EX-99.3

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 prospectus. This discussion and analysis contains forward-looking statements that involve risks, uncertainties and assumptions. Our actual results may differ materially from those anticipated in these forward-looking statements as a result of a number of factors, including, but not limited to, those set forth under “Risk Factors”, “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this prospectus.

Overview

We are a growth-oriented Delaware limited partnership formed by CVR Energy to own and operate a nitrogen fertilizer facility and develop a diversified portfolio of assets that are complementary to our business and CVR Energy’s refining business. Our objective is to generate stable cash flows and, over time, to increase our quarterly cash distributions per unit. We intend to utilize the significant experience of CVR Energy’s management team to execute our growth strategy, including the acquisition from CVR Energy and third parties of additional infrastructure assets relating to fertilizer transportation and storage, petroleum storage, petroleum transportation and crude oil gathering. Upon the closing of this offering, CVR Energy will indirectly own approximately 87% of our outstanding units.

Our initial asset consists of a nitrogen fertilizer manufacturing facility, including (1) a 1,225 ton-per-day ammonia unit, (2) a 2,025 ton-per-day UAN unit and (3) an 84 million standard cubic foot per day gasifier complex, which consumes approximately 1,500 tons per day of pet coke to produce hydrogen. In 2007, we produced approximately 326,662 tons of ammonia, of which approximately 72% was upgraded into approximately 576,888 tons of UAN. At current natural gas and pet coke prices, we are the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. We generated net sales of $173.5 million, $170.0 million and $187.4 million, and operating income of $71.0 million, $43.0 million and $48.0 million, for the years ended December 31, 2005, 2006 and 2007, respectively.

Our nitrogen fertilizer plant in Coffeyville, Kansas includes a pet coke gasifier that produces high purity hydrogen which in turn is converted to ammonia at a related ammonia synthesis plant. Ammonia is further upgraded into UAN solution in a related UAN unit. Pet coke is a low value by-product of the refinery coking process. On average during the last four years, more than 75% of the pet coke consumed by the nitrogen fertilizer plant was produced by CVR Energy’s refinery. We obtain most of our pet coke via a long-term coke supply agreement with CVR Energy.

The nitrogen fertilizer plant is the only commercial facility in North America utilizing a pet coke gasification process to produce nitrogen fertilizers. Its redundant train gasifier provides good on-stream reliability and the use of low cost by-product pet coke feed (rather than natural gas) to produce hydrogen provides the facility with a significant competitive advantage due to currently high and volatile natural gas prices. Our competition utilizes natural gas to produce ammonia. Historically, pet coke has been a less expensive feedstock than natural gas on a per-ton of fertilizer produced basis.

The spare gasifier at the nitrogen fertilizer plant was expanded in 2006, increasing ammonia production by 6,500 tons per year. In addition, we are moving forward with an approximately $85 million fertilizer plant expansion, of which approximately $8 million was incurred as of December 31, 2007. We estimate this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium-priced UAN by approximately 50%. We currently expect to complete this expansion in late 2009 or early 2010. This project is also expected to improve our cost structure by eliminating the need for rail shipments of ammonia, thereby reducing the risks associated with such rail shipments and avoiding anticipated cost increases in such transport.

Factors Affecting Comparability

Our results over the past three years have been and our future results will be influenced by the following factors, which are fundamental to understanding comparisons of our period-to-period financial performance.

Acquisitions

On March 3, 2004, Coffeyville Resources completed the acquisition of one facility within Farmland’s eight-plant nitrogen fertilizer manufacturing and marketing division (together with the former Farmland petroleum division). As a result, financial information as of and for the periods prior to March 3, 2004 discussed below and included elsewhere in this prospectus was derived from the financial statements and reporting systems of Farmland.

A new basis of accounting was established on the date of the Initial Acquisition and, therefore, the financial position and operating results after March 3, 2004 are not consistent with the operating results before the Initial Acquisition date. However, management believes the most meaningful way to comment on the statement of operations data due to the short period from January 1, 2004 to March 2, 2004 is to compare the sum of the operating results for both periods in 2004 with the sum of the operating results for both periods in 2005. Management believes it is not practical to comment on the cash flows from operating activities in the same manner because the Initial Acquisition resulted in some comparisons not being meaningful. For instance, we did not acquire the accounts receivable or assume the accounts payable of Farmland. Farmland collected and made payments on these accounts after March 3, 2004, and these transactions are not included in our consolidated statements of cash flows.

On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, Coffeyville Acquisition LLC acquired all of the subsidiaries of Coffeyville Group Holdings, LLC, including what is now our business. As a result of certain adjustments made in connection with this acquisition, a new basis of accounting was established on the date of the acquisition and the results of operations for the 191 days ended December 31, 2005 are not comparable to prior periods.

Original Predecessor Corporate Allocations

Our financial statements prior to March 3, 2004 reflect an allocation of certain general corporate expenses of Farmland, including general and corporate insurance, property insurance, corporate retirement and benefits, human resource and payroll department salaries, facility costs, information services, and information systems support. For the year ended December 31, 2003 and for the 62-day period ended March 2, 2004, these costs allocated to our business were approximately $10.1 million and $3.2 million, respectively. Our financial statements prior to March 3, 2004 also reflect an allocation of interest expense from Farmland. These allocations were made by Farmland on a basis deemed meaningful for their internal management needs and may not be representative of the actual expense levels required to operate the businesses at that time or as they have been operated after March 3, 2004. Our insurance costs are greater now as compared to the period prior to March 3, 2004, as we have elected to obtain additional insurance coverage (such as business interruption insurance) that had not been carried by Farmland.

Successor Corporate Allocations

Our financial statements subsequent to June 23, 2005 reflect an allocation of certain general corporate expenses of Coffeyville Resources, LLC. CVR Energy allocated general and administrative expenses to us based on allocation methodologies that it considered reasonable and which result in an allocation of the cost of doing business borne by CVR Energy on behalf of us. However, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

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, mark-to-market changes in interest rate swap and losses on extinguishment of debt.

Selling, general and administrative expense allocations were based primarily on a percentage of total fertilizer payroll to the total fertilizer and petroleum segment payrolls. Property insurance costs were allocated based upon specific segment valuations. Interest expense, interest income, bank charges, gain(loss) on derivatives and loss on extinguishment of debt were allocated based upon fertilizer divisional equity as a percentage of total CVR Energy debt and equity. See Note 3 “Summary of Significant Accounting Policies — Allocation of Costs” in our historical financial statements included elsewhere in this prospectus.

Asset Impairments

In December 2002, Farmland implemented SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, resulting in a reorganization expense from the impairment of long-lived assets. Under SFAS No. 144, recoverability of assets to be held and used is measured by comparison of the carrying amount of an asset to the estimated undiscounted future net cash flows expected to be generated by the asset. It was determined that the carrying amount of the fertilizer assets exceeded its estimated future undiscounted net cash flow. An impairment charge of $230.8 million was recognized for the fertilizer assets, based on Farmland’s best assumptions regarding the use and eventual disposition of those assets, primarily from indications of value received from potential bidders through the bankruptcy sale process. In 2003, as a result of receiving a bid from Coffeyville Resources in the bankruptcy court’s sales process, Farmland revised its estimate for the amount to be generated from the disposition of these assets, and an additional impairment charge was taken. The charge to earnings in 2003 was $5.7 million for the fertilizer assets.

Original Predecessor Agreement with CHS, Inc.

For the period ending December 31, 2003 and the first 62 days of 2004, Farmland’s sales of nitrogen fertilizer products were subject to a marketing agreement with CHS, Inc. Under the agreement, CHS, Inc. was responsible for marketing substantially all of the nitrogen fertilizer products made by Farmland. Following the Initial Acquisition, we began marketing nitrogen fertilizer products directly to distributors and dealers. As a result, we have been able to generate higher average plant gate prices on sales of fertilizer products as a percentage of market average prices. For example, in 2004 we generated average plant gate prices as a percentage of market averages of 90.0% and 80.1% for ammonia and UAN, respectively, compared to average plant gate prices as a percentage of market averages of 86.6% and 75.9% for ammonia and UAN, respectively, in 2003. The term plant gate price refers to the unit price of fertilizer in dollars per ton, offered on a delivered basis, excluding shipment costs.

Publicly Traded Partnership Expenses

We expect that our general and administrative expenses will increase 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, registrar and transfer agent fees, incremental director and officer liability insurance costs and director compensation. We estimate that the increase in these costs will total approximately $2.5 million on an annual basis, excluding the costs associated with this offering and the costs of the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing. Our financial

statements following this offering will reflect the impact of these expenses, which will affect the comparability of our post-offering results with our financial statements from periods prior to the completion of this offering. Our unaudited pro forma financial statements, however, do not reflect this expense.

Changes in Legal Structure

Prior to March 3, 2004 our business was operated by Original Predecessor. Original Predecessor was not a separate legal entity, and its operating results were included within the operating results of Farmland and its subsidiaries in filing consolidated federal and state income tax returns. As a cooperative, Farmland was subject to income taxes on all income not distributed to patrons as qualified patronage refunds, and Farmland did not allocate income taxes to its divisions. As a result, results of operations during periods when we were operated by Original Predecessor do not reflect any provision for income taxes.

From March 3, 2004 to June 23, 2005, our business was operated by Immediate Predecessor and from June 23, 2005 through October 24, 2007 our business was operated by Successor. Both Immediate Predecessor and Successor were corporations, and our business operated as part of a larger company together with a petroleum refining business. Since October 24, 2007 our business has operated as a partnership, though still together with a petroleum refining business. Upon the completion of this offering, our business will continue to operate as a partnership, but for the first time will operate on a stand-alone basis as a nitrogen fertilizer business.

2007 Flood

During the weekend of June 30, 2007, torrential rains in southeastern Kansas caused the Verdigris River to overflow its banks and flood the city of Coffeyville. Our nitrogen fertilizer plant, which is located in close proximity to the Verdigris River, was flooded, sustained major damage and required repairs. As a result of the flooding, our nitrogen fertilizer facility stopped operating on June 30, 2007. Production at our nitrogen fertilizer facility was restarted on July 13, 2007. Total gross costs recorded as a result of the damage to our facility for the year ended December 31, 2007 were approximately $5.8 million. We recorded net costs associated with the flood of $2.4 million, which is net of $3.3 million of accounts receivable from insurers, and we believe collection of this amount is probable. We spent approximately $3.5 million to repair the nitrogen fertilizer facility in the year ended December 31, 2007. All further flood-related repairs will be paid for by CVR Energy pursuant to an indemnity agreement we will enter into prior to the completion of this offering. See “Business — Flood” and “Certain Relationships and Related Party Transactions — Agreements with CVR Energy — Indemnity and Transition Services Agreement”. We cannot predict how much of these amounts CVR Energy will be able to recover through insurance. See “Risk Factors — Risks Related to Our Business — Our facilities face operating hazards and interruptions. We could face potentially significant costs to the extent these hazards or interruptions are not fully covered by our existing insurance coverage. Insurance companies that currently insure companies in our industry may cease to do so or may substantially increase premiums in the future”.

Industry Factors

Our earnings depend largely on the prices of nitrogen fertilizer products, the floor price of which is directly influenced by natural gas prices. Natural gas prices have been and continue to be volatile.

Currently, the nitrogen fertilizer market is driven by an almost unprecedented increase in demand. According to the United States Department of Agriculture, U.S. farmers planted 92.9 million acres of corn in 2007, exceeding the 2006 planted area by 19 percent. This increase in acres planted in the U.S. was driven in large part by ethanol demand. In addition to the increase in U.S. nitrogen fertilizer demand, global demand has increased due to overall market growth in countries such as India, Latin America and Russia.

Total worldwide ammonia capacity has been growing. A large portion of the net growth has been in China and is attributable to China maintaining its self-sufficiency with regards to ammonia. Excluding China and the former Soviet Union, the trend in net ammonia capacity has been essentially flat since the late 1990s, as new plant construction has been offset by plant closures in countries with high-cost feedstocks. The high cost of capital is also limiting capacity increase. Today’s strong market growth appears to be readily absorbing the latest capacity additions.

Factors Affecting Results

Our earnings and cash flow from operations are primarily affected by the relationship between nitrogen fertilizer product prices and direct operating expenses. Unlike our competitors, we use minimal natural gas as feedstock and, as a result, are not directly impacted in terms of cost, by high or volatile swings in natural gas prices. Instead, CVR Energy’s adjacent oil refinery supplies us with most of the pet coke feedstock we need pursuant to a long-term coke supply agreement we entered into in October 2007. The price at which nitrogen fertilizer products are ultimately sold depends on numerous factors, including the supply of, and the demand for, nitrogen fertilizer products which, in turn, depends on, among other factors, the price of natural gas, the cost and availability of fertilizer transportation infrastructure, changes in the world population, weather conditions, grain production levels, the availability of imports, and the extent of government intervention in agriculture markets. While our net sales could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and nitrogen fertilizer products sell at the floor price, high natural gas prices do not force us to shut down our operations because we utilize pet coke as a feedstock to produce ammonia and UAN rather than natural gas.

Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. Natural gas costs and the price of nitrogen fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade of competitors’ facilities, price volatility, 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.

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. For further details on the economics of fertilizer, see “Industry Overview”.

Natural gas is the most significant raw material required in the production of most nitrogen fertilizers. North American natural gas prices have increased substantially and, since 1999, have become significantly more volatile. In 2005, North American natural gas prices reached unprecedented levels due to the impact hurricanes Katrina and Rita had on an already tight natural gas market. Recently, natural gas prices have moderated, returning to pre-hurricane levels or lower.

In order to assess the operating performance of our business, we calculate plant gate price to determine our operating margin. Plant gate price refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. Given the use of low cost pet coke, our business is not presently subjected to the high raw materials costs of competitors that use natural gas, the cost of which has been high in recent periods. Instead of experiencing high variability in the cost of raw materials, our business utilizes less than 1% of the natural gas relative to other natural gas-based fertilizer producers and we estimate that our business would continue to have a production cost advantage in comparison to U.S. Gulf Coast ammonia producers at natural gas prices as low as $2.50 per MMBtu. The spot price for natural gas at Henry Hub on December 31, 2007 was $7.48 per MMBtu.

Because the nitrogen fertilizer plant has certain logistical advantages relative to end users of ammonia and UAN and demand relative to production has remained high, we have primarily targeted end users in the U.S. farm belt where we incur lower freight costs than our competitors. The farm belt refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. We do not incur any intermediate storage, barge or pipeline freight charges when we sell in these markets, giving us a distribution cost advantage over U.S. Gulf Coast importers, assuming freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect. Selling products to customers within economic rail transportation limits of the nitrogen fertilizer plant and keeping transportation costs low are keys to maintaining profitability.

The value of nitrogen fertilizer products is also an important consideration in understanding our results. During 2007 we upgraded approximately 72% of our ammonia production into UAN, a product that presently generates a greater value than ammonia. UAN production is a major contributor to our profitability.

The direct operating expense structure of our business is also important to our profitability. Using a pet coke gasification process, we have significantly higher fixed costs than natural gas-based fertilizer plants. Major fixed operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These costs comprise the fixed costs associated with the nitrogen fertilizer plant. Variable costs associated with the nitrogen fertilizer plant have averaged approximately 1.2% of direct operating expenses over the last 24 months ended December 31, 2007. The average annual operating costs over the last 24 months ended December 31, 2007 have approximated $65 million, of which substantially all are fixed in nature.

Our largest raw material expense is pet coke, which we purchase from CVR Energy and third parties. In 2007, we spent $13.6 million for pet coke. If pet coke prices rise substantially in the future, we may be unable to increase our prices to recover increased raw material costs, because market prices for nitrogen fertilizer products are generally correlated with natural gas prices, the primary raw material used by our competitors, and not pet coke prices.

Consistent, safe, and reliable operations at our nitrogen fertilizer plant are critical to our financial performance and results of operations. Unplanned downtime of the nitrogen fertilizer plant may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. The financial impact of planned downtime, such as major turnaround maintenance, is mitigated through a diligent planning process that takes into account margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors.

We generally undergo a facility turnaround every two years. The turnaround typically lasts 15-20 days each turnaround year and costs approximately $2-3 million per turnaround. The next facility turnaround is currently scheduled for July 2008.

Agreements with CVR Energy

In connection with the initial public offering of CVR Energy and the transfer of the nitrogen fertilizer business to us in October 2007, we entered into a number of agreements with CVR Energy and its affiliates that govern the business relations between CVR Energy and us. These include the coke supply agreement mentioned above, 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.

The price we pay pursuant to the coke supply agreement is based on the lesser of a coke price derived from the price received by us for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet coke. Historically, the cost of product sold (exclusive of depreciation and amortization) in the nitrogen fertilizer business on our financial statements was based on a coke price of $15 per ton beginning in March 2004. If the terms of the coke supply agreement had been in place over the past three years, our cost of product sold (exclusive of depreciation and amortization) would have decreased $1.6 million, decreased $0.7 million, decreased $3.5 million and increased $2.5 million for the 174 day period ended June 24, 2005, the 191 day period ended December 31, 2005, and the years ended December 31, 2006 and 2007, respectively.

In addition, based on management’s current estimates, the services agreement will result in an annual charge of approximately $11.5 million (excluding share-based compensation) in selling, general and administrative expenses (exclusive of depreciation and amortization) in our statement of operations. Had the services agreement been in effect over the past three years, our operating income would have decreased by $0.4 million, $1.6 million, $1.8 million and $0.8 million for the 174-day period ended June 23, 2005, the 191-day period ended December 31, 2005, and the years ended December 31, 2006 and 2007, respectively.

The total change to our operating income as a result of both the 20-year coke supply agreement (which affects our cost of product sold (exclusive of depreciation and amortization)) and the services agreement (which affects our selling, general and administrative expense (exclusive of depreciation and amortization)), if both agreements had been in effect over the last three years, would be an increase of $1.2 million, a decrease of $0.9 million, an increase of $1.7 million and a decrease of $3.3 million for the 174-day period ended June 23, 2005, the 191-day period ended December 31, 2005, and the years ended December 31, 2006 and 2007, respectively.

The feedstock and shared services agreement, the raw water and facilities sharing agreement, the cross-easement agreement and the environmental agreement are not expected to have a significant impact on the financial results of our business. However, the feedstock and shared services agreement includes provisions which require us to provide hydrogen to CVR Energy on a going-forward basis, as we have done in recent years. This will have the effect of reducing our fertilizer production, because we will not be able to convert this hydrogen into ammonia. We believe that the addition of CVR Energy’s new catalytic reformer will reduce, to some extent, but not eliminate, the amount of hydrogen we will need to deliver to CVR Energy, and we expect to continue to deliver hydrogen to CVR Energy. The feedstock and shared services agreement requires CVR Energy to compensate us for the value of production lost due to the hydrogen supply requirement. See “Certain Relationships and Related Party Transactions — Agreements with CVR Energy”.

Net receivables due from CVR Energy were $2,142,301 as of December 31, 2007.

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. Effective June 24, 2005, Successor acquired the net assets of Immediate Predecessor in a business combination accounted for as a purchase. As a result of this acquisition, the audited consolidated financial statements for the periods after the acquisition are presented on a different cost basis than that for the periods before the acquisition and, therefore, are not comparable. Accordingly, in this “— Results of Operations” section, after comparing the year ended December 31, 2007 with the year ended December 31, 2006, we compare the year ended December 31, 2006 with the 174-day period ended June 23, 2005 and the 191-day period ended December 31, 2005.

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. For the years ended December 31, 2004 and 2005 we have provided this supplemental information on a combined basis in order to provide a comparative basis for similar

periods of time. As discussed above, due to the various acquisitions that occurred, there were multiple financial statement periods of less than twelve months. We believe that the most meaningful way to present this supplemental data for the various periods is to compare the sum of the combined operating results for the 2004 and 2005 calendar years with prior fiscal years, and to compare the sum of the combined operating results for the year ended December 31, 2005 with the years ended December 31, 2006 and 2007.

Accordingly, for purposes of displaying supplemental operating data for the year ended December 31, 2005, we have combined the 174-day period ended June 23, 2005 and the 191-day period ended December 31, 2005 in order to provide a comparative year ended December 31, 2005 to the year ended December 31, 2006. Additionally, the 62-day period ended March 2, 2004 and the 304-day period ended December 31, 2004 have been combined in order to provide a comparative twelve-month period ended December 31, 2004 to a combined twelve-month period ended December 31, 2005 comprised of the 174-day period ended June 23, 2005 and the 191-day period ended December 31, 2005.

The tables below provide an overview of our results of operations, relevant market indicators and our key operating statistics during the past five fiscal years:


	Original Predecessor				Immediate Predecessor				Successor
			62 Days		304 Days		174 Days		191 Days		Year		Year
	Year Ended		Ended		Ended		Ended		Ended		Ended		Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,		December 31,
Business Financial Results	2003		2004		2004		2005		2005		2006		2007
	(unaudited)		(unaudited)		(unaudited)
	(in millions)
Net sales	$	100.9	$	19.4	$	91.4	$	76.7	$	96.8	$	170.0	$	187.4
Cost of product sold (exclusive of depreciation and amortization)		21.9		4.1		18.8		9.8		19.2		33.4		33.1
Direct operating expenses (exclusive of depreciation and amortization)(1)		53.0		8.4		44.3		26.0		29.1		63.6		66.7
Selling, general and administrative expenses (exclusive of depreciation and amortization)(1)		10.1		3.2		5.0		5.1		4.6		12.9		20.4
Net costs associated with flood(2)		—		—		—		—		—		—		2.4
Depreciation and amortization(3)		1.2		0.2		0.9		0.3		8.4		17.1		16.8
Impairment and other charges(4)		6.9		—		—		—		—		—		—

Operating income	$	7.8	$	3.5	$	22.4	$	35.5	$	35.5	$	43.0	$	48.0
Net income(5)		7.3		3.5		20.8		32.7		26.0		14.7		24.1


(1)		Our direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization) for the 191 days ended December 31, 2005, the year ended December 31, 2006 and the year ended December 31, 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 SFAS 123(R). 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 were:


	191 Days ended		Year Ended		Year Ended
	December 31,		December 31,		December 31,
	2005		2006		2007
	(in millions)

Direct operating expenses (exclusive of depreciation and amortization)	$	0.1	$	0.8	$	1.2
Selling, general and administrative expenses (exclusive of depreciation and amortization)		0.2		3.2		9.7

Total	$	0.3	$	4.0	$	10.9


(2)		Total gross costs recorded as a result of the damage to the 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.

(3)		Depreciation and amortization is comprised of the following components as excluded from direct operating expense and selling, general and administrative expense and as included in net costs associated with flood:


	Original Predecessor				Immediate Predecessor				Successor
	Year		62 Days		304 Days		174 Days		191 Days		Year		Year
	Ended		Ended		Ended		Ended		Ended		Ended		Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,		December 31,
	2003		2004		2004		2005		2005		2006		2007
	(unaudited)		(unaudited)		(unaudited)
	(in millions)
Depreciation and amortization excluded from direct operating
expenses	$	1.2	$	0.1	$	0.9	$	0.3	$	8.3	$	17.1	$	16.8
Depreciation and amortization excluded from selling, general and administrative expenses		—		0.1		—		—		0.1		—		—
Depreciation included in net costs associated with flood		—		—		—		—		—		—		0.8

Total depreciation and amortization	$	1.2	$	0.2	$	0.9	$	0.3	$	8.4	$	17.1	$	17.6


(4)		During the year ended December 31, 2003, we recorded a charge of $5.7 million related to the asset impairment of the nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.2 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code.

100


(5)		The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature:


	Original Predecessor				Immediate Predecessor				Successor
			62 Days		304 Days		174 Days		191 Days		Year		Year
	Year Ended		Ended		Ended		Ended		Ended		Ended		Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,		December 31,
	2003		2004		2004		2005		2005		2006		2007
	(unaudited)		(unaudited)		(unaudited)
	(in millions)
Impairment of property, plant and equipment(a)	$	5.7	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0
Loss on extinguishment of debt(b)		—		—		0.7		1.2		—		8.5		0.2
Inventory fair market value adjustment		—		—		—		—		0.7		—		—
Interest rate swap		—		—		—		—		0.1		(1.8)		(1.4)
Share-based compensation expense(c)		—		—		—		—		0.3		4.0		10.9


(a)		During the year ended December 31, 2003, we recorded a charge of $5.7 million related to the asset impairment of our nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition.

(b)		Represents our portion of (1) the write-off of deferred financing costs in connection with the refinancing of the senior secured credit facility of Coffeyville Resources, LLC on June 23, 2005, (2) the write-off in connection with the refinancing of the senior secured credit facility of Coffeyville Resources, LLC on December 28, 2006, and (3) the write-off in connection with the repayment and termination of three of the credit facilities of Coffeyville Resources, LLC and Coffeyville Refining & Marketing Holding, Inc., an indirect parent company of Coffeyville Resources, LLC and a subsidiary of CVR Energy, Inc., on October 26, 2007.

(c)		Our direct operating expenses (exclusive of depreciation and amortization) and selling, general and administrative expenses (exclusive of depreciation and amortization) 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 SFAS 123(R). See Note 1 above. We are not responsible for the payment of cash related to any share-based compensation expense allocated to us by CVR Energy.

The following tables show selected information about key market indicators and certain operating statistics for our business, respectively:


	Annual Average for
	Year Ended December 31,
Market Indicators	2003		2004		2005		2006		2007

Natural gas (dollars per MMBtu)	$	5.49	$	6.18	$	9.01	$	6.98	$	7.12
Ammonia — Southern Plains (dollars per ton)		274		297		356		353		409
UAN — Corn Belt (dollars per ton)		143		171		212		197		288

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				Original
				Predecessor			Immediate
				and			Predecessor
				Immediate			and
	Original			Predecessor			Successor
	Predecessor			Combined			Combined			Successor
	Year Ended December 31,
Company Operating Statistics	2003			2004			2005			2006			2007

Production (thousand tons):
Ammonia		335.7			309.2			413.2			369.3			326.7
UAN		510.6			532.6			663.3			633.1			576.9

Total		846.3			841.8			1,076.5			1,002.4			903.6
Sales (thousand tons):
Ammonia		134.8			103.2			141.4			117.7			92.8
UAN		528.9			528.8			639.1			644.6			576.4

Total		663.7			632.0			780.5			762.3			669.2
Product price (plant gate) (dollars per ton)(1):
Ammonia	$	235		$	265		$	323		$	339		$	376
UAN		107			136			173		$	164		$	209
On-stream factor(2):
Gasifier		90.1	%		92.4	%		98.1	%		92.5	%		90.0	%
Ammonia		89.6	%		79.9	%		96.7	%		89.3	%		87.7	%
UAN		81.6	%		83.3	%		94.3	%		88.9	%		78.7	%
Reconciliation to net sales (dollars in thousands):
Freight in revenue	$	12,535		$	11,161		$	14,780		$	17,876		$	14,338
Hydrogen Revenue		—			318			2,721			6,820			17,812
Sales net plant gate		88,373			99,388			156,011			145,334			155,299

Total net sales	$	100,908		$	110,867		$	173,512		$	170,030		$	187,449


(1)		Plant gate price per ton represents net sales less freight 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.

(2)		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 turnarounds at the nitrogen fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors in 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN, and (ii) the on-stream factors in 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN.

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006.

Net Sales. Net sales were $187.4 million for the year ended December 31, 2007 compared to $170.0 million for the year ended December 31, 2006. The increase of $17.4 million was the result of higher plant gate prices ($33.0 million), partially offset by reductions in overall sales volumes ($15.6 million).

Net sales for the year ended December 31, 2007 included $133.0 million from the sale of UAN, $36.6 million from the sale of ammonia and $17.8 million from the sale of hydrogen to CVR Energy. Net sales for the year ended December 31, 2006 included $121.1 million from the sale of UAN, $42.1 million from the sale of ammonia and $6.8 million from the sale of hydrogen to CVR Energy. The increase in hydrogen sales of $11.0 million was the result of the flood during the weekend of June 30, 2007 and the turnaround at CVR Energy’s refinery, both of which idled CVR Energy’s refinery and therefore reduced its ability to manufacture its own hydrogen.

In regard to product sales volumes for the year ended December 31, 2007, our nitrogen operations experienced a decrease of 21% in ammonia sales unit volumes (24,972 tons) and a decrease of 11% in UAN sales unit volumes (68,222 tons). The decrease in ammonia sales volume was the result of decreased production volumes during the year ended December 31, 2007 relative to the comparable period of 2006 due to unscheduled downtime at our nitrogen fertilizer plant and the transfer of hydrogen to CVR Energy’s petroleum operations to facilitate sulfur recovery in its ultra low sulfur diesel production unit. We believe that the transfer of hydrogen to CVR Energy’s petroleum

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operations will decrease, to some extent, during most of 2008 because CVR Energy’s new continuous catalytic reformer will produce hydrogen for CVR Energy.

On-stream factors (total number of hours operated divided by total hours in the reporting period) for all units of our nitrogen operations (gasifier, ammonia unit and UAN unit) during 2007 were less than the comparable period of 2006 primarily due to approximately 18 days of downtime for all three primary nitrogen units associated with the flood, nine days of downtime related to compressor repairs in the ammonia unit and 24 days of downtime related to the UAN expansion in the UAN unit. In addition, all three primary units also experienced brief and unscheduled downtime for repairs and maintenance during the year ended December 31, 2007. It is typical to experience brief outages in complex manufacturing operations such as our 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 FOB the delivery point less any freight cost we absorb to deliver the product. We believe plant gate price is meaningful because we sell products both FOB our plant gate (sold plant) and FOB 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. Average plant gate prices during the year ended December 31, 2007 for ammonia and UAN were greater than average plant gate prices during the comparable period of 2006 by 11% and 27%, respectively. Our ammonia and UAN sales prices for product shipped during the year ended December 31, 2006 generally followed volatile natural gas prices; however, it is typical for the reported pricing in our business to lag the spot market prices for nitrogen fertilizer due to forward price contracts. As a result, forward price contracts entered into during the late summer and fall of 2005 (during a period of relatively high natural gas prices due to the impact of hurricanes Rita and Katrina) comprised a significant portion of the product shipped in the spring of 2006. However, as natural gas prices moderated in the spring and summer of 2006, nitrogen fertilizer prices declined and the spot and fill contracts entered into and shipped during this lower natural gas prices environment realized a lower average plant gate price. Ammonia and UAN sales prices for the year ended December 31, 2007 were negatively impacted by relatively low natural gas prices compared to 2005 and 2006, but this decrease was more than offset by a sharp increase in nitrogen fertilizer prices driven by increased demand for nitrogen fertilizer due to the increased use of corn for the production of ethanol and an overall increase in prices for corn, wheat and soybeans, the primary row crops in our region. This increase in demand for nitrogen fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation to natural gas. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Industry Factors”.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold is primarily comprised of expenses related to pet coke purchases, freight and distribution expenses and railcar expense. Freight and distribution expenses consist of our outbound freight cost, which we pass through to our customers. Railcar expense is our actual expense to acquire, maintain and lease railcars. Cost of product sold for the year ended December 31, 2007 was $33.1 million compared to $33.4 million for the year ended December 31, 2006. The decrease of $0.3 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of reduced freight expense and lower overall sales volumes in 2007 partially offset by increased pet coke costs. In 2007, pet coke costs increased as we purchased more pet coke from third parties than is typical as a result of the flood which curtailed CVR Energy’s pet coke production.

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associated with repairs and maintenance ($6.5 million), equipment rental ($0.6 million), environmental ($0.4 million), utilities ($0.3 million) and insurance ($0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with turnaround ($2.6 million), royalties and other ($1.7 million), catalyst ($0.4 million) and chemicals ($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 corporate allocations from CVR Energy. These selling, general and administrative allocations from CVR Energy are based on different methodologies depending on the particular expense. With the contribution of our business to the Partnership in October 2007, certain expenses of the Partnership are subject to the management services agreement with CVR Energy and its affiliates. Selling, general and administrative expenses exclusive of depreciation and amortization were $20.4 million for the year ended December 31, 2007 as compared to $12.9 million for the year ended December 31, 2006. This variance was primarily the result of increases in expenses associated with non-cash share-based compensation allocated to us by CVR Energy in accordance with SFAS 123(R) for financial reporting purposes ($7.5 million), the management services agreement and corporate allocations from CVR Energy ($0.9 million) and outside services ($0.5 million). These increases in selling, general and administrative expenses were partially offset by the retirement of fixed assets as a result of the spare gasifier project ($1.0 million) in 2006.

Net Costs Associated with Flood. Net costs associated with flood for the year ended December 31, 2007 were approximately $2.4 million. There was no comparable expense for the year ended December 31, 2006. Total gross costs recorded as a result of the damage to the nitrogen fertilizer plant for the year ended December 31, 2007 were approximately $5.8 million. Included in this cost was approximately $0.8 million recorded for depreciation for temporarily idle facilities, $0.7 million for internal salaries and $4.3 million for other repair and related costs. Total accounts receivable from insurers relating to the nitrogen fertilizer plant approximated $3.3 million at December 31, 2007, and we believe collection of this amount is probable.

Depreciation and Amortization. Depreciation and amortization decreased to $16.8 million for the year ended December 31, 2007 as compared to $17.1 million for the year ended December 31, 2006. During the restoration period for the nitrogen fertilizer operations due to the flood, $0.8 million of depreciation and amortization was reclassified into net costs associated with flood. Adjusting for this $0.8 million reclassification, depreciation and amortization would have increased by approximately $0.5 million.

Operating Income. Operating income was $48.0 million for the year ended December 31, 2007 as compared to $43.0 million for the year ended December 31, 2006. This increase of $5.0 million was primarily the result of higher plant gate prices ($33.0 million), partially offset by reductions in overall sales volumes ($15.6 million). Partially offsetting the higher plant gate prices for UAN and ammonia was an increase of $3.1 million in direct operating expenses, which was primarily the result of increases in expenses associated with repairs and maintenance ($6.5 million), equipment rental ($0.6 million), environmental ($0.4 million), utilities ($0.3 million) and insurance ($0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with turnaround ($2.6 million), royalties and other expenses ($1.7 million), catalyst ($0.4 million) and chemicals ($0.3 million). Further offsetting the higher plant gate prices was a $7.7 million increase in selling, general and administrative expenses over the comparable periods primarily the result of increases in expenses associated with deferred compensation ($7.5 million), the management services agreement and corporate allocations from CVR Energy ($0.9 million) and outside services ($0.5 million). These increases in selling, general and administrative expenses were partially offset by the retirement of fixed assets as a result of the spare gasifier project ($1.0 million) in 2006.

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Interest Expense and Other Financing Costs. Interest expense and other financing costs for the year ended December 31, 2006 and the year-to-date period ending October 24, 2007 is the result of an allocation based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy. After October 24, 2007, interest expense and other financing costs was based upon the outstanding inter-company balance between us and CVR Energy. Interest expense for the year ended December 31, 2007 was $23.6 million as compared to interest expense of $23.5 million for the year ended December 31, 2006. The comparability of interest expense and other financing costs during these periods has been impacted by the differing capital structures of Successor during these periods, the interest expense allocation method utilized prior to October 24, 2007 and the interest expense calculation after October 24, 2007. See “— Factors Affecting Comparability”.

Interest Income. Interest income for the year ended December 31, 2006 and the year-to-date period ending October 24, 2007 is the result of an allocation based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy. After October 24, 2007, interest income was based upon the outstanding balance of an inter-company note between our business and CVR Energy and actual interest income on cash balances in our business’s bank account. Interest income was $0.3 million for the year ended December 31, 2007 as compared to $1.4 million for the year ended December 31, 2006. The comparability of interest income during these periods has been impacted by the differing capital structures of CVR Energy, the interest income allocation method utilized prior to October 24, 2007 and the interest income calculation after October 24, 2007. See “— Factors Affecting Comparability”.

Gain (Loss) on Derivatives. Gain (loss) on derivatives is the result of an allocation based on our business’s percentage of divisional equity relative to the debt and equity of CVR Energy. Furthermore, the gain (loss) on derivatives is exclusively related to the interest rate swap entered into by CVR Energy in July 2005. Gain (loss) on derivatives was a loss of $0.5 million for the year ended December 31, 2007 as compared to a gain of $2.1 million for the year ended December 31, 2006. The comparability of gain (loss) on derivatives during these periods has been impacted by the differing capital structures of CVR Energy during these periods and the aforementioned gain (loss) on derivative allocation method. See “— Factors Affecting Comparability”.

Loss on Extinguishment of Debt. Loss on extinguishment of debt is the result of an allocation of such expense to us based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy. In August 2007, as a result of the flood, Coffeyville Resources entered into a new $25.0 million senior secured term loan and a new $25.0 million senior unsecured term loan. Concurrently, Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan. With the completion of CVR Energy’s initial public offering in October 2007, these three facilities were repaid and terminated. As a result of this termination and the related extinguishment of debt allocation, we recognized $0.2 million as a loss on extinguishment of debt in 2007.

On December 28, 2006, Coffeyville Acquisition LLC refinanced its existing first lien credit facility and second lien credit facility and raised $1.075 billion in long-term debt commitments under a new credit facility. See “— Liquidity and Capital Resources — Debt”. As a result of the retirement of the first and second lien credit facilities with the proceeds of the new credit facility and the related extinguishment of debt allocation, we recognized $8.5 million as a loss on extinguishment of debt in 2006. On June 24, 2005 and in connection with the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC, Coffeyville Resources raised $800.0 million in long-term debt commitments under both the first lien credit facility and second lien credit facility. See “— Factors Affecting Comparability” and “— Liquidity and Capital Resources — Debt”.

Other Income (Expense). For the year ended December 31, 2007, other income was $0.1 million as compared to other expense of $0.2 million for the year ended December 31, 2006.

Income Tax Expense. Income tax expense for the years ended December 31, 2007 and December 31, 2006 was immaterial and was primarily comprised of a Texas state franchise tax.

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Net Income. Net income for the year ended December 31, 2007 was $24.1 million as compared to net income of $14.7 million for the year ended December 31, 2006. Net income increased $9.4 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 primarily due to strong plant gate prices for UAN and ammonia, more than offsetting reductions in overall sales volumes and increases in direct operating expenses (exclusive of depreciation and amortization), selling, general and administrative expenses (exclusive of depreciation and amortization) and net costs associated with flood.

Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 191 Days Ended December 31, 2005.

Net Sales. Net sales were $170.0 million for the year ended December 31, 2006 compared to $76.7 million for the 174 days ended June 23, 2005 and $96.8 million for the 191 days ended December 31, 2005. The decrease of $3.5 million from the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was the result of both decreases in selling prices ($1.3 million) and reductions in overall sales volumes ($2.2 million) as compared to the year ended December 31, 2005.

Net sales for the year ended December 31, 2006 included $121.1 million from the sale of UAN, $42.1 million from the sale of ammonia and $6.8 million from the sale of hydrogen to CVR Energy. Net sales for the year ended December 31, 2005 included $122.2 million from the sale of UAN, $48.6 million from the sale of ammonia and $2.7 million from the sale of hydrogen to CVR Energy.

In regard to product sales volumes for the year ended December 31, 2006, we experienced a decrease of 17% in ammonia sales unit volumes (23,647 tons) and an increase of 0.9% in UAN sales unit volumes (5,510 tons). The decrease in ammonia sales volume was the result of decreased production volumes during the year ended December 31, 2006 relative to the comparable period of 2005 due to the scheduled turnaround at the nitrogen fertilizer plant during July 2006 and the transfer of hydrogen to CVR Energy’s petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit. We believe that the transfer of hydrogen to CVR Energy’s petroleum operations will decrease, to some extent, during 2008 because CVR Energy’s new continuous catalytic reformer will produce hydrogen for CVR Energy.

On-stream factors (total number of hours operated divided by total hours in the reporting period) for all units of our operations (gasifier, ammonia unit and UAN unit) were less in 2006 than in 2005 primarily due to the scheduled turnaround in July 2006 and downtime in the ammonia unit due to a crack in the converter. It is typical to experience brief outages in complex manufacturing operations such as our nitrogen fertilizer plant which result in less than 100% on-stream availability for one or more specific units.

Plant gate prices are prices FOB the delivery point less any freight cost absorbed to deliver the product. We believe plant gate price is meaningful because the nitrogen fertilizer business sells products both FOB the nitrogen fertilizer plant gate (sold plant) and FOB the customer’s designated delivery site (sold delivered). In addition, 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. Average plant gate prices during the year ended December 31, 2006 for ammonia were greater than average plant gate prices during the comparable period of 2005 by 5%. In contrast to ammonia, UAN prices decreased for the year ended December 31, 2006 as compared to the year ended December 31, 2005 by 5%. The positive price comparisons for ammonia sales, given the dramatic decline in natural gas prices during the comparable periods, were the result of prepay contracts executed during the period of relatively high natural gas prices that resulted from the impact of hurricanes Katrina and Rita on an already tight natural gas market.

Cost of Product Sold (Exclusive of Depreciation and Amortization). Cost of product sold is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold for the year ended December 31, 2006 was $33.4 million compared to $9.8 million for the 174 days

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ended June 23, 2005 and $19.2 million for the 191 days ended December 31, 2005. The increase of $4.4 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of increases in freight expense.

Direct Operating Expenses (Exclusive of Depreciation and Amortization). Direct operating expenses include costs associated with the actual operations of our nitrogen fertilizer plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Direct operating expenses exclusive of depreciation and amortization for the year ended December 31, 2006 were $63.6 million as compared to $26.0 million for the 174 days ended June 23, 2005 and $29.1 million for the 191 days ended December 31, 2005. The increase of $8.5 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of increases in turnaround expenses ($2.6 million), utilities ($2.6 million), repairs and maintenance ($1.3 million), labor ($0.9 million), outside services ($0.8 million), insurance ($0.6 million), and chemicals ($0.3 million), partially offset by reductions in expenses related to environmental ($0.5 million) and catalyst and refractory brick ($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 corporate allocations from CVR Energy or Immediate Predecessor. These selling, general and administrative allocations from CVR Energy or Immediate Predecessor are based on different methodologies depending on the particular expense. Selling, general and administrative expenses were $12.9 million for the year ended December 31, 2006 as compared to $5.1 million for the 174 days ended June 23, 2005 and $4.6 million for the 191 days ended December 31, 2005. For the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005, selling, general and administrative expense increased approximately $3.2 million. This variance was primarily the result of increases in expenses associated with corporate allocations ($2.1 million) and the retirement of fixed assets as a result of the spare gasifier expansion project ($1.0 million).

Depreciation and Amortization. Depreciation and amortization increased to $17.1 million for the year ended December 31, 2006 as compared to $0.3 million for the 174 days ended June 23, 2005 and $8.4 million for the 191 days ended December 31, 2005. This increase of $8.4 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of the step-up in property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability”.

Operating Income. Our operating income was $43.0 million for the year ended December 31, 2006 as compared to $35.5 million for the 174 days ended June 23, 2005 and $35.5 million for the 191 days ended December 31, 2005. This decrease of $28.0 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was the result of reduced sales volumes, lower plant gate prices for UAN and increased direct operating expenses as described above.

Interest Expense and Other Financing Costs. Interest expense and other financing costs is the result of an allocation based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy or the Immediate Predecessor. We reported interest expense and other financing costs for the year ended December 31, 2006 of $23.5 million as compared to interest expense and other financing costs of $0.8 million for the 174 days ended June 23, 2005 and $14.8 million for the 191 days ended December 31, 2005. The comparability of interest expense and other financing costs during the comparable periods has been impacted by the differing capital structures of CVR Energy and Immediate Predecessor periods and the interest expense allocation method mentioned above. See “— Factors Affecting Comparability”.

Interest Income. Interest income is the result of an allocation based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy or the Immediate

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Predecessor. Interest income was $1.4 million for the year ended December 31, 2006 as compared to $0.0 million for the 174 days ended June 23, 2005 and $0.5 million for the 191 days ended December 31, 2005. The comparability of interest income during the comparable periods has been impacted by the differing capital structures of CVR Energy and Immediate Predecessor periods and the interest income allocation method mentioned above. See “— Factors Affecting Comparability”.

Gain (Loss) on Derivatives. Gain (loss) on derivatives is the result of an allocation based on our business’s percentage of divisional equity relative to the debt and equity of CVR Energy or the Immediate Predecessor. Furthermore, the gain (loss) on derivatives is exclusively related to the interest rate swap entered into by the Immediate Successor in July 2005. Gain (loss) on derivatives was $2.1 million for the year ended December 31, 2006 as compared to $4.9 million for the 191 days ended December 31, 2005. The comparability of gain (loss) on derivatives during the comparable periods has been impacted by the differing capital structures of CVR Energy and Immediate Predecessor during these periods and the (loss) on derivative allocation method mentioned above. See “— Factors Affecting Comparability”.

Loss on Extinguishment of Debt. Extinguishment of debt is the result of an allocation based upon our business’s percentage of divisional equity relative to the debt and equity of CVR Energy or the Immediate Predecessor. On December 28, 2006, Coffeyville Resources refinanced its existing first lien credit facility and second lien credit facility and raised $1.075 billion in long-term debt commitments under a new revolving secured credit facility. See “— Liquidity and Capital Resources — Debt”. As a result of the retirement of the first and second lien credit facilities with the proceeds of the new revolving secured credit facility and the extinguishment of debt allocation method mentioned above, we recognized $8.5 million as a loss on extinguishment of debt in 2006.

On June 24, 2005 and in connection with the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC, Coffeyville Resources raised $800.0 million in long-term debt commitments under both the first lien credit facility and second lien credit facility. See “— Factors Affecting Comparability” and “— Liquidity and Capital Resources — Debt”. As a result of the retirement of Immediate Predecessor’s outstanding indebtedness consisting of $150.0 million term loan and revolving credit facilities and the extinguishment of debt allocation method mentioned above, we recognized $1.2 million as a loss on extinguishment of debt in 2005. See “— Factors Affecting Comparability”.

Other Income (Expense). For the year ended December 31, 2006, other income was $0.2 million as compared to other expense of $0.8 million for the 174 days ended June 23, 2005 and no other income (expense) for the 191 days ended December 31, 2005.

Income Tax Expense. Income tax expense for the year ended December 31, 2006, the 174 days ended June 23, 2005 and the 191 days ended December 31, 2005 was immaterial and was primarily comprised of Texas state franchise taxes.

Net Income. For the year ended December 31, 2006, net income decreased to $14.7 million as compared to net income of $32.7 million for the 174 days ended June 23, 2005 and net income of $26.0 million for the 191 days ended December 31, 2005. Net income decreased $44.0 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 primarily due to decreased sales prices, reductions in sales volumes and increases in expenses associated with cost of product sold (exclusive of depreciation and amortization), direct operating expenses (exclusive of depreciation and ammortization), selling, general and administrative expenses (exclusive of depreciation and ammortization), depreciation and ammortization, interest expense and other financing costs, gain (loss) on derivatives and loss on extinguishment of debt.

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

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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 prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.

Impairment of Long-Lived Assets

We review our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable, in accordance with the provisions of SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets. Recoverability of an asset to be held and used is measured by a comparison of the carrying amount of an asset to future undiscounted net cash flows expected to be generated by the asset. If such asset is considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeded the fair value of the asset. Assets to be disposed of would be separately reported at the lower of the carrying value or fair value less cost to sell the asset.

As of December 31, 2007, net property, plant and equipment totaled approximately $352.0 million. To the extent events or circumstances change indicating the carrying amounts of our assets may not be recoverable, we could experience asset impairments in the future.

Impairment of Goodwill

We account for goodwill in accordance with the provisions of SFAS 142, Goodwill and Other Intangible Assets, which requires goodwill and intangible assets with indefinite useful lives not be amortized, but be tested for impairment annually or whenever indicators or impairments arise. Intangible assets that have finite lives continue to be amortized over their estimated useful lives. To the extent events or circumstances change indicating the carrying amount of our goodwill may not be recoverable, we could recognize a material impairment charge in the future. As of December 31, 2007, goodwill totaled approximately $41.0 million.

Allocation of Costs

Our consolidated financial statements have been prepared in accordance with Staff Accounting Bulletin, or SAB, Topic 1-B. These rules require allocations of costs for salaries and benefits, depreciation, rent, accounting, and legal services, and other general and administrative, or G&A, expenses. CVR Energy has allocated G&A expenses to us, and based on management’s estimation, we believe the allocation methodologies used are reasonable and result in a fair allocation of the cost of doing business borne by CVR Energy and Coffeyville Resources LLC on behalf of our business; however, these allocations may not be indicative of the cost of future operations or the amount of future allocations.

Our historical income statements reflect all of the direct expenses that the parent incurred on our behalf. Our financial statements therefore include certain expenses incurred by our parent which include, but are not necessarily limited to, the following:


	•	Officer and employee salaries and equity compensation;

	•	Rent or depreciation;

	•	Advertising;

	•	Accounting, tax and legal and information technology services;

	•	Other selling, general and administrative expenses;

	•	Costs for defined contributions plans, medical, and other employee benefits; and

	•	Financing costs, including interest, mark-to-market changes in interest rate swap, and losses on extinguishment of debt.

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If shared costs rise or the method by which we allocate shared costs changes, additional G&A expenses could be allocated to us, which could be material.

Share-Based Compensation

We have been allocated non-cash share-based compensation expense from CVR Energy. CVR Energy accounts for share-based compensation in accordance with SFAS No. 123(R), Share-Based Payments, and in accordance with EITF Issue No. 00-12, “Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee”. In accordance with SFAS 123(R), CVR Energy applies a fair-value based measurement in accounting for share-based compensation. Costs are allocated based upon the percentage of time a CVR Energy employee provides services to us. 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. Expense allocated subsequent to October 24, 2007 is treated as a contribution to capital.

There is considerable judgment in the determination of the significant assumptions used in determining the fair value of the share-based compensation allocated to us from CVR Energy and Coffeyville Acquisition III. Changes in the assumptions used to determine the fair value of compensation expense associated with the override units of Coffeyville Acquisition III could result in material changes in the amounts allocated to us from Coffeyville Acquisition III. Amounts allocated to us from CVR Energy in the future will depend and be based upon the market value of CVR Energy’s common stock.

Purchase Price Accounting and Allocation

The Initial Acquisition and the Subsequent Acquisition described in Note 1 to our audited consolidated financial statements included elsewhere in this prospectus have been accounted for using the purchase method of accounting as of March 3, 2004 and June 24, 2005, respectively. The allocations of the purchase prices to the net assets acquired have been performed in accordance with SFAS No. 141, Business Combinations. In connection with the allocations of the purchase prices, management used estimates and assumptions to determine the fair value of the assets acquired and liabilities assumed. Changes in these assumptions and estimates such as discount rates and future cash flows used in the appraisal process could have a material impact on how the purchase prices were allocated at the dates of acquisition.

Liquidity and Capital Resources

Our principal sources of liquidity have historically been from cash from operations and borrowings under the credit facilities of our parent companies. In connection with the completion of this offering, we expect to enter into our own new revolving secured credit facility and to be removed as a guarantor or obligor under the credit facility of our parent company. Our principal uses of cash are expected to be capital expenditures, distributions and funding our debt service obligations. We believe that our cash from operations, together with the proceeds we retain from this offering and borrowings under our new revolving secured credit facility, will be adequate 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.

Debt

We have historically benefited from borrowings under our parent company’s credit facilities.

On June 24, 2005, our then-parent company Coffeyville Resources entered into a first lien credit facility and a second lien credit facility in connection with the Subsequent Acquisition. The first lien credit facility consisted of $225.0 million of tranche B term loans; $50 million of delayed draw term loans; a $100.0 million revolving loan facility; and a $150.0 million funded letter of credit facility. The second lien credit facility consisted of a $275.0 million term loan. We were a guarantor under these

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facilities. The net proceeds of these facilities, together with an equity contribution from Coffeyville Acquisition, were used to fund the Subsequent Acquisition. The first lien credit facility was amended and restated on June 29, 2006 on substantially the same terms as the June 24, 2005 agreement, principally in order to reduce the applicable margin spreads for borrowings on the first lien term loans and the funded letter of credit facility.

On December 28, 2006, Coffeyville Resources entered into a new secured credit facility which provided financing of up to $1.075 billion and replaced the first lien and second lien credit facilities. The new secured credit facility consisted of $775 million of tranche D term loans, a $150 million revolving credit facility, and a funded letter of credit facility of $150 million. The term loans mature on December 28, 2013, the revolving facility matures on December 28, 2012 and the funded letter of credit facility expires on December 28, 2010. Interest on the term loans and revolving facility accrues at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). The borrower also pays 0.50% per annum in commitment fees on the unused portion of the revolving loan facility. The credit facility required the borrower to prepay outstanding loans, subject to certain exceptions, with 100% of net asset sale proceeds and net insurance proceeds, 100% of the cash proceeds from the incurrence of specified debt obligations, 75% of consolidated excess cash flow, and 100% of the cash proceeds from any initial public offering or secondary registered equity offering. Prior to this offering, we were a guarantor under this credit facility. However, we expect to be removed as a guarantor upon the completion of this offering.

In August 2007, as a result of the flood, our parent companies entered into three new credit facilities:


	•	*$25 Million Secured Facility.* Coffeyville Resources entered into a new $25 million senior secured term loan. Interest was payable in cash, at the borrower’s option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. We were a guarantor under this facility.

	•	*$25 Million Unsecured Facility.* Coffeyville Resources entered into a new $25 million senior unsecured term loan. Interest was payable in cash, at the borrower’s option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. We were a guarantor under this facility.

	•	*$75 Million Unsecured Facility* Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75 million senior unsecured term loan. Drawings could be made from time to time in amounts of at least $5 million. Interest accrued, at the borrower’s option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amounts were ever drawn on this facility.

In October 2007, in connection with CVR Energy’s initial public offering, all amounts outstanding under the $25 million secured facility and the $25 million unsecured facility were repaid and the three facilities entered into in August 2007 were terminated.

New Revolving Secured Credit Facility

In connection with the completion of this offering, we expect to enter into a new revolving secured credit facility and to be removed as a guarantor or obligor from Coffeyville Resources’ credit facility and swap agreements with J. Aron. We currently are negotiating the terms of a proposed -year revolving secured credit facility which we expect would provide for commitments of $ million. We expect to enter into the proposed credit facility with a group of lenders at or prior to the closing of this offering. We expect that the revolving secured credit facility will be used to fund our ongoing working capital needs, letters of credit, distributions and for general partnership purposes,

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including potential future acquisitions and expansions. We expect that interest will accrue at a base rate or, at our option, LIBOR plus an applicable margin and that we will also pay a commitment fee for undrawn amounts. The facility will be prepayable at our option at any time and will contain mandatory prepayment provisions with the proceeds of certain asset sales and debt issuances. The credit facility will contain customary covenants which, among other things, will limit our ability to incur indebtedness, incur liens, make distributions, sell assets, make investments, enter into transactions with affiliates, or consummate mergers. The credit facility will also contain customary events of default. We have not received a commitment letter from any prospective lender with respect to the new revolving secured credit facility, and we cannot assure you that we will be able to obtain a revolving secured credit facility or do so on acceptable terms.

Capital Spending

We divide our capital spending needs into two categories: maintenance, which is either capitalized or expensed, and expansion, which is capitalized. Maintenance capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety laws and regulations. Our maintenance capital spending needs, including major scheduled turnaround expenses, were approximately $4.4 million in 2007 and we estimate that the maintenance capital spending needs of our business will be approximately $13.7 million in 2008 and approximately $36.0 million in the aggregate over the four-year period beginning 2009. These estimates include, among other items, the capital costs necessary to comply with environmental laws and regulations. Our maintenance capital spending is expected to be higher in 2008 than prior years principally due to (1) approximately $2.75 million of incremental turnaround costs expected during 2008 and (2) approximately $3.6 million of non-recurring expenditures related to purchasing a spare piece of equipment in 2008 to increase redundancy in response to equipment failures in 2007. Our new revolving secured credit facility may limit the amount we can spend on capital expenditures.

The following table sets forth our estimate of maintenance capital spending for our business for the years presented as of December 31, 2007 (other than 2006 and 2007 which reflect actual spending). Our future capital spending will be determined by our managing general partner. The data contained in the table below represents our current plans, but these plans may change as a result of unforeseen circumstances and we may revise these estimates from time to time or not spend the amounts in the manner allocated below.


	Actual				Estimated

	2006		2007		2008		2009		2010		2011		2012		Cumulative
	(in millions)
Environmental and safety capital needs	$	0.1	$	0.5	$	2.0	$	4.7	$	2.6		2.7		3.8	$	16.4
Sustaining capital needs		6.6		3.9		8.9		3.2		4.5		4.8		4.3		36.2

		6.7		4.4		10.9		7.9		7.1		7.5		8.1		52.6
Major scheduled turnaround expenses		2.6		—		2.8		—		2.6		—		2.8		10.8

Total estimated maintenance capital spending	$	9.3	$	4.4	$	13.7	$	7.9	$	9.7	$	7.5	$	10.9	$	63.4

In addition to maintenance capital spending, we also undertake expansion capital spending based on the expected return on incremental capital employed. Expansion capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. As of December 31, 2007, we had committed approximately $8 million towards expansion capital spending in 2008. In addition to the $8 million committed in 2008 and our approximately $85 million nitrogen fertilizer plant expansion project referred to below, we anticipate

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additional expansion projects will be identified and may result in additional capital expenditures. See “Business — Our Business Strategy — Executing Several Efficiency-Based and Other Projects.”

We are currently moving forward with an approximately $85 million fertilizer plant expansion, of which approximately $8 million was incurred as of December 31, 2007. We estimate this expansion will increase our nitrogen fertilizer plant’s capacity to upgrade ammonia into premium priced UAN by approximately 50%. We currently expect to complete this expansion in late 2009 or early 2010. This project is also expected to improve the cost structure of the nitrogen fertilizer business by eliminating the need for rail shipments of ammonia, thereby avoiding anticipated cost increases in such transport.

Cash Flows

Operating Activities

Comparability of cash flows from operating activities for the years ended December 31, 2007 and December 31, 2006 and the twelve-month period ended December 31, 2005 has been impacted by the Subsequent Acquisition. See “— Factors Affecting Comparability”. Completion of the Subsequent Acquisition by CVR Energy required a mark up of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold (exclusive of depreciation and amortization). Therefore, the discussion of cash flows from operations has been broken down into four separate periods: the year ended December 31, 2007, the year ended December 31, 2006, the 174 days ended June 23, 2005 and the 191 days ended December 31, 2005.

Net cash flows from operating activities for the year ended December 31, 2007 was $46.5 million. The positive cash flow from operating activities generated over this period was primarily driven by a strong fertilizer price environment. 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. Trade working capital for the year ended December 31, 2007 reduced our operating cash flow by $4.7 million. For the year ended December 31, 2007, accounts receivable increased $4.0 million while inventory increased by $2.0 million resulting in a net use of cash of $6.0 million. These uses of cash due to changes in trade working capital were offset by an increase in accounts payable, or a source of cash, of $1.3 million. With respect to other working capital, the primary source of cash during the year ended December 31, 2007 was a $4.3 million increase in deferred revenue. Deferred revenue represents customer prepaid deposits for the future delivery of our nitrogen fertilizer products. Offsetting the source of cash from deferred revenue were uses of cash related to insurance receivable ($3.3 million), due from affiliate ($2.1 million), prepaid expenses and other current assets ($0.2 million) and accrued expenses and other current liabilities ($0.2 million).

Net cash flows from operating activities for the year ended December 31, 2006 was $34.1 million. The positive cash flow from operating activities generated over this period was primarily driven by a moderate operating environment and favorable changes in trade working capital, partially offset by unfavorable changes in other working capital over the period. Increasing our operating cash flow for the year ended December 31, 2006 was a $2.9 million source of cash related to a decrease in trade working capital. For the year ended December 31, 2006, accounts receivable and inventory decreased approximately $0.7 million and $2.1 million, respectively, as accounts payable remained essentially unchanged. The primary uses of cash during the period include a $3.2 million decrease in deferred revenue and a $2.4 million decrease in accrued expenses and other current liabilities.

Net cash flows from operating activities for the 174 days ended June 23, 2005 was $24.3 million. The positive cash flow generated over this period was primarily driven by income of $32.7 million, partially offset by a $10.4 million increase in other working capital. With respect to trade working capital during this period, a $2.8 million increase in accounts payable and a $0.6 million decrease in inventory were partially offset by an increase in accounts receivable of $1.3 million. The $10.4 million use of cash related to other working capital was primarily related to a $9.1 million reduction in

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deferred revenue. Most deferred revenue is collected ahead of the spring fertilizer season and the balance is reduced as fertilizer is delivered. As such, June 23, 2005 would represent a seasonal low point in fertilizer prepaid contacts.

Net cash flows provided by operating activities for the 191 days ended December 31, 2005 was $45.3 million. The positive cash flow from operating activities generated over this period was primarily the result of strong operating earnings during the period. Trade working capital resulted in a use of $1.7 million in cash during the 191 days ended December 31, 2005 as an increase in accounts receivable of $2.7 million and a decrease in accounts payable of $1.6 million was partially offset by a decrease in inventory of $2.7 million. In addition to strong operating earnings, a $12.6 million source of cash related to changes in other working capital was primarily the result of a $11.5 million increase in deferred revenue. Most deferred revenue is collected ahead of the spring fertilizer season and the balance is reduced as fertilizer is delivered. As such, December 31, 2005, would represent a seasonal high point in fertilizer prepaid contacts for spring delivery.

Investing Activities

Net cash used in investing activities for the year ended December 31, 2007, the year ended December 31, 2006, the 191 days ended December 31, 2005 and the 174 days ended June 23, 2005 was $6.5 million, $13.3 million, $2.0 million and 1.4 million, respectively. Net cash used in investing activities principally relates to capital expenditures.

Financing Activities

Comparability of cash flows from financing activities for the years ended December 31, 2007, December 31, 2006 and the twelve-month period ended December 31, 2005 has been impacted by the Subsequent Acquisition. Net cash used in financing activities for the year ended December 31, 2007 was $25.5 million as compared to net cash used in financing activities of $20.8 million for the year ended December 31, 2006. Net cash used by financing activities for the 174 days ended June 23, 2005 was $22.9 million and net cash used in financing activities for the 191 days ended December 31, 2005 was $43.3 million.

CVR Energy’s centralized approach to cash management and the financing of its operations resulted in our business utilizing CVR Energy’s credit facilities for funding its activities via divisional equity, our only source of cash other than operations. We did not have our own credit facility during these periods or engage in any other borrowing other than borrowings through our parent. The amounts of net cash used in financing activities reflect the fertilizer business’s contribution of divisional equity to its parent companies in each of the periods presented. The fertilizer business remitted net cash flow to its parent company in each period so that the parent company could pay down consolidated debt.

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, 2007 relating to operating leases, unconditional purchase obligations and environmental liabilities for each of the four years following December 31, 2007 and thereafter.

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 fertilizer margins, natural gas prices and general economic, financial, competitive, legislative, regulatory and other factors that are beyond our control.

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	Payments Due by Period
	Total		2008		2009		2010		2011		2012		Thereafter
	(in millions)

Contractual Obligations
Operating leases(1)	$	8.5	$	3.5	$	2.8	$	1.2	$	0.7	$	0.3	$	—
Unconditional purchase obligations(2)		71.6		5.5		5.5		5.6		5.7		5.8		43.5
Unconditional purchase obligations with affiliates(3)		221.1		10.0		10.8		10.0		11.3		11.3		167.7
Environmental liabilities(4)		0.2		0.2		—		—		—		—		—

Total	$	301.4	$	19.2	$	19.1	$	16.8	$	17.7	$	17.4	$	211.2


(1)		We lease various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods.

(2)		The amount includes commitments under an electric supply agreement with the city of Coffeyville and a product supply agreement with the Linde Group.

(3)		The amount includes commitments under our 20-year coke supply agreement with CVR Energy.

(4)		Represents our estimated remaining costs of remediation to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program.

Under our 20-year 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 business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our new revolving secured credit facility, in an amount sufficient to enable us to make the minimum quarterly distribution, finance necessary capital expenditures, service our indebtedness or fund our other liquidity needs. We may seek to sell assets 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.

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Board, or FASB, issued SFAS No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and spoilage. Under SFAS 151, such items will be recognized as current-period charges. In addition, SFAS 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. Successor adopted SFAS 151 effective January 1, 2006. There was no impact on our financial position or results of operation as a result of adopting this standard.

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The Emerging Issues Task Force, or EITF, reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty, and the FASB ratified it on September 28, 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues, and when they should be recorded as an exchange measured at the book value of the item sold. This Issue is to be applied to new arrangements entered into in reporting periods beginning after March 15, 2006. The adoption of this EITF did not have a material impact on our financial position or results of operations.

In June 2006, the FASB ratified its consensus on EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should Be Presented in the Income Statement. EITF 06-3 includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include sales, use, value added, and some excise taxes. These taxes should be presented on either a gross or net basis, and if reported on a gross basis, a company should disclose amounts of those taxes in interim and annual financial statements for each period for which an income statement is presented. The guidance in EITF 06-3 is effective for all periods beginning after December 15, 2006 and did not have a material impact on our financial position or results of operations.

In June 2006, the FASB issued Interpretation (FIN) No. 48, Accounting for Uncertain Tax Positions — an interpretation of FASB Statement No. 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB Statement No. 109, Accounting for Income Taxes, by prescribing a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise would be required to recognize in its financial statements the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. The application of FIN No. 48 is effective for fiscal years beginning after December 15, 2006 and it did not have a material impact on our financial position or results of operations.

In May 2005, the FASB issued SFAS No. 154, Accounting Changes and Error Corrections, which replaces APB Opinion No. 20, Accounting Changes and SFAS No. 3, Reporting Accounting Changes in Interim Financial Statements. SFAS 154 retained accounting guidance related to changes in estimates, changes in a reporting entity and error corrections. However, changes in accounting principles must be accounted for retrospectively by modifying the financial statements of prior periods unless it is impracticable to do so. SFAS 154 is effective for accounting changes made in fiscal years beginning after December 15, 2005. The adoption of SFAS 154 did not have a material impact on our financial position or results of operations.

In September 2006, the FASB issued SFAS No. 157, Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS No. 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price)”. The statement is effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. We are currently evaluating the effect that this statement will have on our financial statements.

In September 2006, the FASB issued FASB Staff Position, or FSP, No. AUG AIR-1, Accounting for Planned Major Maintenance Activities, that disallowed the accrue-in-advance method for planned major maintenance activities. Our scheduled turnaround activities are considered planned major maintenance activities. Since we do not use the accrue-in-advance method of accounting for our turnaround activities, this FSP has no impact on our financial statements.

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In September 2006, the SEC issued SAB No. 108, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in Current Year Financial Statements. SAB 108 was issued to address diversity in practice in quantifying financial statement misstatements and the potential under current practice for the build-up of improper amounts on the balance sheet. The effects of applying the guidance issued in SAB 108 are to be reflected in annual financial statements covering the first fiscal year ending after November 15, 2006. The initial adoption of SAB 108 in 2006 did not have an impact on our financial position or results of operations.

In February 2007, the FASB issued SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities. Under this standard, an entity is required to provide additional information that will assist investors and other users of financial information to more easily understand the effect of the company’s choice to use fair value on its earnings. Further, the entity is required to display the fair value of those assets and liabilities for which the company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS 157 and SFAS No. 107, Disclosures about Fair Value of Financial Instruments. SFAS 159 is effective for fiscal years beginning after November 15, 2007, and early adoption is permitted as of January 1, 2007, provided that the entity makes that choice in the first quarter of 2007 and also elects to apply the provisions of SFAS 157. We are currently evaluating the potential impact that SFAS 159 will have on our financial condition, results of operations and cash flows.

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.

Quantitative and Qualitative Disclosures About Market Risk

Market risk represents the risk of loss that may impact our financial position, results of operations or cash flows due to adverse changes in financial and commodity market prices and rates. 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) or interest rates. Given that our business is currently based entirely in the U.S., 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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