating-to-fixed interest rate swap agreements for the purpose of hedging the interest rate risk associated with a portion of its $125 million floating rate term debt which matures in April 2016. The aggregate notional amount covered under these agreements totals $62.5 million (split evenly between the two agreement dates) and commenced on August 12, 2011 and expires on February 12, 2016. Under the terms of the interest rate swap agreement entered into on June 30, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.94%. Under the terms of the interest rate swap agreement entered into on July 1, 2011, CRNF receives a floating rate based on three month LIBOR and pays a fixed rate of 1.975%. Both swap agreements will be settled every 90 days. The effect of these swap agreements is to lock in a fixed rate of interest of approximately 1.96% plus the applicable margin paid to lenders over three month LIBOR as governed by the CRNF credit agreement. At December 31, 2011, the
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effective rate was approximately 4.69%. The agreements were designated as cash flow hedges at inception and accordingly, the effective portion of the gain or loss on the swap is reported as a component of accumulated other comprehensive income (loss) (“AOCI”), and will be reclassified into interest expense when the interest rate swap transaction affects earnings. The ineffective portion of the gain or loss will be recognized immediately in current interest expense. The interest expense re-classed from AOCI into earnings was $0.4 million for the year ended December 31, 2011.
| (13) | Net Income Per Common Unitholder |
The net income per unit figures on the Consolidated Statement of Operations are based on the net income of the Partnership after the closing of the Initial Public Offering on April 13, 2011 through December 31, 2011, since this is the amount of net income that is attributable to the common units.
The Partnership’s net income is allocated wholly to the common unitholders as the general partner does not have an economic interest.
Basic and diluted net income per common unitholder is calculated by dividing net income by the weighted-average number of common units outstanding during the period and, when applicable, gives effect to phantom units and unvested common units granted under the CVR Partners LTIP. The common units issued during the period are included on a weighted-average basis for the days in which they were outstanding.
The following table illustrates the Partnership’s calculation of net income per common unitholder (in thousands, except per unit information):
| April 13,
2011 to December 31, 2011 |
||||
| Net income (from close of the Initial Public Offering on April 13, 2011 to December 31, 2011) |
$ | 108,351 | ||
|
|
|
|||
| Net income per common unit, basic |
$ | 1.48 | ||
|
|
|
|||
| Net income per common unit, diluted |
$ | 1.48 | ||
|
|
|
|||
| Weighted-average common units outstanding, basic |
73,008 | |||
|
|
|
|||
| Weighted-average common units outstanding, diluted |
73,073 | |||
|
|
|
|||
The Partnership has omitted net income per unit data for all periods other than the twelve months ended December 31, 2011, as the Partnership operated under a different capital structure prior to the closing of the Initial Public Offering on April 13, 2011; therefore, the per unit information is not meaningful to investors.
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| (14) | Comprehensive Income (Loss) |
We have other comprehensive income (loss) resulting from fair value adjustments to our cash flow hedges. Our comprehensive income is as follows:
| Year Ended December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| (in thousands) | ||||||||||||
| Net income |
$ | 132,447 | $ | 33,306 | $ | 57,878 | ||||||
| Other comprehensive income (loss): |
||||||||||||
| Change in fair value of cash flow hedge |
(2,783 | ) | — | — | ||||||||
| Reclassification adjustment to net income on partial settlement of cash flow hedge |
395 | — | — | |||||||||
|
|
|
|
|
|
|
|||||||
| Other comprehensive income (loss) |
(2,388 | ) | — | — | ||||||||
|
|
|
|
|
|
|
|||||||
| Comprehensive income |
$ | 130,059 | $ | 33,306 | $ | 57,878 | ||||||
|
|
|
|
|
|
|
|||||||
| (15) | Income Taxes |
The State of Texas enacted a franchise tax that required the Partnership to pay a tax of 1.0% on the Partnership’s “margin” beginning with the 2008 taxable year, as defined in the law, based on the Partnership’s prior year results. The margin to which the tax rate is applied generally is calculated as the Texas percentage of the Partnership’s revenues for federal income tax purposes less the cost of the products sold as defined by Texas law.
Under ASC Topic 740, Income Taxes (“ASC 740”), taxes based on income like the Texas franchise tax are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized.
Temporary differences related to the Partnership’s property affect the Texas franchise tax. As a result, the Partnership reflected a deferred tax liability in the amount of approximately $36,000 and $37,000 at December 31, 2011 and 2010, respectively, included in the Consolidated Balance Sheets of the Partnership. In addition, the Partnership reflected state income taxes payable of approximately $31,000 and $17,000 at December 31, 2011 and 2010, respectively, included in accrued expenses and other current liabilities on the Consolidated Balance Sheets of the Partnership. For the years ended December 31, 2011, 2010 and 2009, the Partnership recorded income tax expense of $28,000, $26,000 and $15,000, respectively.
| (16) | Benefit Plans |
CRLLC sponsors and administers a defined-contribution 401(k) plan (the “Plan”) for the employees of CRNF. Participants in the Plan may elect to contribute up to 50% of their annual salaries, and up to 100% of their annual bonus received pursuant to CVR Energy’s income sharing plan. CRNF matches up to 75% of the first 6% of the participant’s contribution. Participants in the Plan are immediately vested in their individual contributions. The Plan has a three year vesting schedule for CRNF’s matching funds and contains a provision to count service with any predecessor organization. For the years ended December 31, 2011, 2010 and 2009, CRNF’s contributions under the Plan were $0.4 million, $0.4 million and $0.4 million, respectively.
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| (17) | Commitments and Contingencies |
Leases and Unconditional Purchase Obligations
The minimum required payments for operating leases and unconditional purchase obligations are as follows:
| Operating Leases |
Unconditional Purchase Obligations(1) |
|||||||
| (in thousands) | ||||||||
| Year ending December 31, 2012 |
$ | 5,499 | $ | 21,782 | ||||
| Year ending December 31, 2013 |
6,037 | 22,880 | ||||||
| Year ending December 31, 2014 |
4,678 | 23,092 | ||||||
| Year ending December 31, 2015 |
4,200 | 22,645 | ||||||
| Year ending December 31, 2016 |
3,813 | 23,179 | ||||||
| Thereafter |
8,206 | 205,541 | ||||||
|
|
|
|
|
|||||
| $ | 32,433 | $ | 319,119 | |||||
|
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| (1) | The Partnership’s purchase obligation for pet coke from CVR Energy has been derived from a calculation of the average pet coke price paid to CVR Energy over the preceding two year period. |
CRNF leases railcars and facilities under long-term operating leases. Lease expense for the years ended December 31, 2011, 2010 and 2009, totaled approximately $3.8 million, $4.1 million and $4.0 million, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CRNF’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire. CRNF entered into a lease agreement, in September 2011, for 150 UAN railcars that will be used in conjunction with the UAN expansion. This agreement is effective November 2012.
CRNF also renewed a lease agreement in October 2011 that is effective April 2012, for ninety-seven railcars. The Partnership also amended a portion of a lease agreement in conjunction with improvements to be made to seventy-three UAN railcars.
CRNF has an agreement with the City of Coffeyville (the “City”) pursuant to which it must make a series of future payments for the supply, generation and transmission of electricity and City margin based upon agreed upon rates. This agreement expires on July 1, 2019. Effective August 2008 and through July 2010, the City began charging a higher rate for electricity than what had been agreed to in the contract. CRNF filed a lawsuit to have the contract enforced as written and to recover other damages. CRNF paid the higher rates under protest and subject to the lawsuit in order to obtain the electricity. In August 2010, the lawsuit was settled and CRNF received a return of funds totaling approximately $4.8 million. This return of funds was recorded in direct operating expenses (exclusive of depreciation and amortization) in the Consolidated Statements of Operations during the third quarter of 2010. In connection with the settlement, the electrical services agreement was amended. As a result of the amendment, the annual committed contractual payments are estimated to be approximately $1.9 million. As of December 31, 2011 and 2010, the estimated remaining obligation of CRNF totaled approximately $14.9 million and $16.5 million, respectively, through July 1, 2019. These estimates are subject to change based upon CRNF’s actual usage.
During 2005, CRNF entered into the Amended and Restated On-Site Product Supply Agreement with The BOC Group, Inc. (as predecessor in interest to Linde LLC). Pursuant to the agreement, which expires in 2020, CRNF is required to take as available and pay approximately $300,000 per month, which amount is subject to annual inflation adjustments, for the supply of oxygen and nitrogen to the fertilizer operation. Expenses
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associated with this agreement are included in direct operating expenses (exclusive of depreciation and amortization) and for the years ended December 31, 2011, 2010 and 2009, totaled approximately $4.2 million, $4.7 million and $4.1 million, respectively.
CRNF entered into a sales agreement with Cominco Fertilizer Partnership on November 20, 2007 to purchase equipment and materials which comprise a nitric acid plant. CRNF’s obligation related to the execution of the agreement in 2007 for the purchase of the assets was $3.5 million. On May 25, 2009, CRNF and Cominco amended the contract increasing the liability to approximately $4.3 million, of which approximately $2.3 million has been paid. In consideration of the increased liability, the timeline for removal of the equipment and payment schedule was extended. The amendment sets forth payment milestones based upon the timing of removal of identified assets. The balance of the assets purchased is now anticipated to be removed during the first quarter of 2012. Additionally, as of December 31, 2011, approximately $2.9 million was accrued for the dismantling and removal of the unit. As of December 31, 2011, the Partnership had accrued a total of approximately $4.9 million with respect to the nitric acid plant and the related dismantling obligation, which was included in accrued expenses and other current liabilities. The related asset amounts are included in construction-in-progress at December 31, 2011.
CRNF entered into a lease agreement effective October 25, 2007 with CVR Energy under which certain office and laboratory space is leased. This lease agreement was amended and restated in connection with the Initial Public Offering and extended through October 2017. The agreement requires CRNF to pay approximately $8,700 (rate as of December 31, 2011) on the first day of each calendar month with annual increase. See Note 18 (“Related Party Transactions”) for further discussion.
On February 22, 2011, CRLLC entered into a $250.0 million ABL credit facility. At April 13, 2011, CRLLC’s first lien senior secured notes had an aggregate principal balance of $247.5 million and CRLLC’s second lien senior secured notes had an aggregate principal balance of $225.0 million. The Partnership and CRNF were each released from their obligation as a guarantor or obligor, as applicable, under CRLLC’s ABL credit facility, first lien senior secured notes and second lien senior secured notes as a result of the closing of the Initial Public Offering.
Litigation
From time to time, the Partnership is involved in various lawsuits arising in the normal course of business, including matters such as those described below under “Environmental, Health, and Safety (“EHS”) Matters.” Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the Partnership has accrued for losses for which it may ultimately be responsible. It is possible that management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.
CRNF received a ten year property tax abatement from Montgomery County, Kansas in connection with the construction of the nitrogen fertilizer plant that expired on December 31, 2007. In connection with the expiration of the abatement, the county reassessed CRNF’s nitrogen fertilizer plant and classified the nitrogen fertilizer plant as almost entirely real property instead of almost entirely personal property. The reassessment resulted in an increase in CRNF’s annual property tax expense by an average of approximately $10.7 million per year for the years ended December 31, 2008 and December 31, 2009, $11.7 million for the year ended December 31, 2010 and $11.4 million for the year ended December 31, 2011. CRNF does not agree with the county’s classification
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of its nitrogen fertilizer plant and is currently disputing it before the Kansas Court of Tax Appeals, or COTA. However, CRNF has fully accrued and paid the property taxes the county claims are owed for the years ended December 31, 2010, 2009 and 2008, and has fully accrued such amounts for the year ended December 31, 2011. The first payment in respect of CRNF’s 2011 property taxes was paid in December 2011 and the second payment will be made in May 2012. This property tax expense is reflected as a direct operating expense in the Partnership’s financial results. In January 2012 COTA issued a ruling indicating that the assessment in 2008 of CRNF’s fertilizer plant as almost entirely real property instead of almost entirely personal property was appropriate. CRNF disagrees with the ruling, filed a petition for reconsideration with COTA (which was denied) and plans to file an appeal to the Kansas Court of Appeals. CRNF is also protesting the valuation of the CRNF fertilizer plant for tax years 2009 – 2011, which cases remain pending before COTA. If CRNF is successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then a portion of the accrued and paid expenses would be refunded to CRNF, which could have a material positive effect on the Partnership’s results of operations. If CRNF is not successful in having the nitrogen fertilizer plant reclassified as personal property, in whole or in part, then CRNF expects that it will continue to pay property taxes at elevated rates.
Environmental, Health, and Safety (“EHS”) Matters
CRNF is subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.
CRNF owns and operates a facility utilized for the manufacture of nitrogen fertilizers. Therefore, CRNF has exposure to potential EHS liabilities related to past and present EHS conditions at this location.
From time to time, the United States Environmental Protection Agency (“EPA”) has conducted inspections and issued information requests to CRNF with respect to CRNF’s compliance with the Clean Air Act’s “Risk Management Program” and the release reporting requirements under the Comprehensive Environmental Response, Compensation, and Liability Act and the Emergency Planning and Community Right-to-Know Act. These previous investigations have resulted in the issuance of preliminary findings regarding CRNF’s compliance status. In the fourth quarter of 2010, following CRNF’s reported release of ammonia from its cooling water system and the rupture of its UAN vessel (which released ammonia and other regulated substances) the EPA conducted its most recent inspection and issued an additional request for information to CRNF. The EPA has not made any formal claims against CRNF and CRNF has not accrued for any liability associated with the investigations or releases.
Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. Capital expenditures for the years ended December 31, 2011, 2010 and 2009, were approximately $0.2 million, $0.2 million and $0.9 million, respectively. These expenditures were incurred to improve the environmental compliance and efficiency of the operations. CRNF believes it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.
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| (18) | Related Party Transactions |
Related Party Agreements, effective October 25, 2007
In connection with the formation of CVR Partners and the initial public offering of CVR Energy in October 2007, CVR Partners and CRNF entered into several agreements with CVR Energy and its subsidiaries (including CRRM) that govern the business relations among CVR Partners, its general partner and CRNF on the one hand, and CVR Energy and its subsidiaries, on the other hand. Certain of the agreements described below were amended and restated on April 13, 2011 in connection with the Initial Public Offering; the agreements are described as in effect at December 31, 2011. Amounts owed to CVR Partners and CRNF from CVR Energy and its subsidiaries with respect to these agreements are included in prepaid expenses and other currents assets, and other long-term assets, on the Consolidated Balance Sheets. Conversely, amounts owed to CVR Energy and its subsidiaries by CVR Partners and CRNF with respect to these agreements are included in accounts payable, accrued expenses and other current liabilities, and other long-term liabilities, on the Partnership’s Consolidated Balance Sheets.
Feedstock and Shared Services Agreement
CRNF entered into a feedstock and shared services agreement with CRRM under which the two parties provide feedstock and other services to one another. These feedstocks and services are utilized in the respective production processes of CRRM’s Coffeyville, Kansas refinery and CRNF’s nitrogen fertilizer plant.
Pursuant to the feedstock agreement, CRNF and CRRM have the obligation to transfer excess hydrogen to one another. Net monthly sales of hydrogen to CRRM have been reflected as net sales for CVR Partners. Net monthly receipts of hydrogen from CRRM have been reflected in cost of product sold (exclusive of depreciation and amortization) for CVR Partners. For the years ended December 31, 2011, 2010 and 2009, the net sales generated from the sale of hydrogen to CRRM were approximately $14.2 million, $0.1 million and $0.8 million, respectively. For the years ended December 31, 2011, 2010 and 2009, CVR Partners also recognized $1.0 million, $1.8 million and $1.6 million of cost of product sold (exclusive of depreciation and amortization) related to the transfer of excess hydrogen from the refinery, respectively. At December 31, 2011 and 2010, there was approximately $0.1 million and $0, respectively, of receivables included in prepaid expenses and other current assets on the Consolidated Balance Sheets associated with unpaid balances related to hydrogen sales.
The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net reimbursed or (paid) direct operating expenses recorded during the years ended December 31, 2011, 2010 and 2009 were approximately $(0.3) million, $(0.1) million and $0.2 million, respectively, related to high-pressure steam. Reimbursements or paid amounts for each of the years on a gross basis were nominal.
CRNF is also obligated to make available to CRRM any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by CRNF in a commercially reasonable manner. Reimbursed direct operating expenses associated with nitrogen for the years ended December 31, 2011, 2010 and 2009, were approximately $1.5 million, $0.8 million and $0.8 million, respectively. No amounts were paid by CRNF to CRRM for any of the years.
The agreement also provides a mechanism pursuant to which CRNF transfers a tail gas stream to CRRM. CRNF receives the benefit of eliminating a waste gas stream and recovers the fuel value of the tail gas system. For the year ended December 31, 2011, there were net sales of approximately $48,000 generated from the sale of tail gas to CRRM.
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In April 2011, in connection with the tail gas stream, CRRM installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. CRNF has agreed to pay CRRM the cost of installing the pipe over the next three years and in the fourth year provide an additional 15% to cover the cost of capital. At December 31, 2011, an asset of approximately $0.2 million was included in other current assets and approximately $1.5 million was included in other non-current assets with an offset liability of approximately $0.6 million in other current liabilities and approximately $0.9 million other non-current liabilities in the Consolidated Balance Sheet.
CRNF also provided finished product tank capacity to CRRM under the agreement. Approximately $0.3 million was reimbursed by CRRM for the use of tank capacity for the year ended December 31, 2011. This reimbursement was recorded as a reduction to direct operating expenses. No amounts were received in prior years.
The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
At December 31, 2011 and 2010, receivables of $0.3 million and $0.3 million, respectively, were included in prepaid expenses and other current assets on the Consolidated Balance Sheets associated for amounts yet to be received related to components of the feedstock and shared services agreement other than amounts related to hydrogen sales and pet coke purchases. At December 31, 2011 and 2010, payables of $0.3 million and $0.6 million, respectively, were included in accounts payable on the Consolidated Balance Sheets associated with unpaid balances related to components of the feedstock and shared services agreement, other than amounts related to hydrogen sales and pet coke purchases.
Coke Supply Agreement
CRNF entered into a coke supply agreement with CRRM pursuant to which CRRM supplies CRNF with pet coke. This agreement provides that CRRM must deliver to the Partnership during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at CRRM’s Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. CRNF is also obligated to purchase this annual required amount. If during a calendar month CRRM produces more than 41,667 tons of pet coke, then CRNF will have the option to purchase the excess at the purchase price provided for in the agreement. If CRNF declines to exercise this option, CRRM may sell the excess to a third party.
CRNF obtains most (over 70% on average during the last five years) of the pet coke it needs from CRRM’s adjacent crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price CRNF 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.
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CRNF will also pay any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. CRNF will be entitled to offset any amount payable for the pet coke against any amount due from CRRM under the feedstock and shared services agreement between the parties.
The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
Cost of pet coke associated with the transfer of pet coke from CRRM to CRNF was approximately $10.7 million, $4.0 million and $7.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Payables of $1.0 million and $0.3 million related to the coke supply agreement were included in accounts payable on the Consolidated Balance Sheets at December 31, 2011, and 2010, respectively.
Lease Agreement
CRNF entered into a lease agreement with CRRM under which it leases certain office and laboratory space. The initial term of the lease will expire in October 2017, provided, however, that CRNF may terminate the lease at any time during the initial term by providing 180 days prior written notice. In addition, CRNF has the option to renew the lease agreement for up to five additional one-year periods by providing CRRM with notice of renewal at least 60 days prior to the expiration of the then existing term. For the years ended December 31, 2011, 2010 and 2009, expense incurred related to the use of the office and laboratory space totaled approximately $102,000, $96,000 and $96,000, respectively. There were no unpaid amounts outstanding with respect to the lease agreement as of December 31, 2011 and 2010, respectively.
Environmental Agreement
CRNF entered into an environmental agreement with CRRM which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville, Kansas refinery and the nitrogen fertilizer plant. Generally, both CRNF and CRRM have agreed to indemnify and defend each other and each other’s affiliates against liabilities associated with certain hazardous materials and violations of environmental laws that are a result of or caused by the indemnifying party’s actions or business operations. This obligation extends to indemnification for liabilities arising out of off-site disposal of certain hazardous materials. Indemnification obligations of the parties will be reduced by applicable amounts recovered by an indemnified party from third parties or from insurance coverage.
The agreement provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement is entered into to the extent such contamination or releases are identified in reasonable detail through October 2012. The agreement further provides for indemnification in the case of contamination or releases which occur subsequent to the execution of the agreement.
The term of the agreement is for at least 20 years, or for so long as the feedstock and shared services agreement is in force, whichever is longer.
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Services Agreement
CVR Partners obtains certain management and other services from CVR Energy pursuant to a services agreement between the Partnership, CVR GP, LLC and CVR Energy. Under this agreement, the Partnership’s general partner has engaged CVR Energy to conduct its day-to-day business operations. CVR Energy provides CVR Partners with the following services under the agreement, among others:
| • | services from CVR Energy’s employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall serve the Partnership on a shared, part-time basis only, unless the Partnership and CVR Energy agree otherwise; |
| • | administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
| • | management of the Partnership’s property and the property of its operating subsidiary in the ordinary course of business; |
| • | recommendations on capital raising activities to the board of directors of the Partnership’s general partner, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions; |
| • | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice; |
| • | recommending the payment of distributions; and |
| • | managing or providing advice for other projects, including the acquisitions, as may be agreed by CVR Energy and its general partner from time to time. |
As payment for services provided under the agreement, the Partnership, its general partner or CRNF must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other than administrative personnel, who provide the Partnership services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide the Partnership services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percentage of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges.
Either CVR Energy or the Partnership’s general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. Beginning in April 2012, either CVR Energy or the Partnership’s general partner may terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, the Partnership’s general partner may terminate the agreement immediately if CVR Energy becomes bankrupt or dissolves or commences liquidation or winding-up procedures.
In order to facilitate the carrying out of services under the agreement, CVR Partners and CVR Energy have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.
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Net amounts incurred under the services agreement for the years ended December 31, 2011, 2010 and 2009, were approximately $10.2 million, $10.6 million and $12.1 million, respectively. Of these charges approximately $8.2 million, $8.5 million and $9.3 million, respectively, are included in selling, general and administrative expenses (exclusive of depreciation and amortization). In addition, $2.0 million, $2.1 million and $2.8 million, respectively, are included in direct operating expenses (exclusive of depreciation and amortization). For services performed in connection with the services agreement, the Company recognized personnel costs of $4.6 million, $3.4 million and $3.7 million, respectively, for the years ended December 31, 2011, 2010 and 2009. At December 31, 2011 and 2010, payables of $0.7 million and $2.4 million, respectively, were included in accounts payable on the Consolidated Balance Sheets with respect to amounts billed in accordance with the services agreement.
GP Services Agreement
The Partnership is party to a GP Services Agreement dated November 29, 2011 between the Partnership, CVR GP, LLC and CVR Energy. This agreement allows CVR Energy to engage CVR GP, LLC, in its capacity as the Partnership’s general partner, to provide CVR Energy with (i) business development and related services and (ii) advice or recommendations for such other projects as may be agreed between the Partnership’s general partner and CVR Energy from time to time. As payment for services provided under the agreement, CVR Energy must pay a prorated share of costs incurred by the Partnership or its general partner in connection with the employment of the Partnership’s employees who provide CVR Energy services on a part-time basis, as determined by the Partnership’s general partner on a commercially reasonable basis based on the percentage of total working time that such shared personnel are engaged in performing services for CVR Energy. Pursuant to this GP Services Agreement, one of the Partnership’s executive officers has performed business development services for CVR Energy from time to time.
CVR Energy is not required to pay any compensation, salaries, bonuses or benefits to any of the Partnership’s general partner’s employees who provide services to CVR Energy on a full-time or part-time basis; the Partnership will continue to pay their compensation.
Either CVR Energy or the Partnership’s general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. The Partnership’s general partner also has the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation does not relieve the Partnership’s general partner from its obligations under the agreement. Either CVR Energy or the Partnership’s general partner may terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, CVR Energy may terminate the agreement immediately if the Partnership, or its general partner, become bankrupt, or dissolve and commence liquidation or winding-up.
Limited Partnership Agreement
In connection with the Initial Public Offering, CVR GP and CRLLC entered into the second amended and restated agreement of limited partnership of the Partnership, dated April 13, 2011.
The Partnership’s general partner manages the Partnership’s operations and activities as specified in the partnership agreement. The general partner of the Partnership is managed by its board of directors. CRLLC has the right to select the directors of the general partner. Actions by the general partner that are made in its individual capacity are made by CRLLC as the sole member of the general partner and not by its board of directors. The members of the board of directors of the general partner are not elected by the unitholders and are not subject to re-election on a regular basis in the future. The officers of the general partner manage the day-to-day affairs of the Partnership’s business.
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The partnership agreement provides that the Partnership will reimburse its general partner for all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person to perform services for the Partnership or for its general partner in connection with operating the Partnership). The Partnership reimbursed its general partner for the year ended December 31, 2011 approximately $1.4 million, pursuant to the partnership agreement for personnel costs related to the compensation of executives at the general partner, who manage the Partnership’s business. For the years ended December 31, 2010 and 2009, the Partnership did not make any reimbursement payments to its general partner. At December 31, 2011 and 2010, payables of $0.8 million and $0, respectively, were included in accounts payable related to personnel costs on the Consolidated Balance Sheets with respect to amounts outstanding in accordance with the limited partnership agreement.
Due from Affiliate
CVR Partners historically supplemented CRLLC’s working capital needs. CVR Partners had the right to receive such amounts from CRLLC upon request.
On December 31, 2010, the due from affiliate balance was reduced to $0 as a result of the due from affiliate balance of $160.0 million being distributed by the Partnership to CRLLC and the special general partner. At December 31, 2011 and 2010, included in prepaid expenses and other current assets on the Consolidated Balance Sheets are receivables of approximately $0 and $2.3 million, respectively, for accrued interest with respect to amounts due from affiliate. For the year ended December 31, 2011 the Partnership recognized no interest income associated with the due from affiliate balance compared to approximately $13.1 million, for the year ended December 31, 2010.
Distributions to CRLLC
The Partnership distributed $49.9 million for the year ended December 31, 2011, as regular distributions on CRLLC’s ownership of common units subsequent to the Initial Public Offering. As discussed in Note 6 (“Partners’ Capital and Partnership Distribution”), the Partnership made cash distributions of approximately $276.7 million to CRLLC prior to and at the time of the Partnership’s Initial Public Offering.
| (19) | Fair Value of Financial Instruments |
The book values of cash and cash equivalents, accounts receivable and accounts payable are considered to be representative of their respective fair values due to the immediate short–term maturity of these financial instruments. The carrying value of the Partnership’s debt approximates fair value.
The fair values of financial instruments are estimated based upon current market conditions and quoted market prices for the same or similar instruments. Management estimates that the carrying value approximates fair value for all of the Partnerships’ assets and liabilities that fall under the scope of ASC 825, Financial Instruments (ASC825).
Fair value measurements are derived using inputs (assumptions that market participants would use in pricing an asset or liability) including assumptions about risk. FASB ASC 820 categorizes inputs used in fair value measurements into three broad levels as follows:
| • | (Level 1) Quoted prices in active markets for identical assets or liabilities. |
| • | (Level 2) Observable inputs other than quoted prices included in Level 1, such as quoted prices for similar assets and liabilities in active markets, similar assets and liabilities in markets that are not active or can be corroborated by observable market data. |
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| • | (Level 3) Unobservable inputs that are supported by little or no market activity and that are significant to the fair value of the assets or liabilities. This includes valuation techniques that involve significant unobservable inputs. |
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of December 31, 2011. At December 31, 2010, the Partnership did not have any assets or liabilities measured at fair value on a recurring level.
| December 31, 2011 | ||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||
| (in thousands) | ||||||||||||||||
| Location and Description |
||||||||||||||||
| Cash equivalents (money market account) |
$ | 160,030 | $ | — | $ | — | $ | 160,030 | ||||||||
| Other current assets (marketable securities) |
— | — | — | — | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total Assets |
$ | 160,030 | $ | — | $ | — | $ | 160,030 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Other current liabilities (interest rate swap) |
$ | — | $ | 905 | $ | — | $ | 905 | ||||||||
| Other long-term liabilities (interest rate swap) |
— | 1,483 | — | 1,483 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total Liabilities |
$ | — | $ | 2,388 | $ | — | $ | 2,388 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Accumulated other comprehensive loss (interest rate swap) |
$ | — | $ | 2,388 | $ | — | $ | 2,388 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
As of December 31, 2011, the only financial assets and liabilities that are measured at fair value on a recurring basis are the Partnership’s money market accounts and derivative instruments. The carrying value of the Partnership’s debt approximates fair value. The Partnership has an interest rate swap that is measured at fair value on a recurring basis using Level 2 inputs (see Note 12 “Interest Rate Swap”). The Partnership had no transfers of assets or liabilities between any of the above levels during the year ended December 31, 2011.
The Partnership’s cash and cash equivalent are all Level 1.
The fair values of these interest rate swap instruments are based on discounted cash flow models that incorporate the cash flows of the derivatives, as well as the current LIBOR rate and a forward LIBOR curve, along with other observable market inputs.
| (20) | Major Customers and Suppliers |
Sales of nitrogen fertilizer to major customers were as follows:
| December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Nitrogen Fertilizer |
||||||||||||
| Customer A |
17 | % | 12 | % | 15 | % | ||||||
| Customer B |
12 | % | 10 | % | 9 | % | ||||||
|
|
|
|
|
|
|
|||||||
| 29 | % | 22 | % | 24 | % | |||||||
|
|
|
|
|
|
|
|||||||
In addition to contracts with CVR Energy and its affiliates see Note 18 (“Related Party Transactions”), the Partnership maintains long-term contracts with one supplier. Purchases from this supplier as a percentage of direct operating expenses (exclusive of depreciation and amortization) were as follows:
| December 31, | ||||||||||||
| 2011 | 2010 | 2009 | ||||||||||
| Supplier A |
5 | % | 5 | % | 5 | % | ||||||
111
Table of Contents
CVR PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| (21) | Selected Quarterly Financial Information (Unaudited): |
Summarized quarterly financial date for December 31, 2011 and 2010:
| Year Ended December 31, 2011 | ||||||||||||||||
| Quarter | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| (in thousands, except unit data) | ||||||||||||||||
| Net sales |
$ | 57,377 | $ | 80,673 | $ | 77,203 | $ | 87,614 | ||||||||
| Operating costs and expenses: |
||||||||||||||||
| Cost of products sold (exclusive of depreciation and amortization) - Affiliates |
1,469 | 2,866 | 3,642 | 3,680 | ||||||||||||
| Cost of product sold (exclusive of depreciation and amortization) - Third parties |
6,022 | 6,880 | 7,259 | 10,693 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 7,491 | 9,746 | 10,901 | 14,373 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Direct operating expenses (exclusive of depreciation and amortization) - Affiliates |
693 | 155 | 165 | 154 | ||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) - Third parties |
22,331 | 22,111 | 19,918 | 20,964 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 23,024 | 22,266 | 20,083 | 21,118 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Insurance recovery - business interruption |
(2,870 | ) | — | (490 | ) | — | ||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) – Affiliates |
6,398 | 3,249 | 3,438 | 3,364 | ||||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization) - Third parties |
1,931 | 1,418 | 1,094 | 1,266 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 8,329 | 4,667 | 4,532 | 4,630 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Depreciation and amortization |
4,637 | 4,648 | 4,663 | 4,921 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating costs and expenses |
40,611 | 41,327 | 39,689 | 45,042 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
16,766 | 39,346 | 37,514 | 42,572 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Interest expense and other financing costs |
— | (1,238 | ) | (1,378 | ) | (1,391 | ) | |||||||||
| Interest income |
7 | 22 | 29 | 21 | ||||||||||||
| Other income, net |
(29 | ) | 86 | 132 | 16 | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other income (expense) |
(22 | ) | (1,130 | ) | (1,217 | ) | (1,354 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income before income tax expense |
16,744 | 38,216 | 36,297 | 41,218 | ||||||||||||
| Income tax expense |
10 | 5 | 12 | 1 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income |
$ | 16,734 | $ | 38,211 | $ | 36,285 | $ | 41,217 | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income subsequent to initial public offering |
$ | — | $ | 30,849 | $ | 36,285 | $ | 41,217 | ||||||||
| Net income per common unit – basic |
$ | 0.42 | $ | 0.50 | $ | 0.56 | ||||||||||
| Net income per common unit – diluted |
$ | 0.42 | $ | 0.50 | $ | 0.56 | ||||||||||
| Weighted-average common units outstanding: |
||||||||||||||||
| Basic |
73,001 | 73,003 | 73,020 | |||||||||||||
| Diluted |
73,044 | 73,083 | 73,088 | |||||||||||||
112
Table of Contents
CVR PARTNERS, LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| Year Ended December 31, 2010 | ||||||||||||||||
| Quarter | ||||||||||||||||
| First | Second | Third | Fourth | |||||||||||||
| (in thousands, except unit data) | ||||||||||||||||
| Net sales |
$ | 38,285 | $ | 56,346 | $ | 46,426 | $ | 39,411 | ||||||||
| Operating costs and expenses: |
||||||||||||||||
| Cost of products sold (exclusive of depreciation and amortization) —Affiliates |
1,006 | 1,140 | 2,940 | 678 | ||||||||||||
| Cost of product sold (exclusive of depreciation and amortization) —Third parties |
3,971 | 10,740 | 7,854 | 5,999 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 4,977 | 11,880 | 10,794 | 6,677 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Direct operating expenses (exclusive of depreciation and amortization) —Affiliates |
494 | 458 | 471 | 885 | ||||||||||||
| Direct operating expenses (exclusive of depreciation and amortization) —Third parties |
21,679 | 20,876 | 16,754 | 25,062 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 22,173 | 21,334 | 17,225 | 25,947 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Business interruption recovery |
— | — | — | — | ||||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization)—Affiliates |
2,982 | 1,457 | 2,391 | 9,918 | ||||||||||||
| Selling, general and administrative expenses (exclusive of depreciation and amortization)—Third parties |
520 | 502 | 930 | 1,942 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| 3,502 | 1,959 | 3,321 | 11,860 | |||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Depreciation and amortization |
4,665 | 4,671 | 4,526 | 4,601 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total operating costs and expenses |
35,317 | 39,844 | 35,866 | 49,085 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Operating income |
2,968 | 16,502 | 10,560 | (9,674 | ) | |||||||||||
| Interest expense and other financing costs |
— | — | — | — | ||||||||||||
| Interest income |
3,119 | 3,467 | 3,033 | 3,505 | ||||||||||||
| Other income, net |
(56 | ) | (18 | ) | (46 | ) | (28 | ) | ||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Total other income (expense) |
3,063 | 3,449 | 2,987 | 3,477 | ||||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Income (loss) before income tax expense |
6,031 | 19,951 | 13,547 | (6,197 | ) | |||||||||||
| Income tax expense (benefit) |
28 | 4 | 3 | (9 | ) | |||||||||||
|
|
|
|
|
|
|
|
|
|||||||||
| Net income (loss) |
$ | 6,003 | $ | 19,947 | $ | 13,544 | $ | (6,188 | ) | |||||||
|
|
|
|
|
|
|
|
|
|||||||||
| (22) | Subsequent Events |
On February 13, 2012, CVR Energy announced its intention to sell a portion of its investment in the Partnership. There can be no assurance as to the terms, conditions, amount or timing of such sale, or whether such sale will take place at all. This announcement does not constitute an offer of any securities for sale and is being made pursuant to and in accordance with Rule 135 under the Securities Act.
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Table of Contents
Item 9. Changes in and Disagreements With Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Evaluation of Disclosure Controls and Procedures. Our management, under the direction of our Executive Chairman, Chief Executive Officer and Chief Financial Officer, evaluated as of December 31, 2011 the effectiveness of our disclosure controls and procedures as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Based upon and as of the date of that evaluation, our Executive Chairman, Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective, at a reasonable assurance level, to ensure that information required to be disclosed in the reports we file and submit under the Exchange Act is recorded, processed, summarized and reported as and when required and is accumulated and communicated to our management, including our Executive Chairman, our Chief Executive Officer and our Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosure. It should be noted that any system of disclosure controls and procedures, however well designed and operated, can provide only reasonable, and not absolute, assurance that the objectives of the system are met. In addition, the design of any system of disclosure controls and procedures is based in part upon assumptions about the likelihood of future events. Due to these and other inherent limitations of any such system, there can be no assurance that any design will always succeed in achieving its stated goals under all potential future conditions.
Changes in Internal Control Over Financial Reporting. There has been no change in our internal control over financial reporting required by Rule 13a-15 of the Exchange Act that occurred during the fiscal quarter ended December 31, 2011 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
None.
114
Table of Contents
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Management of CVR Partners, LP
Our general partner, CVR GP, LLC, manages our operations and activities subject to the terms and conditions specified in our partnership agreement. Our general partner is owned by Coffeyville Resources, a wholly-owned subsidiary of CVR Energy. The operations of our general partner in its capacity as general partner are managed by its board of directors. Actions by our general partner that are made in its individual capacity are made by Coffeyville Resources as the sole member of our general partner and not by the board of directors of our general partner. Our general partner is not elected by our unitholders and is not be subject to re-election on a regular basis in the future. The officers of our general partner manage the day-to-day affairs of our business.
Limited partners are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operation. Our partnership agreement contains various provisions which replace default fiduciary duties with contractual corporate governance standards. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for indebtedness or other obligations that are made expressly non-recourse to it. Our general partner therefore may cause us to incur indebtedness or other obligations that are non-recourse to it. Our credit facility is non-recourse to our general partner.
As a publicly traded partnership, we qualify for certain exemptions from the New York Stock Exchange’s corporate governance requirements. Our general partner’s board of directors has not and does not currently intend to establish a nominating/corporate governance committee. Additionally, we could avail ourselves of the additional exemptions available to publicly traded partnerships (including exemptions from the requirements that the majority of the board consist of independent directors and that the board of directors of our general partner have a compensation committee composed entirely of independent directors) at any time in the future. Accordingly, unitholders do not have the same protections afforded to equityholders of companies that are subject to all of the corporate governance requirements of the New York Stock Exchange.
The board of directors of our general partner consists of seven directors, four of whom the board has affirmatively determined are independent in accordance with the rules of the New York Stock Exchange. The board of directors of our general partner met nine times in 2011.
The board of directors of our general partner has established an audit committee comprised of Donna R. Ecton (chairman), Mark A. Pytosh and Jon R. Whitney, each of whom meets the independence and experience standards established by the New York Stock Exchange and the Exchange Act. The audit committee’s responsibilities are to review our accounting and auditing principles and procedures, accounting functions and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent accountants; to review with the independent accountants the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters. The audit committee met ten times in 2011.
In addition, the board of directors of our general partner has established a conflicts committee comprised of Donna R. Ecton (chairman), Mark A. Pytosh and Jon R. Whitney. Pursuant to our partnership agreement, the board may, but is not required to, seek the approval of the conflicts committee whenever a conflict arises between our general partner or its affiliates, on the one hand, and us or any public unitholder, on the other. The conflicts committee may then determine whether the resolution of the conflict of interest is in the best interest of the Partnership. The members of the conflicts committee may not be officers or employees of our general partner or directors, officers or employees of its affiliates, and must meet the independence standard established by the New York Stock Exchange and the Exchange Act to serve on an audit committee of a board of directors. Any matters approved by the conflicts committee are conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by the general partner of any duties it may owe us or our unitholders. The conflicts committee met three times in 2011.
115
Table of Contents
The board of directors of our general partner also created a compensation committee comprised of Frank M. Muller, Jr. (chairman) and Jon R. Whitney. The compensation committee (1) establishes policies and periodically determines matters involving executive compensation, (2) grants or recommends the grant of equity awards under the CVR Partners LTIP, (3) provides counsel regarding key personnel selection, (4) may elect to retain independent compensation consultants, (5) recommends to the board of directors the structure of non-employee director compensation and (6) assists the board of directors in assessing any risks to the Partnership associated with employee compensation practices and policies. In addition, the compensation committee reviews and discusses our Compensation Discussion and Analysis with management and produces a report on executive compensation for inclusion in our annual report on Form 10-K in compliance with applicable federal securities laws. The compensation committee met four times in 2011.
The board of directors of our general partner has created an environmental, health and safety committee comprised of Mark A. Pytosh (chairman), Donna R. Ecton, Frank M. Muller, Jr. and Stanley A. Riemann. The environmental, health and safety committee’s responsibilities are to provide oversight with respect to management’s establishment and administration of environmental, health and safety policies, programs, procedures and initiatives. The environmental, health and safety committee met two times in 2011.
Whenever our general partner makes a determination or takes or declines to take an action in its individual, rather than representative, capacity, it is entitled to make such determination or to take or decline to take such other action free of any fiduciary duty or obligation whatsoever to us, any limited partner or assignee, and it is not required to act in good faith or pursuant to any other standard imposed by our partnership agreement or under Delaware law or any other law. Examples include the exercise of its call right or its registration rights, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership. Actions by our general partner that are made in its individual capacity are made by Coffeyville Resources, the sole member of our general partner, not by its board of directors.
Compensation Committee Interlocks and Insider Participation
No member of the compensation committee of our general partner is now, or was during 2011, an officer or employee of the Partnership or our general partner.
Executive Officers and Directors
The following table sets forth the names, positions and ages (as of February 20, 2012) of the executive officers and directors of our general partner.
The executive officers named below (other than our chief executive officer and Executive Vice President, Business Development) are also executive officers of CVR Energy and are providing their services to our general partner and us pursuant to the services agreement entered into among us, CVR Energy and our general partner. The shared executive officers divide their working time between the management of CVR Energy and us. The approximate weighted-average percentages of the amount of time the shared executive officers spent on management of our partnership in 2011 are as follows: John J. Lipinski (21%), Stanley A. Riemann (24%), Edward A. Morgan (36%), Edmund S. Gross (30%), Kevan A. Vick (100%) and Christopher G. Swanberg (28%). During 2011, Byron R. Kelley spent 100% of his time working for us and Randal T. Maffett spent 71% of his time working for us as an employee of the general partner. Frank A. Pici was appointed Chief Financial Officer effective January 4, 2012 (in place of Edward A. Morgan, who became CVR Energy’s Executive Vice President – Investor Relations). Kevan A. Vick, Executive Vice President and Fertilizer General Manager, announced his retirement effective February 1, 2012.
| Name |
Age |
Position With Our General Partner | ||||
| John J. Lipinski |
60 | Executive Chairman of the Board and Director | ||||
| Byron R. Kelley |
64 | Chief Executive Officer, President and Director | ||||
| Stanley A. Riemann |
60 | Chief Operating Officer and Director | ||||
| Frank A. Pici |
56 | Chief Financial Officer and Treasurer | ||||
| Edmund S. Gross |
61 | Senior Vice President, General Counsel and Secretary | ||||
| Randal T. Maffett |
51 | Executive Vice President, Business Development | ||||
| Christopher G. Swanberg |
54 | Vice President, Environmental, Health and Safety | ||||
| Donna R. Ecton |
64 | Director | ||||
| Frank M. Muller, Jr. |
69 | Director | ||||
| Mark A. Pytosh |
47 | Director | ||||
| Jon R. Whitney |
67 | Director | ||||
116
Table of Contents
John J. Lipinski has served as executive chairman of the board of our general partner since June 2011. Prior to assuming that role, he served as chief executive officer, president and a director of our general partner beginning in October 2007 and chairman of the board of directors of our general partner beginning in November 2010. He has also served as chairman of the board of directors of CVR Energy since October 2007 and chief executive officer, president and a member of the board of directors of CVR Energy beginning in September 2006. Mr. Lipinski has over 38 years of experience in the petroleum refining and nitrogen fertilizer industries. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation, eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation’s refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen-based chemical processing and lubricant operations, as well as the corporate engineering and construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a managing director and partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski graduated from Stevens Institute of Technology with a Bachelor of Engineering (Chemical) and received a JD from Rutgers University School of Law. Mr. Lipinski’s over 38 years of experience in the petroleum refining and nitrogen fertilizer industries adds significant value to the board of directors of our general partner. His in-depth knowledge of the issues, opportunities and challenges facing our business provides the direction and focus the board needs to ensure the most critical matters are addressed.
Byron R. Kelley has served as chief executive officer, president and a director of our general partner since June 2011. Prior to joining CVR Partners, Mr. Kelley served as Chief Executive Officer, President and director of the general partner of Regency Energy Partners LP, a master limited partnership controlled by Energy Transfer Equity LP that specializes in the gathering and processing, contract compression, treating and transportation of natural gas and natural gas liquids. From 2003 to 2008, Mr. Kelley was Executive Vice President and Group President of the pipeline group of CenterPoint Energy in Houston, a business which included two interstate pipeline companies, a gathering and processing company, a pipeline services company and a remote data gathering and communications company. Prior to CenterPoint Energy, he served for six years in senior management at El Paso Energy International in Houston, retiring in 2002 as the company’s president. With 41 years experience in energy related companies, Mr. Kelley’s career also included executive, management and engineering positions at Tenneco Energy Corporation, where he rose to become Senior Vice President, Strategy, and at Louisiana Intrastate Gas Corporation and Southern Natural Gas Company. Mr. Kelley also is past president of the Interstate Natural Gas Association of America and currently serves as a board advisor to the Bright Light Foundation of Houston and to Martin Midstream Partners L.P. Mr. Kelley received a BS degree in civil engineering from Auburn University.
Stanley A. Riemann has served as chief operating officer of our general partner since October 2007 and has been a director of our general partner since July 2011. He has also served as chief operating officer of CVR Energy since September 2006 and chief operating officer of Coffeyville Resources since 2004. Prior to joining Coffeyville Resources in February 2004, Mr. Riemann held various positions associated with the Crop Production and Petroleum Energy Division of Farmland for over 30 years, including, most recently, Executive Vice President of Farmland and President of Farmland’s Energy and Crop Nutrient Division. In this capacity, he was directly responsible for managing the petroleum refining operation and all domestic fertilizer operations, which included the Trinidad and Tobago nitrogen fertilizer operations. His leadership also extended to managing Farmland’s interests in SF Phosphates in Rock Springs, Wyoming and Farmland Hydro, L.P., a phosphate production operation in Florida and managing all company-wide transportation assets and services. On May 31, 2002, Farmland filed for Chapter 11 bankruptcy protection. Mr. Riemann has served as a board member and board chairman on several industry organizations including the Phosphate Potash Institute, the Florida Phosphate Council and the International Fertilizer Association. He currently serves on the Board of The Fertilizer Institute. Mr. Riemann received a BS from the University of Nebraska and an MBA from Rockhurst University.
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Frank A. Pici has served as chief financial officer and treasurer of our general partner and CVR Energy since January 2012. From 2001 to 2010, he was Executive Vice President and CFO of Penn Virginia Corporate (“PVA”), a publicly traded oil and gas exploration and production company focused on unconventional resource and shale plays. Simultaneously, he served as CFO of Penn Virginia GP Holdings, L.P. and Penn Virginia Resource Partners, L.P. two publicly traded master limited partnerships. Prior to working for PVA, Mr. Pici served five years as Vice President and CFO for Mariner Energy, Inc., an oil and gas exploration and production company operating onshore and in the deepwater Gulf of Mexico. Prior to Mariner Energy, Mr. Pici served for seven years in senior financial management positions at Cabot Oil & Gas Corp., a publicly traded oil and gas exploration and production company. He has an MBA from the University of Pittsburgh and a Business Administration degree from Clarion University and is a Certified Public Accountant (presently inactive).
Edmund S. Gross has served as senior vice president, general counsel and secretary of our general partner since October 2007. He has also served as senior vice president, general counsel and secretary of CVR Energy since October 2007, vice president, general counsel and secretary of CVR Energy since September 2006 and general counsel and secretary of Coffeyville Resources since July 2004. Prior to joining Coffeyville Resources, Mr. Gross was of counsel at Stinson Morrison Hecker LLP in Kansas City, Missouri from 2002 to 2004, was Senior Corporate Counsel with Farmland from 1987 to 2002 and was an associate and later a partner at Weeks, Thomas & Lysaught, a law firm in Kansas City, Kansas, from 1980 to 1987. Mr. Gross received a BA in history from Tulane University, a JD from the University of Kansas and an MBA from the University of Kansas.
Randal T. Maffett has served as Executive Vice President of Business Development for our general partner since August 2011. Prior to joining CVR Partners, Mr. Maffett was President and Chief Executive Officer of Sendero Capital Partners, Inc., a private equity firm focused on investments, acquisitions and operations in the upstream, midstream and downstream sectors of the energy industry from 2004 to 2011. Prior to joining Sendero Capital Partners, Mr. Maffett held senior executive positions at RWE Trading Americas and Enron Corp., where he was responsible for developing and executing corporate growth strategies, corporate turnarounds and corporate restructurings. He has over 30 years experience including engineering, operations, marketing and commodities trading for Ladd Petroleum Corporation, Altresco Financial Inc., Delhi Gas Pipeline and Mobil Oil Corporation. Mr. Maffett received a BS in petroleum engineering from Louisiana State University.
Christopher G. Swanberg has served as vice president, environmental, health and safety at our general partner since October 2007. He has also served as vice president, environmental, health and safety at CVR Energy since September 2006 and as vice president, environmental, health and safety at Coffeyville Resources since June 2005. He has served in numerous management positions in the petroleum refining industry such as Manager, Environmental Affairs for the refining and marketing division of Atlantic Richfield Company (ARCO) and Manager, Regulatory and Legislative Affairs for Lyondell-Citgo Refining. Mr. Swanberg’s experience includes technical and management assignments in project, facility and corporate staff positions in all environmental, safety and health areas. Prior to joining Coffeyville Resources, he was Vice President of Sage Environmental Consulting, an environmental consulting firm focused on petroleum refining and petrochemicals, from September 2002 to June 2005. Mr. Swanberg received a BS in Environmental Engineering Technology from Western Kentucky University and an MBA from the University of Tulsa.
Donna R. Ecton has been a member of the board of directors of our general partner since March 2008. Ms. Ecton is founder, chairman, and chief executive officer of the management consulting firm EEI Inc, which she founded in 1998. Prior to founding EEI, she served as a board member of H&R Block, Inc. from 1993 to 2007, a board member of PETsMART, Inc. from 1994 to 1998, PETsMART’s chief operating officer from 1996 to 1998, and as chairman, president and chief executive officer of Business Mail Express, Inc., a privately held expedited print/mail business, from 1995 to 1996. Ms. Ecton was president and chief executive officer of Van Houten North America Inc. from 1991 to 1994 and Andes Candies Inc from 1991 to 1994. She has also held senior management positions at Nutri/System, Inc. and Campbell Soup Company. She started her business career in banking with both Chemical Bank and Citibank N.A. Ms. Ecton currently serves on the board of directors of Body Central Corp., a multi-channel specialty woman’s apparel retailer. Ms. Ecton is a member of the Council
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on Foreign Relations in New York City. She was also elected to and served on Harvard University’s Board of Overseers. Ms. Ecton received a BA in economics from Wellesley College and an MBA from the Harvard Graduate School of Business Administration. We believe Ms. Ecton’s significant background as both an executive officer and director of public companies and experience in finance is an asset to our board. Her knowledge and experience provide the audit committee with valuable perspective in managing the relationship with our independent accountants and the performance of the financial auditing oversight.
Frank M. Muller, Jr. has been a member of the board of directors of our general partner since May 2008. Until August 2009, Mr. Muller served as the chairman and chief executive officer of the technology design and manufacturing firm TenX Technology, Inc., which he founded in 1985. He is currently the president of Toby Enterprises, which he founded in 1999 to invest in startup companies, and the chairman of Topaz Technologies, Ltd., a software engineering company. Mr. Muller was a senior vice president of The Coastal Corporation from 1989 to 2001, focusing on business acquisitions and joint ventures, and general manager of the Kensington Company, Ltd. from 1984 to 1989. Mr. Muller started his business career in the oil and chemical industries with Pepsico, Inc. and Agrico Chemical Company. Mr. Muller served in the United States Army from 1965 to 1973. Mr. Muller received a BS and MBA from Texas A&M University. We believe Mr. Muller’s experience in the chemical industry and expertise in developing and growing new businesses is an asset to our board.
Mark A. Pytosh has been a member of the board of directors of our general partner since June 2011. Mr. Pytosh has served as the Chief Financial Officer of CCS Corporation since April 2010. CCS is a privately-held company that is the largest oil and gas environmental services company in North America. Before joining CCS, Mr. Pytosh served as Executive Vice President and Chief Financial Officer of Covanta Holding Corporation from December 2007 through March 2010 and as Senior Vice President and Chief Financial Officer of Covanta from September 2006 to December 2007. Covanta is a publicly-traded company which owns and operates energy-from-waste power facilities, biomass power facilities and independent power plants in the United States, Europe and Asia. From February 2004 to August 2006 Mr. Pytosh served as Executive Vice President and from May 2005 to August 2006 as Chief Financial Officer, of Waste Services, Inc., a publicly-traded integrated solid waste services company. From 2000 to early 2004 Mr. Pytosh was a managing director in Investment Banking at Lehman Brothers where he led the firm’s Global Industrial Group. Prior to joining Lehman Brothers he was a managing director at Donaldson, Lufkin & Jenrette where he led the firm’s Environmental Services and Automotive industry groups. He began his career at Kidder, Peabody. We believe Mr. Pytosh’s experience with public companies in the energy industry and strong financial background is an asset to our board.
Jon R. Whitney has been a member of the board of directors of our general partner since June 2011. He previously worked at Colorado Interstate Gas Company (CIG), a natural gas transmission company, from 1968 until 2001. He served as President and Chief Executive Officer of CIG from 1990 until it merged with El Paso Corporation in 2001. After leaving CIG, he served as Co-Chairman of the Board for TransLink, an independent electric power system operator, was a member of Peak Energy Ventures, LLC, a natural gas consulting company, and served on the boards of directors of Storm Cat Energy Corporation, Patina Oil and Gas Corporation (prior to its merger with Noble Energy in 2005), American Oil and Gas Corporation (prior to its merger with Hess Corporation in 2010), Bear Cub Energy and Bear Paw Energy. He also held committee positions with the Interstate Natural Gas Association of America and the American Gas Association. He is currently a director of Bear Tracker Energy LLC, a private company in the midstream energy business. We believe Mr. Whitney’s experience in the natural gas industry and as a director to multiple companies in the energy space is an asset to our board.
The directors of our general partner hold office until the earlier of their death, resignation or removal.
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Item 11. Executive Compensation
Compensation Discussion and Analysis
Overview
The Partnership does not directly employ any of the executives responsible for the management of our business. Our general partner employs Byron R. Kelley, its chief executive officer, and Randal T. Maffett, its executive vice president of business development. The other executives responsible for the management of our business are employed by CVR Energy, including John J. Lipinski, Edward A. Morgan, Kevan A. Vick (prior to his retirement effective February 1, 2012), and Stanley A. Riemann. Messrs. Lipinski, Kelley, Morgan, Vick, Maffett and Riemann are, respectively, the two people who served as chief executive officer of our general partner during 2011, the chief financial officer of our general partner during 2011, and the next three most highly compensated executive officers of our general partner during 2011 based on the portion of their compensation attributable to services performed for us. Throughout this Annual Report, Messrs. Lipinski, Kelley, Morgan, Vick, Maffett and Riemann are referred to collectively as the named executive officers.
The weighted-average percentages of the amount of time that the named executive officers spent on management of our business in 2011 are as follows: John J. Lipinski (21%), Byron R. Kelley (100%), Edward A. Morgan (36%), Kevan A. Vick (100%), Randal T. Maffett (71%) and Stanley A. Riemann (24%). These numbers are weighted because the named executive officers may spend a different percentage of their time dedicated to our business each quarter. The remainder of their time was spent working for CVR Energy (other than Messrs. Kelley and Vick, who spent all of their time working for our business).
Messrs. Kelley and Maffett are employed and paid by our general partner, whereas Messrs. Lipinski, Morgan, Vick (prior to his retirement effective February 1, 2012), and Riemann are employed and paid by CVR Energy. Effective January 1, 2012, Mr. Vick’s employment agreement with CVR was assigned to our general partner and was amended and restated on substantially the same terms. The compensation of all of the named executive officers for 2011 was determined by CVR Energy, with the exception of phantom units granted by the Partnership to Messrs. Kelley, Vick and Maffett. In addition, all of the named executive officers participate in the welfare and retirement plans of CVR Energy. The Partnership has no control and does not establish or direct the compensation policies or practices of CVR Energy. The Partnership bears an allocated portion of CVR Energy’s costs of providing compensation and benefits to the CVR Energy employees who serve as executive officers of our general partner pursuant to the services agreement described below. We are required to pay all compensation amounts allocated to us by CVR Energy (except for share-based compensation awarded by CVR Energy), although we may object to amounts that we deem unreasonable.
Based on an internal review by the compensation committee of our general partner of our material compensation programs and its understanding of the material compensation programs of CVR Energy, the compensation committee of our general partner has concluded that there are no plans that provide meaningful incentives for employees, including the named executive officers, to take risks that would be reasonably likely to have a material adverse effect on the Partnership.
Pursuant to the services agreement between us, our general partner and CVR Energy, among other matters:
| • | CVR Energy makes available to our general partner the services of the CVR Energy executive officers and employees, certain of whom serve as executive officers of our general partner; and |
| • | We, our general partner and our operating subsidiary, as the case may be, are obligated to reimburse CVR Energy for any allocated portion of the costs that CVR Energy incurs in providing compensation and benefits to such CVR Energy employees, with the exception of costs attributable to share-based compensation awarded by CVR Energy. |
Under the services agreement, either our general partner, CRNF (our subsidiary) or we pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other
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than administrative personnel, who provide us services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide us services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for us; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement. Following April 13, 2012, either CVR Energy or our general partner may terminate the services agreement upon at least 180 days’ notice. For more information on this services agreement, see “Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy.” In the case of Mr. Maffett, CVR Energy bears an allocated portion of the general partner’s cost of providing compensation to him pursuant to the GP Services Agreement entered into among the Partnership, our general partner and CVR Energy in November 2011. Pursuant to the agreement, CVR Energy must pay a prorated share of costs incurred by the Partnership or its general partner in connection with the employment of the Partnership’s employees who provide CVR Energy services on a part-time basis, as determined by the general partner on a commercially reasonable basis based on the percentage of total working time that such shared personnel are engaged in performing services for CVR Energy.
As discussed above, 2011 compensation for all of the named executive officers was set by CVR Energy, with the exception of phantom units granted by the Partnership to Messrs. Kelley, Vick and Maffett. The following discussion is based on information provided to us by CVR Energy. In the future, it is our intent that the compensation committee of our general partner (which was formed in June 2011) will be responsible for determining the compensation of the named executive officers dedicated solely to our business or who are employed by us or our general partner.
Compensation Philosophy
CVR Energy’s executive compensation philosophy is threefold:
| • | To align the executive officers’ interest with that of the stockholders and stakeholders, which provides long-term economic benefits to the stockholders; |
| • | To provide competitive financial incentives in the form of salary, bonuses and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and |
| • | To maintain a compensation program whereby the executive officers, through exceptional performance and equity ownership, have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders. |
Elements of Compensation Program
For 2011, the three primary components of CVR Energy’s compensation program were base salary, an annual performance-based cash bonus and equity awards. While these three components are related, they are viewed as separate and analyzed as such. The named executive officers are also provided with benefits that are generally available to CVR Energy’s salaried employees.
CVR Energy believes that equity compensation is the primary motivator in attracting and retaining executive officers. Salary and cash bonuses are viewed as secondary. However, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.
CVR Energy’s compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is
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equity compensation. The decision is strictly made on a subjective and individual basis after consideration of all relevant factors. The Chief Executive Officer of CVR Energy, while not a member of CVR Energy’s compensation committee, reviews information provided by the committee’s compensation consultant, Longnecker & Associates (“Longnecker”), as well as other relevant market information and actively provides guidance and recommendations to the committee regarding the amount and form of the compensation of other executive officers and key employees.
Longnecker has been engaged by CVR Energy on behalf of its compensation committee to assist the committee with its review of executive officers’ compensation levels and the mix of compensation as compared to peer companies, companies of similar size and other relevant market information. To this end, Longnecker performed a study including an analysis that management reviewed and then provided to the compensation committee for its use in making decisions regarding the salary, bonus and other compensation amounts paid to named executive officers. The following companies were included in the report and analysis prepared by Longnecker as members of CVR Energy’s “peer group”- the independent refining companies of Frontier Oil Corporation, Holly Corporation and Tesoro Corporation and the fertilizer businesses of CF Industries Holdings Inc. and Terra Industries, Inc. Although no specific target for total compensation or any particular element of compensation was set relative to CVR Energy’s peer group, the focus of Longnecker’s recommendations was centered on compensation levels at the median or 50th percentile of the peer group. As discussed earlier, in the future it is our intent that our general partner will be responsible for determining the compensation of the named executive officers dedicated solely to our business. To that end, in November 2011, the Partnership separately engaged Longnecker to perform an analysis for use of our general partner in making compensation decisions in respect of 2012 and with respect to the determination of the phantom units granted to Messrs. Kelley, Vick and Maffett in 2011.
The analysis performed by Longnecker for the compensation committee of our general partner was based upon the executive compensation paid by the Partnership’s “peer group”, which included Calumet Specialty Products Partners, LP, DCP Midstream Partners, LP, Natural Resource Partners, LP and Penn Virginia Resource Partners, LP. The compensation committee of our general partner decided to grant and determined the number of phantom units to be granted in December 2011 based on its review of its peer group’s long-term incentive grants as a percentage of base pay, which was compiled in the report from Longnecker.
Base Salary. In determining base salary levels, the compensation committee of CVR Energy takes into account the following factors: (i) CVR Energy’s financial and operational performance for the year, (ii) the previous years’ compensation level for each executive officer, (iii) peer or market survey information for comparable public companies and (iv) recommendations of the chief executive officer, based on individual responsibilities and performance, including each executive officer’s commitment and ability to: (A) strategically meet business challenges, (B) achieve financial results, (C) promote legal and ethical compliance, (D) lead their own business or business team for which they are responsible and (E) diligently and effectively respond to immediate needs of the volatile industry and business environment.
Rather than establishing compensation solely on a formula-driven basis, we understand that decisions by CVR Energy’s compensation committee are made using an approach that considers several important factors in developing compensation levels. For example, CVR Energy’s compensation committee considers whether individual base salaries reflect responsibility levels and are reasonable, competitive and fair. In addition, in setting base salaries, CVR Energy’s compensation committee reviews published survey and peer group data prepared by Longnecker and considers the applicability of the salary data in view of the individual positions within CVR Energy.
Annual Bonus. Information about total cash compensation paid by members of CVR Energy’s peer group is used in determining both the level of bonus award and the ratio of salary to bonus, as the compensation committee of CVR Energy believes that maintaining a level of bonus and a ratio of fixed salary to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in attracting and retaining executives. The compensation committee of CVR Energy also believes that a significant portion of executive officers’ compensation should be at risk, which means that a portion of the executive officers’ overall
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compensation is not guaranteed and is determined based on individual and company performance. Executive officers have greater potential bonus awards as the authority and responsibility of an executive increases. Employment agreements for each of the named executive officers provide that the executive is eligible to receive an annual cash bonus with a target bonus equal to a specified percentage of the relevant executive’s annual base salary. Under the employment agreements in effect during 2011, target bonuses were the following percentages of salary: Mr. Lipinski (250%), Mr. Kelley (200%), Mr. Morgan (120%), Mr. Vick (80%), Mr. Maffett (100%) and Mr. Riemann (200%). These target percentages were the result of individual negotiations between the named executive officers and CVR Energy or our general partner, as applicable, and were in correlation with the findings and recommendations by Longnecker based upon review of CVR Energy’s peer group, companies of similar size and other relevant market information. Specific bonus measures were determined by the board of directors of CVR Energy based on a review of CVR Energy’s peer group and discussions with CVR Energy management and the compensation committee of CVR Energy. The measures were selected based on optimizing operations, maintaining financial stability and providing a safe work environment intended to maximize the company’s overall performance resulting in increased shareholder value.
In March 2011, CVR Energy adopted the CVR Energy, Inc. Performance Incentive Plan (the “CVR Energy PIP”), pursuant to which all of the named executive officers had the opportunity to earn bonuses in respect of 2011. The payment of annual bonuses for the 2011 performance year to the named executive officers depended on the achievement of financial, operational and safety measures, which comprised 50%, 30% and 20% of the annual bonuses, respectively. In March 2011, the compensation committee of CVR Energy approved the threshold, target and maximum performance goals with respect to each measure. Specific bonus measures were determined by CVR Energy based on a review of its peer group and discussions between CVR Energy’s board of directors and management and its compensation committee. The measures were selected based on optimizing operations, maintaining financial stability and providing a safe work environment intended to maximize CVR Energy’s overall performance resulting in increased shareholder value.
The financial measures relevant to the named executive officers were consolidated adjusted earnings before interest, taxes, depreciation and amortization (“EBITDA”), fertilizer business adjusted EBITDA, and consolidated adjusted cash flow. The 2011 performance goals for these financial measures were as follows: consolidated adjusted cash flow (threshold – $10 million; target – $35 million; maximum – $60 million); consolidated adjusted EBITDA (threshold – $159.4 million; target – $318.8 million; maximum – $477.6 million); and fertilizer adjusted EBITDA (threshold – $69.8 million; target – $139.6 million; maximum – $209.4 million). Awards were not payable with respect to the financial measures unless at least 50% of the relevant performance goal was achieved. The operational measures relevant to the named executive officers were petroleum reliability and fertilizer reliability. The 2011 performance goals for these operational measures were as follows: for the petroleum business, crude throughput, BPD (threshold – 90,000 BPD; target – 100,500 BPD; maximum 102,500 BPD); and for the fertilizer business, on-stream factors for ammonia/UAN units (threshold – 90% / 87%; target – 95% / 92%; maximum – 97% / 94%). Awards were not payable with respect to the operational measures unless at least 50% of the relevant performance goal was achieved. The safety measure relevant to the named executive officers was consolidated OSHA personal injury statistics. The 2011 performance goals for this safety measure was as follows: threshold – 9 recordable events; target – 8 recordable events; maximum – 7 recordable events. Awards were not payable with respect to the safety measure unless the number of recordable events was less than the three year average.
The following table reflects how each named executive officer’s 2011 bonus was allocated among the various performance measures. The executives receive 50%, 100%, or up to 150% of the applicable portion for levels of performance attained at threshold, target and maximum, respectively, and the percentage of the target amount for each respective measure that would be paid at various levels of achievement.
| Performance Measure |
Percentage of Target Bonus Paid for Relevant Measure | |
| Consolidated adjusted EBITDA |
25% for Lipinski, Morgan, Riemann | |
| Fertilizer adjusted EBITDA |
25% for Kelley, Vick, Maffett | |
| Consolidated adjusted cash flow |
25% for all named executive officers | |
| Crude throughput, BPD |
15% for Lipinski, Morgan, Riemann | |
| On-stream ammonia / UAN |
15% for Lipinski, Morgan, Riemann | |
| On-stream ammonia / UAN |
30% for Kelley, Vick, Maffett | |
| Consolidated OSHA |
20% for all named executive officers |
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For 2011, the actual level of achievement with respect to the adjusted EBITDA of the fertilizer business was $162.7 million. CVR Energy has advised us that the actual level of achievement was in excess of the maximum targets established for consolidated adjusted EBITDA, consolidated adjusted cash flow and the fertilizer reliability measures. The actual level of achievement for the petroleum reliability measure was between the target and maximum targets established. The actual level of achievement for the consolidated OSHA statistics was below the threshold target established. As a result of these levels of performance, Messrs. Lipinski, Morgan and Riemann earned 112.94% of their respective target annual bonuses and Messrs. Kelley, Vick and Maffett earned 111.65% of their respective target annual bonuses. Messrs. Kelley and Maffett will be paid a prorated amount based upon the length of time they were employed in 2011. The amounts earned by the named executive officers as a result of their respective levels of performance during 2011 pursuant to the CVR Energy PIP are set forth in the Summary Compensation Table that follows in the Non-Equity Incentive Award column.
Equity Awards
CVR Energy and the Partnership each use equity incentives to reward long-term performance. The issuance of equity to executive officers is intended to generate significant future value for each executive officer if CVR Energy’s performance is outstanding and the value of CVR Energy’s equity increases for all of its stockholders. CVR Energy’s compensation committee believes that its equity incentives promote long-term retention of executives. Prior to 2011, the principal equity incentives were those that were negotiated at the time of the acquisition of the CVR Energy business in June 2005 (with additional awards that were not originally allocated in June 2005 issued in December 2006), including to the named executive officers who were employed by CVR Energy at such time, in order to bring CVR Energy’s compensation package in line with executives at private equity portfolio companies, based on the private equity market practices at that time. Any costs associated with equity incentives awarded (other than pursuant to the CVR Partners LTIP) are borne wholly by CVR Energy. These profits interests have not had any realization event to date, but in connection with the Partnership’s Initial Public Offering in April 2011, the members of CALLC III received proceeds from the sale of the incentive distribution rights and the general partner interest. See “Certain Relationships and Related Party Transactions.”
In April 2011, the Partnership adopted the CVR Partners LTIP. Individuals who are eligible to receive awards under the CVR Partners LTIP include the employees, officers, consultants and directors of the Partnership and its general partner and their respective subsidiaries and parents. The CVR Partners LTIP permits the grant of options, unit appreciation rights, distribution equivalent rights, restricted units, phantom units and other unit-based awards, each in respect of common units in the Partnership, as determined by the compensation committee of our general partner. Each phantom unit represents the right of the grantee to receive, if such phantom unit becomes vested, one common unit of the Partnership. In 2011, the Partnership granted phantom units to Messrs. Kelley, Vick and Maffett. These phantom units are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided that the executives continue to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. The issuance of common units upon vesting shall be subject to the executives’ prior execution of and becoming a party to the Agreement of Limited Partnership of CVR Partners, LP, as may be amended from time to time, and as in effect at the time of such issuance. Any common units delivered to the executives in respect of the phantom units shall remain subject to the retention guidelines included in the corporate governance guidelines of the Partnership, as in effect on the date of the award.
Perquisites. A portion of medical insurance and life insurance provided to the named executive officers is paid by CVR Energy, as well as a medical physical every three years. Mr. Vick, who was involved in direct operations at our facilities prior to his retirement in February 2012, received use of a company vehicle. The total value of all perquisites and personal benefits provided to each respective named executive officer in 2011 was less than $10,000.
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Other Forms of Compensation. Each of the named executive officers has provisions in their respective employment agreements with CVR Energy or, in the case of Messrs. Kelley and Maffett, our general partner, providing for certain severance benefits in the event a termination of their employment under certain circumstances. These severance provisions are described below in “— Change-in-Control and Termination Payments” and were negotiated between the named executive officers and CVR Energy or our general partner, as applicable.
Compensation Committee Report
The compensation committee of our general partner has reviewed and discussed the Compensation Discussion and Analysis with management. Based on this review and discussion, the compensation committee recommended to the board of directors that the Compensation Discussion and Analysis be included in this Annual Report.
Compensation Committee
Frank M. Muller, Jr. (Chairman)
Jon R. Whitney
Summary Compensation Table
The following table sets forth the portion of compensation paid to the named executive officers that is attributable to services performed for us during the year ended December 31, 2011. The amount set forth in the total column reflects the product of each respective named executive officer’s total compensation earned in 2011 multiplied by the percentage of time spent performing services for us, with such percentage weighted among the various elements of compensation in accordance with the allocation of each particular element to services performed for the Partnership. For example, since Mr. Lipinski dedicated a weighted-average of approximately 21% of his time to performing services for us, the amounts reflected in the total column represents approximately 21% of his total compensation for 2011. In the case of Messrs. Kelley and Vick, who spent 100% of their time dedicated to the business in 2011, these amounts reflected in this table represent the total compensation paid to them. However, equity awards granted by CVR Energy are not included in this table as we are not obligated under the services agreement to reimburse CVR Energy for any portion of share-based compensation awarded by CVR Energy and, accordingly, do not consider such awards to be attributable to services performed for us.
| Name and Principal Position |
Year | Salary ($) | Bonus ($)(1) |
Stock Awards ($)(2) |
Non-Equity Incentive Plan Compensation ($)(3) |
All Other Compensation ($) |
Total ($) | |||||||||||||||||||||
| John J. Lipinski, Executive Chairman |
|
2011 2010 2009 |
|
|
189,000 138,916 170,400 |
|
|
— 266,667 426,000 |
|
|
— — — |
|
|
533,653 — — |
|
|
5,197 1,390 2,614 |
|
|
727,850 406,973 599,014 |
| |||||||
| Byron R. Kelley, Chief Executive Officer (4) |
2011 | 291,667 | — | 2,000,031 | 651,319 | 9,541 | 2,952,558 | |||||||||||||||||||||
| Edward A. Morgan, Chief Financial Officer (5) |
|
2011 2010 2009 |
|
|
120,600 49,469 42,837 |
|
|
— 50,400 64,238 |
|
|
— — — |
|
|
163,450 — — |
|
|
4,408 1,204 34,335 |
|
|
288,458 101,073 141,410 |
| |||||||
| Kevan A. Vick, Executive Vice President and Fertilizer General Manager (6) |
|
2011 2010 2009 |
|
|
253,000 245,000 245,000 |
|
|
— 196,000 196,000 |
|
|
328,915 — — |
|
|
225,989 — — |
|
|
19,605 16,178 13,929 |
(7)
|
|
827,509 457,178 454,929 |
| |||||||
| Randal T. Maffett, Executive Vice President Business Development (8) |
2011 | 88,743 | (9) | 59,155 | 550,016 | 77,210 | 2,867 | 777,991 | ||||||||||||||||||||
| Stanley A. Riemann, Chief Operating Officer |
|
2011 2010 2009 |
|
|
102,000 62,493 140,270 |
|
|
— 124,500 280,540 |
|
|
— — — |
|
|
230,403 — — |
|
|
5,940 1,895 4,148 |
|
|
338,434 188,888 424,958 |
| |||||||
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| (1) | The amount in this column for Mr. Maffett reflects a $25,000 signing bonus, as well as a discretionary bonus earned for 2011 and paid in 2012. Amounts included in this column for other named executive officers reflect bonuses earned pursuant to CVR Energy’s discretionary bonus plan for performance during 2010 and 2009. CVR Energy’s discretionary bonus plan was replaced by the CVR Energy PIP in March 2011. |
| (2) | Amounts in this column reflect the aggregate grant date fair value of phantom units granted during 2011 to certain of the named executive officers pursuant to the CVR Partners LTIP, computed in accordance with FASB ASC Topic 718 which are set forth in footnote 3 to our audited financials. These phantom units are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided that the executives continue to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, and subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. The table does not include amounts with respect to equity awards granted by CVR Energy to certain of the named executive officers pursuant to the CVR Energy Long-Term Incentive Plan because such amounts were not reimbursed by us. |
| (3) | Amounts in this column reflect amounts earned pursuant to the CVR Energy PIP in respect of performance during 2011, which were paid in 2012. |
| (4) | Mr. Kelley’s compensation for 2011 has been pro-rated to reflect amounts earned starting on June 1, 2011, the date he became employed by our general partner. Prior to such date, Mr. Lipinski served as chief executive officer of our general partner. |
| (5) | Mr. Morgan’s compensation for 2009 has been pro-rated to reflect amounts earned following the date he became employed by CVR Energy in May 2009. |
| (6) | Mr. Vick retired and his employment agreement was terminated effective as of February 1, 2012. In connection with his retirement, our general partner, the Partnership and CVR Energy entered into a Consulting Agreement with Mr. Vick, which is described in more detail following the Grants of Plan-Based Awards table. |
| (7) | The amount in this column includes the portion of the following benefits for Mr. Vick that were reimbursed by us in accordance with the services agreement described herein: (a) car allowance, (b) contribution to Mr. Vick’s account under CVR Energy’s 401 (k) plan and (c) premiums paid on behalf of Mr. Vick with respect to CVR Energy’s basic life insurance program. Premiums paid on behalf of Mr. Vick with respect to CVR Energy’s executive life insurance program are not included because such amounts are not reimbursed by us. |
| (8) | Mr. Maffett’s compensation for 2011 has been pro-rated to reflect amounts earned starting on August 22, 2011, the date he became employed by our general partner. |
| (9) | In addition to salary paid to Mr. Maffett for 2011, the amount in this column also includes amounts paid to him for consulting work performed from June 27, 2011 through August 22, 2011. |
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Grants of Plan-Based Awards
The following table sets forth information concerning grants of plan-based awards to the named executive officers received pursuant to the CVR Partners LTIP, as well as amounts that could have been earned under the CVR Energy PIP during 2011.
| Estimated Future Payouts
Under Non-Equity Incentive Plan Awards(1) |
||||||||||||||||||||||||
| Name |
Grant Date | Threshold ($) |
Target ($) |
Maximum ($) |
All Other Stock Awards: Number of Shares of Stock or Units (#) |
Grant Date Fair Value of Stock Awards ($)(2) |
||||||||||||||||||
| John J. Lipinski |
— | 236,250 | 472,500 | 708,750 | — | — | ||||||||||||||||||
| Byron R. Kelley |
— | 291,667 | 583,333 | 875,000 | — | — | ||||||||||||||||||
| 06/01/2011 | — | — | — | 50,659 | 1,000,009 | |||||||||||||||||||
| 12/30/2011 | — | — | — | 40,291 | 1,000,023 | |||||||||||||||||||
| Edward A. Morgan |
— | 72,360 | 144,720 | 217,080 | — | — | ||||||||||||||||||
| Randal T. Maffett |
— | 35,371 | 70,742 | 106,113 | — | — | ||||||||||||||||||
| 08/22/2011 | — | — | — | 12,815 | 275,010 | |||||||||||||||||||
| 12/30/2011 | — | — | — | 11,080 | 275,006 | |||||||||||||||||||
| Kevan A. Vick |
— | 101,200 | 202,400 | 303,600 | — | — | ||||||||||||||||||
| 12/30/2011 | — | — | — | 13,252 | 328,915 | |||||||||||||||||||
| Stanley A. Riemann |
— | 102,000 | 204,000 | 306,000 | — | — | ||||||||||||||||||
| (1) | Amounts in these columns reflect amounts that could have been earned by the named executive officers under the CVR Energy PIP in respect of 2011 performance at the threshold, target and maximum levels with respect to each performance measure, and pro-rated in accordance with the percentage of time that each named executive officer spent dedicated to our business in 2011. The performance measures and related goals set by the compensation committee of CVR Energy for 2011 are described in the Compensation Discussion and Analysis. Additionally, for Messrs. Kelley and Maffett, the amounts that could have been earned under the PIP are pro-rated for the period of time they were employed by our general partner. |
| (2) | Reflects the grant date fair value of the phantom units awarded under the CVR Partners LTIP during 2011, computed in accordance with FASB ASC Topic 718. Equity awards granted by CVR Energy to the named executive officers are not included in this table as we are not obligated under the services agreement to reimburse CVR Energy for any portion of share-based compensation and, accordingly, do not consider such awards to be attributable to services performed for us. |
Employment Agreements
John J. Lipinski. On July 12, 2005, Coffeyville Resources, LLC entered into an employment agreement with Mr. Lipinski, as chief executive officer, which was subsequently assumed by CVR Energy and amended and restated effective as of January 1, 2008. Mr. Lipinski’s employment agreement was amended and restated effective January 1, 2010 and subsequently amended and restated on January 1, 2011. The agreement has a rolling term of three years so that at the end of each month it automatically renews for one additional month, unless otherwise terminated by CVR Energy or Mr. Lipinski. Mr. Lipinski receives an annual base salary of $900,000 effective as of January 1, 2011. Mr. Lipinski is also eligible to receive a performance-based annual cash bonus with a target payment equal to 250% of his annual base salary to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy for each fiscal year. In addition, Mr. Lipinski is entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure and also includes covenants relating to non-solicitation and non-competition that govern during his employment and thereafter for the period severance is paid and, if no
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severance is paid, for one year following termination of employment. In addition, Mr. Lipinski’s agreement provides for certain severance payments that may be due following the termination of his employment under certain circumstances, which are described below under “— Change-in-Control and Termination Payments.”
Edward A. Morgan. On May 14, 2009, Mr. Morgan entered into an employment agreement with CVR Energy, which was amended effective August 17, 2009. This employment agreement was further amended and restated effective January 1, 2010 and on January 1, 2011, and was subsequently amended on November 29, 2011. This agreement provides for an annual base salary of $335,000 and a 2011 target bonus equal to 120% for Mr. Morgan. In connection with the amendment to Mr. Morgan’s agreement in November 2011, the term was amended to end on December 31, 2012, unless otherwise terminated earlier by either party, and may be extended on such terms and conditions as CVR Energy and Mr. Morgan mutually agree. This amendment also provided that Mr. Morgan would serve as chief financial officer and treasurer of CVR Energy until the date that is 120 days (or such earlier date as CVR Energy may determine) after the date CVR Energy named a successor to serve in such position, at which time Mr. Morgan would then serve as executive vice president of investor relations. On January 4, 2012, in accordance with the agreement, Mr. Morgan transitioned into the role of executive vice president of investor relations for CVR Energy. In connection with this transition and in accordance with the most recent amendment to his agreement, his annual base salary was changed to $275,000. In addition, for 2012, his target bonus will be 120% of his salary as chief financial officer with respect to the period of time he served in such role, and 40% of his salary as executive vice president of investor relations for the period of time he serves in such role. Mr. Morgan is also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as are in effect from time to time on the same basis as other senior executives of CVR Energy. Mr. Morgan is required to abide by a perpetual restrictive covenant relating to non-disclosure, a covenant relating to non-competition during his employment and for 30 days following his termination, and a covenant relating to non-solicitation during his employment and for one year thereafter. Mr. Morgan’s agreement also provides for certain severance payments that may be due following the termination of his employment under certain circumstances, which are described below under “— Change-in-Control and Termination Payments.”
Kevan A. Vick and Stanley A. Riemann. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Messrs. Vick and Riemann, which were subsequently assumed by CVR Energy and amended and restated effective as of December 29, 2007. These agreements were amended and restated effective January 1, 2010 and subsequently amended and restated on January 1, 2011 and have a term of three years that expires in January 2014, unless otherwise terminated earlier by either party. These agreements provide for an annual base salary of $253,000 for Mr. Vick and $425,000 for Mr. Riemann, each effective as of January 1, 2011. Each is also eligible to receive a performance-based annual cash bonus to be based upon individual and/or company performance criteria as established by the compensation committee of the board of directors of CVR Energy for each fiscal year. The target annual bonus percentages for these executive officers effective as of January 1, 2011 are 80% for Mr. Vick and 200% for Mr. Riemann. These executives are also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs of CVR Energy as in effect from time to time on the same basis as other senior executives of CVR Energy. The agreements require these executive officers to abide by a perpetual restrictive covenant relating to non-disclosure and also include covenants relating to non-solicitation and non-competition during the executives’ employment and for one year following termination of employment. In addition, these agreements provide for certain severance payments that may be due following the termination of employment under certain circumstances, which are described below under “— Change-in-Control and Termination Payments.” Effective January 1, 2012, Mr. Vick’s employment agreement with CVR was assigned to our general partner and was amended and restated on substantially the same terms.
In connection with Mr. Vick’s retirement and the termination of his employment agreement effective February 1, 2012, our general partner, the Partnership, CVR Energy and Mr. Vick entered into a consulting agreement effective February 1, 2012. Pursuant to this agreement, Mr. Vick will provide consulting services to our general partner, the Partnership and their subsidiaries and affiliates for two years. As compensation for his
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services, Mr. Vick shall receive an annual retainer of $63,000, plus $175 per hour for each hour worked in excess of certain specified limitations. In addition, pursuant to the consulting agreement, Mr. Vick remained eligible to receive his 2011 annual bonus pursuant to the CVR Energy PIP. The consulting agreement includes a restrictive covenant relating to non-disclosure that governs during the two year term and for ten years thereafter, and also includes covenants relating to non-solicitation and non-competition that govern until February 1, 2014. Pursuant to the agreement, the Partnership and CVR Energy have also agreed to amend the terms of the phantom units of the Partnership and restricted common stock of CVR Energy that are held by Mr. Vick to provide that they shall continue to vest on the original schedule during his service as a consultant.
Byron R. Kelley and Randal T. Maffett. CVR GP, LLC, our general partner, entered into employment agreements with each of Messrs. Kelley and Maffett, on June 1, 2011 and August 22, 2011, respectively. The agreements each have an initial term of three years and will automatically renew for successive one year periods, unless otherwise terminated by either party. The agreements provide for an annual base salary of $500,000 for Mr. Kelley and $275,000 for Mr. Maffett. Mr. Maffett was also paid a signing bonus of $25,000. Mr. Kelley and Mr. Maffett are also eligible to receive a performance-based annual cash bonus to be based upon individual and/or company performance criteria. The target annual bonus percentages commencing with fiscal year 2011 for Messrs. Kelley and Maffett are 200% and 100% of base salary, respectively. These executives are also entitled to participate in such health, insurance, retirement and other employee benefit plans and programs as in effect from time to time on the same basis as other senior executives. The agreements require Messrs. Kelley and Maffett to abide by perpetual restrictive covenants relating to non-disclosure and also include covenants relating to non-solicitation and non-competition during the executives’ employment and for one year following termination of employment. In addition, these agreements provide for certain severance payments that may be due following the termination of employment under certain circumstances, which are described below under “— Change-in-Control and Termination Payments.”
Outstanding Equity Awards at Fiscal Year End
The following table sets forth information concerning outstanding equity awards granted pursuant to the CVR Partners LTIP that were held by certain of the named executive officers as of December 31, 2011.
| Stock Awards | ||||||||
| Name |
Number of Shares or Units of Stock |
Market Value of Shares or Units of |
||||||
| Byron R. Kelley |
90,950 | 2,257,379 | ||||||
| Randal T. Maffett |
23,895 | 593,074 | ||||||
| Kevan A. Vick |
13,252 | 328,915 | ||||||
| (1) | The phantom units reflected in this table are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided the executive continues to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. |
| (2) | This column represents the closing price of our common units on December 31, 2011, which was $24.82, multiplied by the number of unvested phantom units outstanding on such date. |
Reimbursement of Expenses of Our General Partner
Our general partner and its affiliates are reimbursed for expenses incurred on our behalf under the services agreement. See “Certain Relationships and Related Transactions, and Director Independence — Agreements with CVR Energy — Services Agreement” for a description of our services agreement. These expenses include the costs of employee, officer and director compensation and benefits properly allocable to us, and all other expenses necessary or appropriate to the conduct of our business and allocable to us. These expenses also include costs incurred by CVR Energy or its affiliates in rendering corporate staff and support services to us pursuant to the
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services agreement, including a pro-rata portion of the compensation of CVR Energy’s executive officers who provide management services to us based on the amount of time such executive officers devote to our business. For the year ending December 31, 2011, the total amount paid to our general partner and its affiliates (including amounts paid to CVR Energy pursuant to the services agreement) was approximately $11.6 million.
Our partnership agreement provides that our general partner determines which of its affiliates’ expenses are allocable to us and the services agreement provides that CVR Energy invoice us monthly for services provided thereunder. Our general partner may dispute the costs that CVR Energy charges us under the services agreement, but we are not entitled to a refund of any disputed cost unless it is determined not to be a reasonable cost incurred by CVR Energy in connection with services it provided.
Change-in-Control and Termination Payments
Under the terms of the named executive officers’ employment agreements with our general partner or CVR Energy (as applicable), they are entitled to severance and other benefits from us or CVR Energy following the termination of their employment under certain circumstances. The amounts reflected in this section have not been pro-rated for Messrs. Lipinski, Morgan and Vick based on the amount of time spent working for us because we do not reimburse CVR Energy for costs associated with terminations of employment under the services agreement. The amounts of potential post-employment payments and benefits in the narrative and table below assume that the triggering event took place on December 31, 2011.
John J. Lipinski. If Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement), then in addition to any accrued amounts, including any base salary earned but unpaid through the date of termination, any earned but unpaid annual bonus for completed fiscal years, any unused accrued paid time off and any unreimbursed expenses (“Accrued Amounts”), Mr. Lipinski is entitled to receive as severance (a) salary continuation for 36 months (b) a pro-rata bonus for the year in which termination occurs based on actual results and (c) the continuation of medical benefits for 36 months at active-employee rates or until such time as Mr. Lipinski becomes eligible for medical benefits from a subsequent employer. In addition, if Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in his employment agreement) within one year following a change in control (as defined in his employment agreements) or in specified circumstances prior to and in connection with a change in control, Mr. Lipinski will receive 1/12 of his target bonus for the year of termination for each month of the 36 month period during which he is entitled to severance.
If Mr. Lipinski’s employment is terminated as a result of his disability, then in addition to any Accrued Amounts and any payments to be made to Mr. Lipinski under disability plan(s), Mr. Lipinski is entitled to (a) disability payments equal to, in the aggregate, Mr. Lipinski’s base salary as in effect immediately before his disability (the estimated total amount of this payment is set forth in the relevant table below) and (b) a pro-rata bonus for the year in which termination occurs based on actual results. Such supplemental disability payments will be made in installments for a period of 36 months from the date of disability. As a condition to receiving these severance payments and benefits, Mr. Lipinski must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. If Mr. Lipinski’s employment is terminated at any time by reason of his death, then in addition to any Accrued Amounts Mr. Lipinski’s beneficiary (or his estate) will be paid (a) the base salary Mr. Lipinski would have received had he remained employed through the remaining term of his employment agreement and (b) a pro-rata bonus for the year in which termination occurs based on actual results. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski’s supplemental disability payments or the payments due to Mr. Lipinski’s beneficiary or estate by reason of his death. Mr. Lipinski will be required to cooperate in obtaining such insurance. Upon a termination by reason of Mr. Lipinski’s retirement after reaching age 62, in addition to any Accrued Amounts, Mr. Lipinski will receive (a) continuation of medical and dental benefits for 36 months at active-employee rates or until such time as Mr. Lipinski becomes eligible for such benefits from a
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subsequent employer, (b) provision of an office at CVR Energy’s headquarters and use of CVR Energy’s facilities and administrative support, each at CVR Energy’s expense, for 36 months and (c) a pro-rata bonus for the year in which termination occurs based on actual results.
In the event that Mr. Lipinski is eligible to receive continuation of medical and dental benefits at active-employee rates but is not eligible to continue to receive benefits under CVR Energy’s plans pursuant to the terms of such plans or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing Mr. Lipinski with such benefits at the same cost to CVR Energy as providing him with continued coverage under CVR Energy’s plans. If such coverage cannot be obtained, CVR Energy will pay Mr. Lipinski on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had he continued participation in CVR Energy’s medical and dental plans.
If any payments or distributions due to Mr. Lipinski would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be “cut back” only if that reduction would be more beneficial to him on an after-tax basis than if there was no reduction. The estimated total amounts payable to Mr. Lipinski (or his beneficiary or estate in the event of death) in the event of termination of employment under the circumstances described above are set forth in the table below. Mr. Lipinski would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by him voluntarily without good reason and not by reason of his retirement. The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure. The agreement also includes covenants relating to non-solicitation and non-competition during Mr. Lipinski’s employment term, and thereafter during the period he receives severance payments or supplemental disability payments, as applicable, or for one year following the end of the term (if no severance or disability payments are payable).
Edward A. Morgan and Kevan A. Vick. Pursuant to their employment agreements, if the employment of Messrs. Morgan or Vick is terminated either by CVR Energy without cause and other than for disability or by the executive officer for good reason (as such terms are defined in their respective employment agreements), then these executive officers are entitled, in addition to any Accrued Amounts, to receive as severance (a) salary continuation for 12 months, (b) a pro-rata bonus for the year in which termination occurs based on actual results and (c) the continuation of medical and dental benefits for 12 months at active-employee rates or until such time as the executive officer becomes eligible for such benefits from a subsequent employer. In addition, if the employment of the named executive officers is terminated either by CVR Energy without cause and other than for disability or by the executives for good reason (as these terms are defined in their employment agreements) within one year following a change in control (as defined in their employment agreements) or in specified circumstances prior to and in connection with a change in control, they are also entitled to receive additional benefits. For Mr. Morgan, the severance period and benefit continuation period is extended to 24 months and he will also receive monthly payments equal to 1/12 of his target bonus for the year of termination during the 24 month severance period. Mr. Vick will receive monthly payments equal to 1/12 of his respective target bonus for the year of termination for 12 months. Upon a termination by reason of these executives’ employment upon retirement after reaching age 62, in addition to any Accrued Amounts, they will receive (a) a pro-rata bonus for the year in which termination occurs based on actual results and (b) continuation of medical benefits for 24 months at active-employee rates or until such time as they become eligible for medical benefits from a subsequent employer. Effective January 1, 2012, Mr. Vick’s employment agreement with CVR was assigned to our general partner and was amended and restated on substantially the same terms.
In the event that Messrs. Morgan and Vick are eligible to receive continuation of medical and dental benefits at active-employee rates but are not eligible to continue to receive benefits under CVR Energy’s plans pursuant to the terms of such plans or a determination by the insurance providers, CVR Energy will use reasonable efforts to obtain individual insurance policies providing the executives with such benefits at the same cost to CVR Energy as providing them with continued coverage under CVR Energy’s plans. If such coverage cannot be obtained, CVR Energy will pay the executives on a monthly basis during the relevant continuation period, an amount equal to the amount CVR Energy would have paid had they continued participation in CVR Energy’s medical and dental plans.
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As a condition to receiving these severance payments and benefits, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction. These executive officers would solely be entitled to Accrued Amounts, if any, upon the termination of employment by CVR Energy for cause, or by them voluntarily without good reason and not by reason of retirement, death or disability. The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include covenants relating to non-solicitation and covenants relating to non-competition during their employment terms and for one year following the end of the terms.
The tables that follow reflect the severance and benefits that would have been paid and provided to Mr. Morgan and Mr. Vick had their employment been terminated under certain circumstances as of December 31, 2011. However, certain changes were made pursuant to the most recent amendment to Mr. Morgan’s agreement regarding payments and benefits in the event of a termination of employment. If, after January 4, 2012, Mr. Morgan’s employment is terminated by CVR Energy without cause and other than for disability (as such terms are defined in his employment agreement) or if he resigns for any reason, then in addition to any Accrued Amounts, Mr. Morgan is entitled to receive (i) accelerated vesting of all unvested shares of restricted common stock then held by him, (ii) a pro-rata bonus for the year in which such termination or resignation occurs based on actual results, and (iii) solely if Mr. Morgan’s employment is terminated by CVR Energy without cause and other than for disability, salary continuation until December 31, 2012. In addition, if after January 4, 2012, Mr. Morgan’s employment is terminated by CVR Energy without cause and other than for disability or if he resigns for good reason (in each case, as such terms are defined in his employment agreement) within one year following a change in control (as defined in his employment agreement) or in specified circumstances prior to and in connection with a change in control, then in addition to the amounts described above, Mr. Morgan is entitled to receive monthly payments of $9,167 during the 12-month period following such termination or resignation. In addition, the covenant relating to non-competition for Mr. Morgan was amended to only apply during his employment term and for 30 days thereafter. In addition, pursuant to Mr. Vick’s consulting agreement, he would not be entitled to any severance upon the termination of his services by our general partner.
Byron R. Kelley and Randal T. Maffett. Pursuant to their employment agreements, if the employment of Messrs. Kelley or Maffett is terminated either by our general partner without cause and other than for disability or by the executive officer for good reason (as such terms are defined in their respective employment agreements), then these executive officers are entitled, in addition to any Accrued Amounts, to receive as severance (a) salary continuation for 12 months (18 months for Mr. Kelley), (b) a pro-rata bonus for the year in which termination occurs based on actual results and (c) the continuation of medical and dental benefits for 12 months (18 months for Mr. Kelley) at active-employee rates or until such time as the executive officer becomes eligible for such benefits from a subsequent employer. In addition, if the employment of these named executive officers is terminated either by our general partner without cause and other than for disability or by the executives for good reason (as these terms are defined in their employment agreements) within one year following a change in control (as defined in their employment agreements) or in specified circumstances prior to and in connection with a change in control, they are also entitled to receive additional benefits. For Mr. Kelley, the severance period and benefit continuation period is extended to 30 months and he will also receive monthly payments equal to 1/12 of his bonus for the year of termination based on actual results during the 30 month severance period. Mr. Maffett will receive monthly payments equal to 1/12 of his target bonus for the year of termination for 12 months. Upon a termination by reason of these executives’ employment upon retirement (in the case of Mr. Kelley after the later of reaching age 62 or having five years of service and, in the case of Mr. Maffett, after reaching age 62), in addition to any Accrued Amounts, they will receive (a) a pro-rata bonus for the year in which termination occurs based on actual results and (b) continuation of medical benefits for 24 months at active-employee rates or until such time as they become eligible for medical benefits from a subsequent employer. In addition, in the case of Mr. Kelley, if he resigns for any reason other than by reason of his death following the three year initial term of his employment agreement (ending
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June 1, 2014), he will be entitled to a pro-rata bonus for the year in which termination occurs based on actual results. Mr. Kelley does not currently receive benefits from our general partner.
In the event that Messrs. Kelley and Maffett are eligible to receive continuation of medical and dental benefits at active-employee rates but are not eligible to continue to receive benefits under our plans pursuant to the terms of such plans or a determination by the insurance providers, we will use reasonable efforts to obtain individual insurance policies providing the executives with such benefits at the same cost to us as providing them with continued coverage under our plans. If such coverage cannot be obtained, we will pay the executives on a monthly basis during the relevant continuation period, an amount equal to the amount we would have paid had they continued participation in our medical and dental plans.
As a condition to receiving these severance payments and benefits, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer would be subject to the excise tax imposed under Section 4999 of the Code, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction. These executive officers would solely be entitled to Accrued Amounts, if any, upon the termination of employment by our general partner for cause, or by them voluntarily without good reason and not by reason of retirement, death or disability. The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include covenants relating to non-solicitation and covenants relating to non-competition during their employment terms and for one year following the end of the terms.
| Cash Severance ($) | Benefit Continuation ($) | |||||||||||||||||||||||||||||||||||||||
| Death | Disability | Retirement | Termination without Cause or with Good Reason |
Death | Disability | Retirement | Termination without Cause or with Good Reason |
|||||||||||||||||||||||||||||||||
| (1) | (2) | (1) | (2) | |||||||||||||||||||||||||||||||||||||
| John J. Lipinski |
4,950,000 | 4,950,000 | 2,250,000 | 4,950,000 | 11,700,000 | — | — | 27,767 | 27,767 | 27,767 | ||||||||||||||||||||||||||||||
| Edward A. Morgan |
— | — | 402,000 | 737,000 | 1,876,000 | — | — | 26,560 | 13,883 | 26,560 | ||||||||||||||||||||||||||||||
| Kevan A. Vick |
— | — | 253,000 | 455,400 | 657,800 | — | — | 26,560 | 13,280 | 13,280 | ||||||||||||||||||||||||||||||
| Byron R. Kelley |
— | — | 1,000,000 | 1,750,000 | 4,750,000 | — | — | — | — | — | ||||||||||||||||||||||||||||||
| Randal T. Maffett |
— | — | 275,000 | 550,000 | 825,000 | — | — | 26,560 | 13,280 | 13,280 | ||||||||||||||||||||||||||||||
| (1) | Severance payments and benefits in the event of termination without cause or resignation for good reason not in connection with a change in control. |
| (2) | Severance payments and benefits in the event of termination without cause or resignation for good reason in connection with a change in control. |
Each of the named executive officers of our general partner who is employed by CVR Energy has been granted shares of restricted stock granted pursuant to the CVR Energy LTIP. In connection with joining CVR Energy on May 14, 2009, Mr. Morgan was granted 25,000 shares of restricted stock. On December 18, 2009, Mr. Morgan was granted 38,168 shares of restricted stock. On July 16, 2010, Messrs. Lipinski, Morgan and Vick were granted 222,532, 41,725 and 13,909 shares of restricted stock, respectively. On December 31, 2010, Messrs. Lipinski, Morgan and Vick were granted 222,333, 41,502 and 14,526 shares of restricted stock, respectively. On December 30, 2011, Messrs. Lipinski and Morgan were granted 266,952 and 8,810 shares of restricted stock, respectively.
Subject to vesting requirements, the named executive officers are required to retain at least 50% of their respective shares for a period equal to the lesser of (a) three years, commencing with the date of the award, or (b) as long as such individual remains an officer or employee of CVR Energy (or an affiliate). The named executive officers have the right to vote their shares of restricted stock immediately, although the shares are subject to transfer restrictions and vesting requirements that lapse in one-third annual increments beginning on the first anniversary of the date of grant, subject to immediate vesting under certain circumstances. The shares
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granted to Mr. Morgan in May 2009 become immediately vested in the event of his death or disability. The shares granted to Mr. Lipinski become immediately vested in the event his employment is terminated without cause. All other grants of restricted stock become immediately vested in the event of the relevant named executive officer’s death, disability or retirement, or in the event of any of the following: (a) such named executive officer’s employment is terminated other than for cause within the one year period following a change in control of CVR Energy, Inc.; (b) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (c) such named executive officer’s employment is terminated under certain circumstances prior to a change in control. The terms disability, retirement, cause, good reason and change in control are all defined in the CVR Energy LTIP.
The following table reflects the value of accelerated vesting of the unvested restricted stock awards held by the named executive officers assuming the triggering event took place on December 31, 2011, and based on the closing price of CVR Energy common stock as of such date, which was $18.73 per share.
Value of Accelerated Vesting of Restricted Stock Awards
| Death ($) | Disability ($) | Retirement ($) | Termination without Cause or with Good Reason ($) |
|||||||||||||||||
| (1) | (2) | |||||||||||||||||||
| John J. Lipinski |
10,554,879 | 10,554,879 | 10,554,879 | 10,554,879 | 10,554,879 | |||||||||||||||
| Edward A. Morgan |
1,598,587 | 1,598,587 | 1,598,587 | — | 1,598,587 | |||||||||||||||
| Kevan A. Vick |
355,046 | 355,046 | 355,046 | — | 355,046 | |||||||||||||||
| (1) | Termination without cause or resignation for good reason not in connection with a change in control. |
| (2) | Termination without cause or resignation for good reason in connection with a change in control. |
Each of the named executive officers of our general partner who is employed by our general partner and Mr. Vick (who was employed by CVR Energy through December 31, 2011) has been granted phantom units pursuant to the CVR Partners, LP Long-Term Incentive Plan (the “CVR Partners LTIP”). In connection with the commencement of his employment on June 1, 2011, Mr. Kelley was granted 50,659 phantom units and on August 22, 2011, Mr. Maffett was granted 12,815 phantom units. On December 30, 2011, Messrs. Kelley, Maffett and Vick were granted 40,291, 11,080 and 13,252 phantom units, respectively.
Each phantom unit represents the right to receive one common unit of the Partnership upon vesting. Subject to vesting requirements, the named executive officers are required to retain at least 50% of their respective common units for a period equal to the lesser of (a) three years, commencing with the date of the award, or (b) as long as such individual remains an officer or employee of the Partnership (or an affiliate). The phantom units are subject to transfer restrictions and are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided that the executives continue to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. The phantom units granted to Mr. Kelley become immediately vested in the event his employment is terminated without cause. All other grants of phantom units become immediately vested in the event of the relevant named executive officer’s death, disability or retirement, or in the event of any of the following: (a) such named executive officer’s employment is terminated other than for cause within the one year period following a change in control; (b) such named executive officer resigns from employment for good reason within the one year period following a change in control; or (c) such named executive officer’s employment is terminated under certain circumstances prior to a change in control. The terms disability, retirement, cause, good reason and change in control are all defined in the CVR Partners LTIP.
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The following table reflects the value of accelerated vesting of the unvested phantom unit awards held by the named executive officers assuming the triggering event took place on December 31, 2011, and based on the closing price of the Partnership common units as of such date, which was $24.82 per share.
Value of Accelerated Vesting of Phantom Unit Awards
| Death ($) | Disability ($) | Retirement ($) | Termination without Cause or with Good Reason ($) |
|||||||||||||||||
| (1) | (2) | |||||||||||||||||||
| Byron R. Kelley |
2,257,379 | 2,257,379 | 2,257,379 | 2,257,379 | 2,257,379 | |||||||||||||||
| Randal T. Maffett |
593,074 | 593,074 | 593,074 | — | 593,074 | |||||||||||||||
| Kevan A. Vick |
328,915 | 328,915 | 328,915 | — | 328,915 | |||||||||||||||
| (1) | Termination without cause or resignation for good reason not in connection with a change in control. |
| (2) | Termination without cause or resignation for good reason in connection with a change in control. |
Compensation of Directors
Directors of our general partner who are not officers, employees or directors of CVR Energy or its affiliates receive compensation for their services. Prior to the completion of the Initial Public Offering in April 2011, independent directors of our general partner received an annual cash fee of $75,000, with the audit committee chair receiving an additional annual cash fee of $15,000. Subsequent to the Initial Public Offering until June 30, 2011, independent directors received an annual cash fee of $50,000, with the audit committee chair receiving an additional annual cash fee of $15,000. Beginning July 1, 2011, independent directors receive an annual director fee of $55,000. The audit committee chair receives an additional fee of $15,000 per year, while independent directors serving on the audit committee receive an additional fee of $7,500 per year. The compensation committee chair receives an additional fee of $8,000 per year, while independent directors serving on the compensation committee receive an additional fee of $5,000 per year. The chair of the environmental, health and safety committee receives an additional fee of $8,000 per year, while independent directors serving on the environmental, health and safety committee receive an additional fee of $5,000 per year. All fees have been pro-rated based on the amount of time such fee was in place. In addition, independent directors also receive an annual award of common units with a value of $60,000 and is also reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors (and committees thereof) of our general partner and for other director-related education expenses.
The following table sets forth the compensation received by each independent director of our general partner for the year ended December 31, 2011.
| Name |
Fees Earned or Paid
in Cash (1)($) |
Unit Awards (2)($) | Total Compensation ($) | |||||||||
| Donna R. Ecton |
81,125 | 401,476 | 482,601 | |||||||||
| Frank M. Muller, Jr. |
59,807 | 264,892 | 324,699 | |||||||||
| Mark A. Pytosh |
39,417 | 89,190 | 128,607 | |||||||||
| Jon R. Whitney |
37,917 | 89,190 | 127,107 | |||||||||
| (1) | Amounts reflected in this column include annual retainer fees and additional fees for service as committee members, including the chair positions during 2011. |
| (2) | Each of the independent directors was granted 2,418 common units on December 30, 2011, which are subject to the retention requirement described below. The number of common units granted in 2011 was based on the closing market price of the Partnership’s common units on the date of the grant, which was $24.82 per unit. In connection with the appointment of Messrs. Pytosh and Whitney to the board, each of |
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| them was granted 1,478 common units on June 1, 2011, which are subject to the retention requirements described below. In connection with the completion of the Initial Public Offering, Ms. Ecton and Mr. Muller were awarded 14,655 and 8,793 phantom units, respectively, which became fully vested six months after the date of grant on October 12, 2011 and are subject to the retention requirements described below. The dollar amounts in the table reflect the grant date fair value of these phantom units in accordance with FASB ASC Topic 718. |
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The following table presents information regarding beneficial ownership of our common units as of February 22, 2012 by:
| • | our general partner; |
| • | each of our general partner’s directors; |
| • | each of our general partner’s executive officers; |
| • | each unitholder known by us to beneficially hold five percent or more of our outstanding units; and |
| • | all of our general partner’s named executive officers and directors as a group. |
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all common units beneficially owned, subject to community property laws where applicable. The business address for each of our beneficial owners is c/o CVR Partners, LP, 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479.
| Name of Beneficial Owner |
Common Units Beneficially Owned |
|||||||
| Number | Percent | |||||||
| CVR GP, LLC(1) |
— | — | ||||||
| Coffeyville Resources, LLC(2) |
50,920,000 | 69.7 | % | |||||
| John J. Lipinski(3) |
187,500 | * | ||||||
| Byron R. Kelley(4) |
— | — | ||||||
| Stanley A. Riemann |
60,000 | * | ||||||
| Frank A. Pici |
— | — | ||||||
| Edmund S. Gross |
— | — | ||||||
| Christopher G. Swanberg |
15,000 | * | ||||||
| Randal T. Maffett(5) |
— | — | ||||||
| Donna R. Ecton(6) |
24,433 | * | ||||||
| Frank M. Muller, Jr.(7) |
33,086 | * | ||||||
| Mark A. Pytosh(8) |
53,896 | * | ||||||
| Jon R. Whitney(9) |
10,896 | * | ||||||
| All directors and executive officers of our general partner as a group (11 persons)(10) |
384,811 | * | ||||||
| * | Less than 1% |
| (1) | CVR GP, LLC, a wholly-owned subsidiary of Coffeyville Resources, is our general partner and manages and operates our business and has a non-economic general partner interest. |
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| (2) | Coffeyville Resources, LLC is an indirect wholly-owned subsidiary of CVR Energy, a publicly traded company. CVR Energy may be deemed to have direct beneficial ownership of the common units held by Coffeyville Resources, LLC by virtue of its control of Coffeyville Resources, LLC. The directors of CVR Energy are John J. Lipinski, Barbara M. Baumann, William J. Finnerty, C. Scott Hobbs, George E. Matelich, Steve A. Nordaker, Robert T. Smith, Joseph E. Sparano and Mark E. Tomkins. |
| (3) | Mr. Lipinski owns 62,500 common units directly. In addition, Mr. Lipinski may be deemed to be the beneficial owner of an additional 125,000 common units, which are owned by the 2011 Lipinski Exempt Family Trust, which are held in trust for the benefit of Mr. Lipinski’s family. Mr. Lipinski’s spouse is the trustee of the trust. |
| (4) | Mr. Kelley was awarded 50,659 phantom units on June 1, 2011 and 40,291 phantom units on December 30, 2011. Each phantom unit represents the right to receive one common unit upon vesting. These phantom units are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided that the executive continues to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. Subject to vesting requirements, Mr. Kelley is required to retain at least 50% of such common units for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as Mr. Kelley remains an officer or employee of the Company (or an affiliate). No portion of the phantom units held by Mr. Kelley will vest within 60 days of February 23, 2012. Therefore, such phantom units do not give Mr. Kelley beneficial ownership of any of our common units. |
| (5) | Mr. Maffett was awarded 12,815 phantom units on August 22, 2011 and 11,080 phantom units on December 30, 2011. Each phantom unit represents the right to receive one common unit upon vesting. These phantom units are scheduled to become vested in equal installments on the first three anniversaries of the date of grant, provided that the executive continues to serve as an employee of the Partnership or one of its subsidiaries or parents on each such date, subject to accelerated vesting under certain circumstances as described in more detail in the section titled “Change-in-Control and Termination Payments” below. Subject to vesting requirements, Mr. Maffett is required to retain at least 50% of such common units for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as Mr. Maffett remains an officer or employee of the Company (or an affiliate). No portion of the phantom units held by Mr. Maffett will vest within 60 days of February 23, 2012. Therefore, such phantom units do not give Mr. Maffett beneficial ownership of any of our common units. |
| (6) | Ms. Ecton purchased 12,500 common units in connection with CVR Partners’ Initial Public Offering in April 2011. Ms. Ecton was awarded 14,655 phantom units in connection with the Initial Public Offering, subject to a six-month vesting period. Upon vesting in October 2011, the phantom units converted to 14,655 common units, with 4,412 common units being withheld for tax purposes, resulting in a net award of 10,243 common units. Ms. Ecton was also awarded 2,418 common units on December 30, 2011, with 728 common units being withheld for tax purposes, resulting in a net award of 1,690 common units. These common units vested immediately. However, Ms. Ecton is required to retain at least 60% of the common units (including those vesting in October 2011 through the phantom unit award in April 2011) awarded for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as she remains on the Board. |
| (7) | Mr. Muller purchased 21,875 common units in connection with CVR Partners’ Initial Public Offering in April 2011. Mr. Muller was awarded 8,793 phantom units in connection with the Initial Public Offering, subject to a six-month vesting period. Upon vesting in October 2011, the phantom units converted to 8,793 common units. Mr. Muller was also awarded 2,418 common units on December 30, 2011. These common units vested immediately. However, Mr. Muller is required to retain at least 60% of the common units (including those vesting in October 2011 through the phantom unit award in April 2011) awarded for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as he remains on the Board. |
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| (8) | Mr. Pytosh purchased 50,000 common units in connection with CVR Partners’ Initial Public Offering in April 2011. Mr. Pytosh was awarded 1,478 common units on June 1, 2011 and 2,418 common units on December 30, 2011. These common units vested immediately. However, Mr. Pytosh is required to retain at least 60% of the common units awarded for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as he remains on the Board. |
| (9) | Mr. Whitney purchased 7,000 common units in connection with CVR Partners’ Initial Public Offering in April 2011. Mr. Whitney was awarded 1,478 common units on June 1, 2011 and 2,418 common units on December 30, 2011. These common units vested immediately. However, Mr. Whitney is required to retain at least 60% of the common units awarded for a period equal to the lesser of (i) three years, commencing with the date of the award, or (ii) as long as he remains on the Board. |
| (10) | The number of common units owned by all of the directors and executive officers of our general partner, as a group, reflects the sum of (1) the 187,500 common units owned by Mr. Lipinski, the 60,000 common units owned by Mr. Riemann and the 15,000 common units owned by Mr. Christopher G. Swanberg, (2) the 24,433 common units owned by Ms. Ecton, (3) the 33,086 common units owned by Mr. Muller, (4) the 53,896 common units owned by Mr. Pytosh and (5) the 10,896 common units owned by Mr. Whitney. |
The following table sets forth, as of February 22, 2012, the number of shares of common stock of CVR Energy owned by each of the executive officers and directors of our general partner and all directors and executive officers of our general partner as a group.
| Shares Beneficially Owned | ||||||||
| Name and Address |
Number | Percent | ||||||
| John J. Lipinski |
755,236 | * | ||||||
| Byron R. Kelley |
— | — | ||||||
| Stanley A. Riemann |
200,553 | * | ||||||
| Frank A. Pici |
35,071 | * | ||||||
| Edmund S. Gross |
160,883 | * | ||||||
| Christopher G. Swanberg |
61,578 | * | ||||||
| Randal T. Maffett |
— | — | ||||||
| Donna R. Ecton |
3,500 | * | ||||||
| Frank M. Muller, Jr. |
— | — | ||||||
| Mark A. Pytosh |
— | — | ||||||
| Jon R. Whitney |
— | — | ||||||
| All directors and executive officers of our general partner as a group (11 persons) |
1,216,821 | 1.4 | % | |||||
| * | Less than 1% |
Item 13. Certain Relationships and Related Transactions, and Director Independence
Coffeyville Resources, a wholly-owned subsidiary of CVR Energy, owns (i) 50,920,000 common units, representing approximately 70% of our outstanding units and (ii) our general partner with its non-economic general partner interest (which does not entitle it to receive distributions) in us. On February 13, 2012, CVR Energy announced its intention to sell a portion of its common unit holdings in CVR Partners. There can be no assurance as to the terms, conditions, amount or timing of such offering, or whether such offering will take place at all. This announcement does not constitute an offer of any securities for sale and is being made pursuant to and in accordance with Rule 135 under the Securities Act.
Agreements with CVR Energy
In connection with the formation of CVR Partners and the initial public offering of CVR Energy in October 2007, we entered into several agreements with CVR Energy and its affiliates that govern the business relations among us, CVR Energy and its affiliates and our general partner. In connection with our Initial Public Offering in
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April 2011, we amended and restated certain of the intercompany agreements and entered into several new agreements with CVR Energy and its affiliates, including our partnership agreement. These agreements were not the result of arm’s –length negotiations and the terms of these agreements are not necessarily at least as favorable to the parties to these agreements as terms which could have been obtained from unaffiliated third parties.
Coke Supply Agreement
We are party to a pet coke supply agreement with CVR Energy pursuant to which CVR Energy supplies us with pet coke. This agreement provides that CVR Energy must deliver to the Partnership during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at CVR Energy’s Coffeyville, Kansas petroleum refinery or (ii) 500,000 tons of pet coke. We are also obligated to purchase this annual required amount. If during a calendar month CVR Energy produces more than 41,667 tons of pet coke, then we will have the option to purchase the excess at the purchase price provided for in the agreement. If we decline to exercise this option, CVR Energy may sell the excess to a third party.
The Partnership obtains most (over 70% on average during the last five years) of the pet coke it needs from CVR Energy’s adjacent crude oil refinery pursuant to the pet coke supply agreement, and procures the remainder on the open market. The price we pay 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.
We also pay any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. We will be entitled to offset any amount payable for the pet coke against any amount due from CVR Energy under the feedstock and shared services agreement between the parties. If we fail to pay an invoice on time, we will pay interest on the outstanding amount payable at a rate of three percent above the prime rate.
In the event CVR Energy delivers pet coke to us on a short term basis and such pet coke is off-specification on more than 20 days in any calendar year, there will be a price adjustment to compensate us and/or capital contributions will be made to us to allow us to modify our equipment to process the pet coke received. If CVR Energy determines that there will be a change in pet coke quality on a long-term basis, then it will be required to notify us of such change with at least three years’ notice. We will then determine the appropriate changes necessary to our nitrogen fertilizer plant in order to process such off-specification pet coke. CVR Energy will compensate us for the cost of making such modifications and/or adjust the price of pet coke on a mutually agreeable commercially reasonable basis.
The terms of the pet coke supply agreement provide benefits both to us and CVR Energy’s petroleum business. The cost of the pet coke supplied by CVR Energy to us in most cases will be lower than the price which we otherwise would pay to third parties. The cost to us will be lower both because the actual price paid will be lower and because we will pay significantly reduced transportation costs (since the pet coke is supplied by an adjacent facility which will involve no freight or tariff costs). In addition, because the cost we pay will be formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), we will enjoy lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.
In return for CVR Energy receiving a potentially lower price for pet coke in periods when the pet coke price is impacted by lower UAN prices, it enjoys the following benefits associated with the disposition of a low value by-product of the refining process: avoiding the capital cost and operating expenses associated with handling pet coke; enjoying flexibility in its crude slate and operations as a result of not being required to meet a specific pet coke quality; and avoiding the administration, credit risk and marketing fees associated with selling pet coke.
We may be obligated to provide security for our payment obligations under the agreement if in CVR Energy’s sole judgment there is a material adverse change in our financial condition or liquidity position or in
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our ability to make payments. This security shall not exceed an amount equal to 21 times the average daily dollar value of pet coke we purchase for the 90-day period preceding the date on which CVR Energy gives us notice that it has deemed that a material adverse change has occurred. Unless otherwise agreed by CVR Energy and us, we can provide such security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If we do not provide such security, CVR Energy may require us to pay for future deliveries of pet coke on a cash-on-delivery basis, failing which it may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days’ prior written notice. Additionally, we may terminate the agreement within 60 days of providing security, so long as we provide five days’ prior written notice.
The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements.
The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain affiliates.
Our pet coke cost per ton purchased from CVR Energy averaged $28, $11 and $22 for the years ended December 31, 2011, 2010 and 2009, respectively. Total purchases of pet coke from CVR Energy were approximately $10.7 million, $4.0 million and $7.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. Third-party pet coke prices averaged $45, $40 and $37 for the years ended December 31, 2011, 2010 and 2009, respectively. Total purchases of pet coke from third parties were approximately $6.2 million, $3.4 million and $5.0 million for the years ended December 31, 2011, 2010 and 2009, respectively.
Feedstock and Shared Services Agreement
We are party to a feedstock and shared services agreement with CVR Energy in October 2007 under which we and CVR Energy provide feedstock and other services to one another. These feedstocks and services are utilized in the respective production processes of CVR Energy’s Coffeyville, Kansas refinery and our nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas.
Pursuant to the feedstock agreement, we and CVR Energy have the obligation to transfer excess hydrogen to one another. We are only obligated to provide hydrogen to CVR Energy upon demand if, the hydrogen is not required for operation of our fertilizer plant, as determined in a commercially reasonable manner as based upon our current or anticipated operational needs. The feedstock agreement provides hydrogen supply and pricing terms for sales of hydrogen by both parties. Pricing for sales of hydrogen from us to CVR Energy is structured to make us whole as if we had used the hydrogen sold to CVR Energy to produce ammonia. After extended periods of time and in excess of certain quantity thresholds, pricing to CVR Energy reverts to a UAN pricing structure to
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make us whole, as if we had produced UAN for sale. Pricing for sales of hydrogen by CVR Energy to us is based off of the price of natural gas. The hydrogen sales that we and CVR Energy make to each other are netted on a monthly basis, and we or CVR Energy will be paid to the extent that either of us sells more hydrogen than purchased in any given month. Net monthly sales of hydrogen to CVR Energy have been reflected as net sales for CVR Partners. Net monthly receipts of hydrogen from CVR Energy have been reflected in cost of product sold (exclusive of depreciation and amortization) for CVR Partners. For the years ended December 31, 2011, 2010 and 2009, the net sales generated from the sale of hydrogen to CVR Energy were approximately $14.2 million, $0.1 million and $0.8 million, respectively. For the years ended December 31, 2011, 2010 and 2009, CVR Partners also recognized $1.0 million, $1.8 million and $1.6 million of cost of product sold (exclusive of depreciation and amortization) related to the transfer of excess hydrogen from the refinery. At December 31, 2011 and 2010, there was approximately $0.1 million and $0, respectively, of receivables included in prepaid expenses and other current assets on the Consolidated Balance Sheets associated with unpaid balances related to hydrogen sales.
The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. Net reimbursed or (paid) direct operating expenses recorded during the years ended December 31, 2011, 2010 and 2009 were approximately $(0.3) million, $(0.1) million and $0.2 million, respectively, related to high-pressure steam. Reimbursements or paid amounts for each of the years on a gross basis were nominal.
We are also obligated to make available to CVR Energy any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by us in a commercially reasonable manner. The price for the nitrogen is based on a cost of $0.035 cents per kilowatt hour, as adjusted to reflect changes in our electric bill. Reimbursed direct operating expenses associated with nitrogen for the years ended December 31, 2011, 2010 and 2009, were approximately $1.5 million, $0.8 million and $0.8 million, respectively. No amounts were paid by us to CVR Energy for any of the years.
The agreement also provides that both we and CVR Energy must deliver instrument air to one another in some circumstances. We must make instrument air available for purchase by CVR Energy at a minimum flow rate, to the extent produced by the Linde air separation plant and available to us. The price for such instrument air is $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in our electric bill. To the extent that instrument air is not available from the Linde air separation plant and is available from CVR Energy, CVR Energy is required to make instrument air available to us for purchase at a price of $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in CVR Energy’s electric bill. Reimbursed direct operating expenses recorded for the years ended December 31, 2011, 2010 and 2009 were zero. Reimbursements or paid amounts for each of the years on a gross basis were nominal.
The agreement provides a mechanism pursuant to which we may transfer a tail gas stream (which is otherwise flared) to CVR Energy which installed a pipe between the Coffeyville, Kansas refinery and the nitrogen fertilizer plant to transfer the tail gas. We agreed to pay CVR Energy the cost of installing the pipe over the next three years and in the fourth year provide an additional 15% to cover the cost of capital. At December 31, 2011, an asset of approximately $0.2 million was included in other current assets and approximately $1.5 million was included in other non-current assets with an offset liability of approximately $0.6 million in other current liabilities and approximately $0.9 million other non-current liabilities in our Consolidated Balance Sheet.
With respect to oxygen requirements, we are obligated to provide oxygen produced by the Linde air separation plant and made available to us to the extent that such oxygen is not required for operation of our nitrogen fertilizer plant. The oxygen is required to meet certain specifications and is to be sold at a fixed price.
The agreement also addresses the means by which we and CVR Energy obtain natural gas. Currently, natural gas is delivered to both our nitrogen fertilizer plant and the refinery pursuant to a contract between CVR Energy and Atmos Energy Corp., or Atmos. Under the feedstock and shared services agreement, we reimburse
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CVR Energy for natural gas transportation and natural gas supplies purchased on our behalf. At our request or at the request of CVR Energy, in order to supply us with natural gas directly, both parties will be required to use their commercially reasonable efforts to (i) add us as a party to the current contract with Atmos or reach some other mutually acceptable accommodation with Atmos whereby both we and CVR Energy would each be able to receive, on an individual basis, natural gas transportation service from Atmos on similar terms and conditions as set forth in the current contract, and (ii) purchase natural gas supplies on their own account.
The agreement also addresses the allocation of various other feedstocks, services and related costs between the parties. Sour water, water for use in fire emergencies, finished product tank capacity, costs associated with security services, and costs associated with the removal of excess sulfur are all allocated between the two parties by the terms of the agreement. The agreement also requires us to reimburse CVR Energy for utility costs related to a sulfur processing agreement between Tessenderlo Kerley, Inc. and CVR Energy. We have a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both our and CVR Energy’s existing agreements with Tessenderlo Kerley are allocated equally between the two parties except in certain circumstances.
The parties may temporarily suspend the provision of feedstocks or services pursuant to the terms of the agreement if repairs or maintenance are necessary on applicable facilities. Additionally, the agreement imposes minimum insurance requirements on the parties and their affiliates.
The agreement has an initial term of 20 years, and will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the Coffeyville, Kansas refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent. Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain affiliates.
Raw Water and Facilities Sharing Agreement
We are party to a raw water and facilities sharing agreement with CVR Energy which (i) provides for the allocation of raw water resources between the refinery and our nitrogen fertilizer plant and (ii) provides for the management of the water intake system (consisting primarily of a water intake structure, water pumps, meters, and a short run of piping between the intake structure and the origin of the separate pipes that transport the water to each facility) which draws raw water from the Verdigris River for both our facility and CVR Energy’s refinery. This agreement provides that a water management team consisting of one representative from each party to the agreement will manage the Verdigris River water intake system. The water intake system is owned and operated by CVR Energy. The agreement provides that both companies have an undivided one-half interest in the water rights that allow the water to be removed from the Verdigris River for use at our nitrogen fertilizer plant and CVR Energy’s refinery.
The agreement provides that both our nitrogen fertilizer plant and the refinery are entitled to receive sufficient amounts of water from the Verdigris River each day to enable them to conduct their businesses at their appropriate operational levels. However, if the amount of water available from the Verdigris River is insufficient
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to satisfy the operational requirements of both facilities, then such water shall be allocated between the two facilities on a prorated basis. This prorated basis will be determined by calculating the percentage of water used by each facility over the two calendar years prior to the shortage, making appropriate adjustments for any operational outages involving either of the two facilities.
Costs associated with operation of the water intake system and administration of water rights are also allocated on a prorated basis, calculated by CVR Energy based on the percentage of water used by each facility during the calendar year in which such costs are incurred. However, in certain circumstances, such as where one party bears direct responsibility for the modification or repair of the water pumps, one party will bear all costs associated with such activity. Additionally, we must reimburse CVR Energy for electricity required to operate the water pumps on a prorated basis that is calculated monthly.
Either we or CVR Energy are entitled to terminate the agreement by giving at least three years’ prior written notice. Between the time that notice is given and the termination date, CVR Energy must cooperate with us to allow us to build our own water intake system on the Verdigris River to be used for supplying water to our nitrogen fertilizer plant. CVR Energy is required to grant easements and access over its property so that we can construct and utilize such new water intake system, provided that no such easements or access over CVR Energy’s property shall have a material adverse affect on its business or operations at the refinery. We will bear all costs and expenses for such construction if we are the party that terminated the original water sharing agreement. If CVR Energy terminates the original water sharing agreement, we may either install a new water intake system at our own expense, or require CVR Energy to sell the existing water intake system to us for a price equal to the depreciated book value of the water intake system as of the date of transfer.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The parties may obtain injunctive relief to enforce their rights under the agreement. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
The term of the agreement is perpetual unless (1) the agreement is terminated by either party upon three years’ prior written notice in the manner described above or (2) the agreement is otherwise terminated by the mutual written consent of the parties.
Real Estate Transactions
Land Transfer. In January 2008, CVR Energy transferred five parcels of land consisting of approximately 30 acres located on the Coffeyville, Kansas site to us. No consideration was exchanged. The land was transferred for purposes of (i) creating clean distinctions between the refinery and the fertilizer plant property, (ii) providing us with additional space for completing our UAN expansion and (iii) providing us with additional storage area for pet coke.
Cross-Easement Agreement. We are party to a cross-easement agreement with CVR Energy so that both we and CVR Energy can access and utilize each other’s land in certain circumstances in order to operate our respective businesses. The agreement grants easements for the benefit of both parties and establishes easements for operational facilities, pipelines, equipment, access, and water rights, among other easements. The intent of the agreement is to structure easements that provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party’s property.
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The agreement provides that facilities located on each party’s property will generally be owned and maintained by the property-owning party; provided, however, that in certain specified cases where a facility that benefits one party is located on the other party’s property, the benefited party will have the right to use, and will be responsible for operating and maintaining, the overlapping facility.
The easements granted under the agreement are non-exclusive to the extent that future grants of easements do not interfere with easements granted under the agreement. The duration of the easements granted under the agreement will vary, and some will be perpetual. Easements pertaining to certain facilities that are required to carry out the terms of our other agreements with CVR Energy will terminate upon the termination of such related agreements. We have obtained a water rights easement from CVR Energy that is perpetual in duration. See “— Raw Water and Facilities Sharing Agreement.”
The agreement contains an obligation to indemnify, defend and hold harmless the other party against liability arising from negligence or willful misconduct by the indemnifying party. The agreement also requires the parties to carry minimum amounts of employer’s liability insurance, commercial general liability insurance, and other types of insurance. If either party transfers its fee simple ownership interest in the real property governed by the agreement, the new owner of the real property will be deemed to have assumed all of the obligations of the transferring party under the agreement, except that the transferring party will retain liability for all obligations under the agreement which arose prior to the date of transfer.
Lease Agreement. We are party to a lease agreement with CVR Energy in October 2007 under which we lease certain office and laboratory space. The initial term of the lease will expire in October 2017, provided, however, that we may terminate the lease at any time during the initial term by providing 180 days’ prior written notice. In addition, we have the option to renew the lease agreement for up to five additional one-year periods by providing CVR Energy with notice of renewal at least 60 days prior to the expiration of the then-existing term. There were no unpaid amounts outstanding with respect to the lease agreement as of December 31, 2011 and 2010, respectively.
Environmental Agreement
We are party to an environmental agreement with CVR Energy which provides for certain indemnification and access rights in connection with environmental matters affecting the Coffeyville, Kansas refinery and the nitrogen fertilizer plant.
To the extent that one party’s property experiences environmental contamination due to the activities of the other party and the contamination is known at the time the agreement was entered into, the contaminating party is required to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for expenses incurred in connection with implementing such measures.
To the extent that liability arises from environmental contamination that is caused by CVR Energy but is also commingled with environmental contamination caused by us, CVR Energy may elect in its sole discretion and at its own cost and expense to perform government mandated environmental activities relating to such liability, subject to certain conditions and provided that CVR Energy will not waive any rights to indemnification or compensation otherwise provided for in the agreement.
The agreement also addresses situations in which a party’s responsibility to implement such government-mandated environmental activities as described above may be hindered by the property-owning party’s creation of capital improvements on the property. If a contaminating party bears such responsibility but the property-owning party desires to implement a planned and approved capital improvement project on its property, the parties must meet and attempt to develop a soil management plan together. If the parties are unable to agree on a soil management plan 30 days after receiving notice, the property-owning party may proceed with its own commercially reasonable soil management plan. The contaminating party is responsible for the costs of disposing of hazardous materials pursuant to such plan.
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If the property-owning party needs to do work that is not a planned and approved capital improvement project but is necessary to protect the environment, health, or the integrity of the property, other procedures will be implemented. If the contaminating party still bears responsibility to implement government-mandated environmental activities relating to the property and the property-owning party discovers contamination caused by the other party during work on the capital improvement project, the property-owning party will give the contaminating party prompt notice after discovery of the contamination, and will allow the contaminating party to inspect the property. If the contaminating party accepts responsibility for the contamination, it may proceed with government-mandated environmental activities relating to the contamination, and it will be responsible for the costs of disposing of hazardous materials relating to the contamination. If the contaminating party does not accept responsibility for such contamination or fails to diligently proceed with government-mandated environmental activities related to the contamination, then the contaminating party must indemnify and reimburse the property-owning party upon the property-owning party’s demand for costs and expenses incurred by the property-owning party in proceeding with such government-mandated environmental activities.
Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement has a term of at least 20 years or for so long as the feedstock and shared services agreement is in force, whichever is longer. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages, from either party or certain of its affiliates.
The agreement also provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement is entered into to the extent such contamination or releases are identified in reasonable detail through October 2012. The agreement further provides for indemnification in the case of contamination or releases that occur subsequent to the execution of the agreement. If one party causes such contamination or release on the other party’s property, the latter party must notify the contaminating party, and the contaminating party must take steps to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for the costs associated with doing such work.
The agreement also grants each party reasonable access to the other party’s property for the purpose of carrying out obligations under the agreement. However, both parties must keep certain information relating to the environmental conditions on the properties confidential. Furthermore, both parties are prohibited from investigating soil or groundwater conditions except as required for government-mandated environmental activities, in responding to an accidental or sudden contamination of certain hazardous materials, or in connection with implementation of our comprehensive pet coke management plan.
The agreement provided for the development of a comprehensive pet coke management plan that established procedures for the management of pet coke and the identification of significant pet coke-related contamination. Also, the parties agreed to indemnify and defend one another and each other’s affiliates against liabilities arising under the pet coke management plan or relating to a failure to comply with or implement the pet coke management plan.
Omnibus Agreement
We are party to an omnibus agreement with CVR Energy and our general partner, pursuant to which we have agreed not to, and will cause our controlled affiliates not to, engage in, whether by acquisition or otherwise, (i) the ownership or operation within the United States of any refinery with processing capacity greater than 20,000 bpd whose primary business is producing transportation fuels or (ii) the ownership or operation outside the United States of any refinery, regardless of its processing capacity or primary business, or a refinery restricted business, in either case, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of our outstanding units. The restrictions will not apply to:
| • | any refinery restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a refinery restricted business, as determined in good faith by our general partner’s board of directors; provided, however, if at any time we |
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| complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the refinery-related assets to CVR Energy for their fair market value plus any additional tax or other similar costs that would be required to transfer the refinery-related assets to CVR Energy separately from the acquired business or package of assets; |
| • | engaging in any refinery restricted business subject to the offer to CVR Energy described in the immediately preceding bullet point pending CVR Energy’s determination whether to accept such offer and pending the closing of any offers CVR Energy accepts; |
| • | engaging in any refinery restricted business if CVR Energy has previously advised us that it has elected not to cause it to acquire or seek to acquire such business; or |
| • | acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any refinery restricted business. |
Under the omnibus agreement, CVR Energy has agreed not to, and will cause its controlled affiliates other than us not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as CVR Energy and certain of its affiliates continue to own at least 50% of our outstanding units. The restrictions do not apply to:
| • | any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by CVR Energy’s board of directors, as applicable; provided, however, if at any time CVR Energy completes such an acquisition, it must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to us for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to us separately from the acquired business or package of assets; |
| • | engaging in any fertilizer restricted business subject to the offer to us described in the immediately preceding bullet point pending our determination whether to accept such offer and pending the closing of any offers the we accept; |
| • | engaging in any fertilizer restricted business if we have previously advised CVR Energy that we have elected not to acquire such business; or |
| • | acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any fertilizer restricted business. |
Under the omnibus agreement, we have also agreed that CVR Energy will have a preferential right to acquire any assets or group of assets that do not constitute assets used in a fertilizer restricted business. In determining whether to exercise any preferential right under the omnibus agreement, CVR Energy will be permitted to act in its sole discretion, without any fiduciary obligation to us or the unitholders whatsoever. These obligations will continue so long as CVR Energy owns our general partner directly or indirectly.
Services Agreement
We obtain certain management and other services from CVR Energy pursuant to a services agreement between us, CVR GP, LLC and CVR Energy. Under this agreement, our general partner has engaged CVR Energy to conduct our day-to-day business operations. CVR Energy provides us with the following services under the agreement, among others:
| • | services from CVR Energy’s employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall serve us on a shared, part-time basis only, unless we and CVR Energy agree otherwise; |
| • | administrative and professional services, including legal, accounting, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
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| • | management of our property and the property of our operating subsidiary in the ordinary course of business; |
| • | recommendations on capital raising activities to the board of directors of our general partner, including the issuance of debt or equity interests, the entry into credit facilities and other capital market transactions; |
| • | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for us, and providing safety and environmental advice; |
| • | recommending the payment of distributions; and |
| • | managing or providing advice for other projects, including acquisitions, as may be agreed by CVR Energy and our general partner from time to time. |
As payment for services provided under the agreement, we, our general partner or CRNF must pay CVR Energy (i) all costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, other than administrative personnel, who provide the Partnership services under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by CVR Energy or its affiliates in connection with the employment of its employees, including administrative personnel, who provide the Partnership services under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by CVR Energy on a commercially reasonable basis, based on the percentage of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges. We must pay CVR Energy within 15 days for invoices it submits under the agreement.
We and our general partner are not required to pay any compensation, salaries, bonuses or benefits to any of CVR Energy’s employees who provide services to us or our general partner on a full-time or part-time basis; CVR Energy will continue to pay their compensation. However, personnel performing the actual day-to-day business and operations at the nitrogen fertilizer plant level will be employed directly by us and our subsidiaries, and we will bear all personnel costs for these employees.
Either CVR Energy or our general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. CVR Energy also has the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation does not relieve CVR Energy from its obligations under the agreement. Beginning on April 13, 2012, either CVR Energy or our general partner may terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, our general partner may terminate the agreement immediately if CVR Energy becomes bankrupt, or dissolves and commences liquidation or winding-up.
In order to facilitate the carrying out of services under the agreement, we, on the one hand, and CVR Energy and its affiliates, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.
The agreement also contains an indemnity provision whereby we, our general partner, and CRNF, as indemnifying parties, agree to indemnify CVR Energy and its affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by CVR Energy or other misconduct on its part, as provided in the agreement. The agreement also contains a provision stating that CVR Energy is an independent contractor under the agreement and nothing in the
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agreement may be construed to impose an implied or express fiduciary duty owed by CVR Energy, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from CVR Energy or certain affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement, or fraudulent or dishonest acts on our part.
Net amounts incurred under the services agreement for the years ended December 31, 2011, 2010 and 2009, were approximately $10.2 million $10.6 million and $12.1 million, respectively.
GP Services Agreement
We are party to a GP Services Agreement dated November 29, 2011 between us, CVR GP, LLC and CVR Energy. This agreement allows CVR Energy to engage CVR GP, LLC, in its capacity as our general partner, to provide CVR Energy with (i) business development and related services and (ii) advice or recommendations for such other projects as may be agreed between our general partner and CVR Energy from time to time. As payment for services provided under the agreement, CVR Energy must pay a prorated share of costs incurred by us or our general partner in connection with the employment of our employees who provide CVR Energy services on a part-time basis, as determined by our general partner on a commercially reasonable basis based on the percentage of total working time that such shared personnel are engaged in performing services for CVR Energy. Pursuant to this GP Services Agreement, one of the Partnership’s executive officers has performed business development services for CVR Energy from time to time.
CVR Energy is not required to pay any compensation, salaries, bonuses or benefits to any of our general partner’s employees who provide services to CVR Energy on a full-time or part-time basis; we will continue to pay their compensation.
Either CVR Energy or our general partner may temporarily or permanently exclude any particular service from the scope of the agreement upon 180 days’ notice. Our general partner also has the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of its affiliates or any other person or entity, though such delegation does not relieve the Partnership’s general partner from its obligations under the agreement. Either CVR Energy or the Partnership’s general partner may terminate the agreement upon at least 180 days’ notice, but not more than one year’s notice. Furthermore, CVR Energy may terminate the agreement immediately if the Partnership, or its general partner, become bankrupt, or dissolve and commence liquidation or winding-up.
Trademark License Agreement
We are party to a Trademark License Agreement with CVR Energy pursuant to which CVR Energy has granted us a non-exclusive, non-transferrable license to use the CVR Partners and Coffeyville Resources logos in connection with our business. We agreed to use the marks only in the form and manner and with appropriate legends as prescribed from time to time by CVR Energy, and CVR Energy agreed that the nature and quality of the business that uses the marks will conform to standards currently applied by CVR Partners. Either party can terminate the license with 60 days’ prior notice.
Registration Rights Agreement
In connection with our Initial Public Offering, we entered into an amended and restated registration rights agreement with Coffeyville Resources in April 2011, pursuant to which we may be required to register the sale of the common units Coffeyville Resources holds. Under the amended and restated registration rights agreement, Coffeyville Resources has the right to request that we register the sale of common units held by it on its behalf on six occasions, including requiring us to make available shelf registration statements permitting sales of common units into the market from time to time over an extended period. In addition, Coffeyville Resources and its
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permitted transferees have the ability to exercise certain piggyback registration rights with respect to their securities if we elect to register any of our equity interests. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of our common units held by Coffeyville Resources and any permitted transferee will be entitled to these registration rights, except that the demand registration rights may only be transferred in whole and not in part.
Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of the relationships between our general partner and its affiliates (including Coffeyville Resources and CVR Energy), on the one hand, and us and our public unitholders, on the other hand. Conflicts may arise as a result of (1) the overlap of directors and officers between our general partner and CVR Energy, which may result in conflicting obligations by these officers and directors, and (2) duties of our general partner to act for the benefit of CVR Energy and its stockholders, which may conflict with our interests and the interests of our public unitholders. The directors and officers of our general partner have fiduciary duties to manage our general partner in a manner beneficial to Coffeyville Resources, its owner, and the stockholders of CVR Energy, its indirect parent. At the same time, our general partner has a contractual duty under our partnership agreement to manage us in a manner that is in our best interests.
Whenever a conflict arises between our general partner, on the one hand, and us or any other public unitholder, on the other, our general partner will resolve that conflict. Our partnership agreement contains provisions that replace default fiduciary duties with contractual corporate governance standards as set forth therein. Our partnership agreement also restricts the remedies available to unitholders for actions taken that, without such replacement, might constitute breaches of fiduciary duty.
Our general partner will not be in breach of its obligations under our partnership agreement or its duties to us or our unitholders if the resolution of a conflict is:
| • | approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; |
| • | approved by the vote of a majority of the outstanding common units, excluding any units owned by the general partner or any of its affiliates, although our general partner is not obligated to seek such approval; |
| • | on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or |
| • | fair and reasonable to us, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us. |
Our general partner may, but is not required to, seek the approval of such resolution from the conflicts committee of its board of directors or from the common unitholders. If our general partner does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in our partnership agreement, our general partner or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When our partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the partnership, unless the context otherwise requires.
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Director Independence
While the NYSE does not require a listed publicly traded partnership, such as ours, to have a majority of independent directors on the board of directors of our general partner, the board of directors of our general partner consists of seven directors, four of whom the board has affirmatively determined are independent in accordance with the rules of the New York Stock Exchange. For discussion of the independence of the board of directors of our general partner, please see Item 10. Directors, Executive Officers and Corporate Governance – Management of the Partnership.
Item 14. Principal Accounting Fees and Services
As of February 23, 2012, the Audit Committee of the board of directors of our general partner has not appointed an independent registered public accounting firm for us for 2012.
The charter of the audit committee of the board of directors of our general partner, which is available on our website at www.cvrpartners.com, requires the audit committee to pre-approve all audit services and non-audit services (other than de minimis non-audit services as defined by the Sarbanes-Oxley Act of 2002) to be provided by our independent registered public accounting firm. The audit committee has adopted a pre-approval policy with respect to services that may be performed by the independent auditors. The Partnership’s audit committee pre-approved all fees incurred in fiscal year 2011.
The following table presents fees billed and expected to be billed for professional audit services rendered by KPMG LLP for fiscal years 2011 and 2010 and fees billed and expected to be billed for other services rendered by KPMG LLP for fiscal years 2011 and 2010.
| Fiscal Year 2011 |
Fiscal Year 2010 |
|||||||
| Audit fees (1) |
$ | 637,000 | $ | 1,204,000 | ||||
| Audit-related fees |
— | — | ||||||
| Tax fees (2) |
26,000 | 44,000 | ||||||
| All other fees |
— | — | ||||||
|
|
|
|
|
|||||
| Total |
$ | 663,000 | $ | 1,248,000 | ||||
|
|
|
|
|
|||||
| (1) | Represents the aggregate fees billed and expected to be billed for professional services rendered for the audit of the Partnership’s financial statements for fiscal years ended December 31, 2011 and 2010, assistance with Securities Act filings and related matters, consents issued in connection with Securities Act filings, and consultations on financial accounting and reporting standards arising during the course of the audit for fiscal years 2011 and 2010. Also includes the review of the consolidated financial statements included in the Partnership’s quarterly reports on Form 10-Q. The fees for 2010 also include fees for services associated with the filing of the registration statement and associated audits performed as part of the registration statement filings including consents, comfort letters and review of documents filed with the SEC. |
| (2) | Tax fees consist of fees for general income tax consulting and tax compliance. |
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PART IV
Item 15. Exhibits, Financial Statement Schedules
(a)(1) Financial Statements
See “Index to Consolidated Financial Statements” Contained in Part II, Item 8 of this Report.
(a)(2) Financial Statement Schedules
All schedules for which provision is made in the applicable accounting regulations of the Securities and Exchange Commission are not required under the related instructions or are inapplicable and therefore have been omitted.
(a)(3) Exhibits
| Exhibit Number |
Exhibit Title | |
| 3.1** | Second Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated April 13, 2011 (incorporated by reference to Exhibit 3.1 of the Form 10-Q filed on May 11, 2011) | |
| 3.2** | Amended and Restated Certificate of Limited Partnership of the Partnership, dated April 8, 2011 (incorporated by reference to Exhibit 3.2 of the Form 8-K, filed on April 13, 2011). | |
| 3.3** | Certificate of Formation of CVR GP, LLC, dated June 12, 2007 (incorporated by reference to Exhibit 3.3 of the Form S-1 filed on February 28, 2008). | |
| 3.4* | Third Amended and Restated Limited Liability Company Agreement of CVR GP, LLC, dated April 13, 2011. | |
| 4.1** | Specimen certificate for the common units (incorporated by reference to Appendix A to the Prospectus contained within the Form S-1/A filed on March 17, 2011). | |
| 10.1** | License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between Texaco Development Corporation and Farmland Industries, Inc., as amended (certain portions of this exhibit have been omitted pursuant to a confidential treatment order) (incorporated by reference to Exhibit 10.1 of the Form S-1/A filed on January 28, 2011). | |
| 10.2** | Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. (n/k/a Linde LLC) and Coffeyville Resources Nitrogen Fertilizers, LLC (certain portions of this exhibit have been omitted pursuant to a confidential treatment order) (incorporated by reference to Exhibit 10.2 of the Form S-1/A filed on January 28, 2011). | |
| 10.2.1** | First Amendment to Amended and Restated On-Site Product Supply Agreement, dated as of October 31, 2008, between Coffeyville Resources Nitrogen Fertilizers, LLC and Linde, Inc. (n/k/a Linde LLC) (incorporated by reference to Exhibit 10.3 of the Form 10-Q filed by CVR Energy, Inc. on November 13, 2008). | |
| 10.3** | Amended and Restated Electric Services Agreement dated August 1, 2010, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (incorporated by reference to Exhibit 10.1 of the Form 8-K filed by CVR Energy, Inc. on August 25, 2010). | |
| 10.4** | Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007). | |
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| Exhibit Number |
Exhibit Title | |
| 10.5** | Amended and Restated Cross-Easement Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.5 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.6** | Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.7 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007). | |
| 10.6.1** | Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.17.1 of the Form 10-K filed by CVR Energy, Inc. on March 28, 2008). | |
| 10.6.2** | Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.1 of the Form 10-Q filed by CVR Energy, Inc. on August 14, 2008). | |
| 10.7** | Amended and Restated Feedstock and Shared Services Agreement, dated as of April 13, 2011, among Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.4 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.8** | Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (incorporated by reference to Exhibit 10.9 of the Form 10-Q filed by CVR Energy, Inc. on December 6, 2007). | |
| 10.9** | Amended and Restated Services Agreement, dated as of April 13, 2011, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. (incorporated by reference to Exhibit 10.3 of the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.10** | Amended and Restated Omnibus Agreement, dated as of April 13, 2011, among CVR Energy, Inc., CVR GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.2 of the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.11** | Amended and Restated Registration Rights Agreement, dated as of April 13, 2011, among CVR Partners, LP and Coffeyville Resources, LLC (incorporated by reference to Exhibit 10.6 of the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.12** | Amended and Restated Contribution, Conveyance and Assumption Agreement, dated as of April 7, 2011, among Coffeyville Resources, LLC, CVR GP, LLC, Coffeyville Acquisition III LLC, CVR Special GP, LLC and CVR Partners, LP (incorporated by reference to Exhibit 10.1 of the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.13** | CVR Partners, LP Long-Term Incentive Plan (adopted March 16, 2011) (incorporated by reference to Exhibit 10.1 to the Form S-8 filed on April 12, 2011). | |
| 10.13.1**† | Form of Director Phantom Unit Agreement (incorporated by reference to Exhibit 10.13.1 of the Form S-1/A filed on March 17, 2011). | |
| 10.13.2**† | Form of Director Stock Option Agreement (incorporated by reference to Exhibit 10.13.2 of the Form S-1/A filed on March 17, 2011). | |
| 10.13.3**† | Form of CVR Partners, LP Long-Term Incentive Plan Director Unit Issuance Agreement (incorporated by reference to Exhibit 10.11 of the Form 10-Q filed on August 8, 2011). | |
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| Exhibit Number |
Exhibit Title | |
| 10.13.4**† | Form of CVR Partners, LP Long-Term Incentive Plan Employee Phantom Unit Agreement (incorporated by reference to Exhibit 10.1 of the Form 8-K filed on December 23, 2011). | |
| 10.14** | Trademark License Agreement, dated as of April 13, 2011, among CVR Energy, Inc. and CVR Partners, LP (incorporated by reference to Exhibit 10.9 to the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.15** | Credit and Guaranty Agreement, dated as of April 13, 2011, among Coffeyville Resources Nitrogen Fertilizers, LLC, CVR Partners, LP, the lenders party thereto and Goldman Sachs Lending Partners LLC, as administrative agent and collateral agent (incorporated by reference to Exhibit 10.8 of the Form 8-K/A filed by CVR Energy, Inc. on May 23, 2011). | |
| 10.16**† | Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and John J. Lipinski (incorporated by reference to Exhibit 10.16 of the Form S-1/A filed on January 28, 2011). | |
| 10.17**† | Second Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Edward Morgan (incorporated by reference to Exhibit 10.17 of the Form S-1/A filed on January 28, 2011). | |
| 10.17.1**† | Amendment to Second Amended and Restated Employment Agreement, dated November 29, 2011 by and between CVR Energy, Inc. and Edward Morgan (incorporated by reference to Exhibit 10.1 of the Form 8-K filed on December 2, 2011). | |
| 10.18**† | Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Stanley A. Riemann (incorporated by reference to Exhibit 10.18 of the Form S-1/A filed on January 28, 2011). | |
| 10.19**† | Third Amended and Restated Employment Agreement, dated as of January 1, 2011, by and between CVR Energy, Inc. and Kevan A. Vick (incorporated by reference to Exhibit 10.19 of the Form S-1/A filed on January 28, 2011). | |
| 10.20**† | Employment Agreement, dated as of August 22, 2011, by and between CVR GP, LLC and Randal T. Maffett (incorporated by reference to Exhibit 10.1 of the Form 10-Q filed on November 4, 2011). | |
| 10.21**† | Employment Agreement, dated as of June 1, 2011, by and between CVR GP, LLC and Byron R. Kelley (incorporated by reference to Exhibit 10.9 to the Form 10-Q filed on August 8, 2011). | |
| 10.22* | GP Services Agreement, dated as of November 29, 2011, among CVR Partners, LP, CVR GP, LLC and CVR Energy, Inc. | |
| 10.23* | Assignment and Assumption of Employment Agreement, dated as of January 1, 2012, by and between CVR Energy, Inc. and CVR GP, LLC. | |
| 10.24* | Amended and Restated Employment Agreement, dated as of January 1, 2012, by and between CVR GP, LLC and Kevan A. Vick. | |
| 10.25* | Consulting Agreement, dated January 31, 2012 by and between CVR GP, LLC, CVR Partners, LP, CVR Energy, Inc. and Kevan A. Vick. | |
| 10.26* | Form of Indemnification Agreement between CVR Partners, LP and each of its directors and officers. | |
| 21.1** | List of Subsidiaries of CVR Partners, LP (incorporated by reference to Exhibit 21.1 to the Form S-1 filed on December 20, 2010). | |
| 23.1* | Consent of KPMG LLP. | |
| 31.1* | Certification of the Executive Chairman pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. | |
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| Exhibit Number |
Exhibit Title | |
| 31.2* | Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. | |
| 31.3* | Certification of the Chief Financial Officer pursuant to Rule 13a-14(a) or 15(d)-14(a) under the Securities Exchange Act. | |
| 32.1* | Certification of the Executive Chairman pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 32.2* | Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 32.3* | Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | |
| 101++ | The following financial information for CVR Partners, LP’s Annual Report on Form 10-K for the year ended December 31, 2011, filed with the SEC on February 23, 2012, formatted in XBRL (“Extensible Business Reporting Language”) includes: (1) Consolidated Balance Sheets, (2) Consolidated Statements of Operations, (3) Consolidated Statements of Cash Flows, (4) Consolidated Statement of Partners’ Capital and (5) the Notes to Consolidated Financial Statements (unaudited), tagged as blocks of text.** | |
| * | Filed herewith. | |
| ** | Previously Filed | |
| † | Denotes management contract or compensatory plan or arrangement. | |
| ++ | Users of this data are advised pursuant to Rule 406T of Regulation S-T that this interactive data file is deemed not filed or part of a registration statement or prospectus for purposes of sections 11 or 12 of the Securities Act of 1933, is deemed not filed for purposes of section 18 of the Securities Exchange Act of 1934, and is otherwise not subject to liability under these sections. | |
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PLEASE NOTE: Pursuant to the rules and regulations of the Securities and Exchange Commission, we have filed or incorporated by reference the agreements referenced above as exhibits to this annual report on Form 10-K. The agreements have been filed to provide investors with information regarding their respective terms. The agreements are not intended to provide any other factual information about the Company or its business or operations. In particular, the assertions embodied in any representations, warranties and covenants contained in the agreements may be subject to qualifications with respect to knowledge and materiality different from those applicable to investors and may be qualified by information in confidential disclosure schedules not included with the exhibits. These disclosure schedules may contain information that modifies, qualifies and creates exceptions to the representations, warranties and covenants set forth in the agreements. Moreover, certain representations, warranties and covenants in the agreements may have been used for the purpose of allocating risk between the parties, rather than establishing matters as facts. In addition, information concerning the subject matter of the representations, warranties and covenants may have changed after the date of the respective agreement, which subsequent information may or may not be fully reflected in the Partnership’s public disclosures. Accordingly, investors should not rely on the representations, warranties and covenants in the agreements as characterizations of the actual state of facts about the Partnership or its business or operations on the date hereof.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
| CVR Partners, LP | ||
| By: |
CVR GP, LLC, its general partner | |
| By: |
/s/ BYRON R. KELLEY | |
| Chief Executive Officer | ||
Date: February 23, 2012
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report had been signed below by the following persons on behalf of the registrant and in the capacity and on the dates indicated.
| Signature |
Title |
Date | ||
| /S/ JOHN J. LIPINSKI |
Chairman of the Board of Directors, Executive Chairman |
February 23, 2012 | ||
| John J. Lipinski | ||||
| /S/ BYRON R. KELLEY Byron R. Kelley |
Chief Executive Officer, President and Director (Principal Executive Officer) |
February 23, 2012 | ||
| /S/ FRANK PICI Frank Pici |
Chief Financial Officer and Treasurer (Principal Financial and Accounting Officer) |
February 23, 2012 | ||
| /S/ STANLEY A. RIEMANN |
Director |
February 23, 2012 | ||
| Stanley A. Riemann | ||||
| /S/ DONNA R. ECTON |
Director |
February 23, 2012 | ||
| Donna R. Ecton | ||||
| /S/ FRANK M. MULLER, JR. |
Director |
February 23, 2012 | ||
| Frank M. Muller, Jr. | ||||
| /S/ MARK A. PYTOSH |
Director |
February 23, 2012 | ||
| Mark A. Pytosh | ||||
| /S/ JON R. WHITNEY |
Director |
February 23, 2012 | ||
| Jon R. Whitney | ||||
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