SEC Filing | CVR Energy, Inc.

Proposed Maximum

Title of Each Class of

Aggregate Offering

Securities to be Registered

Price (1)(2)

Amount of Registration Fee (3)

Common Stock, $0.01 par value

$300,000,000

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S-1/A

As filed with the Securities and Exchange Commission on December 18, 2006

Registration No. 333-137588

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

AMENDMENT NO. 2

FORM S-1

REGISTRATION STATEMENT UNDER

THE SECURITIES ACT OF 1933

CVR ENERGY, INC.

(Exact Name of Registrant as Specified in Its Charter)


Delaware	2911	61-1512186
(State or Other Jurisdiction of	(Primary Standard Industrial	(I.R.S. Employer
Incorporation or Organization)	Classification Code Number)	Identification Number)

2277 Plaza Drive, Suite 500

Sugar Land, Texas 77479

(281) 207-7711

(Address, Including Zip Code, and Telephone Number,

Including Area Code, of Registrant’s Principal Executive Offices)

John J. Lipinski

2277 Plaza Drive, Suite 500

Sugar Land, Texas 77479

(281) 207-7711

(Name, Address, Including Zip Code, and Telephone Number,

Including Area Code, of Agent for Service)

With a copy to:


Stuart H. Gelfond Michael A. Levitt Fried, Frank, Harris, Shriver & Jacobson LLP One New York Plaza New York, New York 10004 (212) 859-8000		Peter J. Loughran Debevoise & Plimpton LLP 919 Third Avenue New York, New York 10022 (212) 909-6000

Approximate date of commencement of proposed sale to the public: As soon as practicable after the effective date of this Registration Statement.

If any of the securities being registered on this Form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this Form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

CALCULATION OF REGISTRATION FEE


(1)		Includes offering price of shares which the underwriters have the option to purchase.

(2)		Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933, as amended.

(3)		Previously paid.

The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.

The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion. Dated December 18, 2006.

CVR Energy, Inc.

Common Stock

This is an initial public offering of shares of common stock of CVR Energy, Inc. CVR Energy is offering all of the shares to be sold in the offering.

Prior to this offering, there has been no public market for the common stock. It is currently estimated that the initial public offering price per share will be between $ and $ . CVR Energy intends to list the common stock on the under the symbol “ ”.

See “Risk Factors” beginning on page 17 to read about factors you should consider before buying shares of the common stock.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or passed upon the adequacy or accuracy of this prospectus. Any representation to the contrary is a criminal offense.


	Per Share	Total

Initial public offering price	$	$
Underwriting discount	$	$
Proceeds, before expenses, to us	$	$

To the extent that the underwriters sell more than shares of common stock, the underwriters have the option to purchase up to an additional shares from the selling stockholder at the initial public offering price less the underwriting discount.

The underwriters expect to deliver the shares against payment in New York, New York on , 2006.

Prospectus dated , 2006.

PROSPECTUS SUMMARY

This summary highlights selected information contained elsewhere in this prospectus. You should carefully read the entire prospectus, including the “Risk Factors” and the consolidated financial statements and related notes included elsewhere in this prospectus, before making an investment decision. In this prospectus, all references to “the Company,” “Coffeyville,” “we,” “us,” and “our” refer to CVR Energy, Inc. and its consolidated subsidiaries, unless the context otherwise requires or where otherwise indicated. You should also see the “Glossary of Selected Terms” beginning on page 167 for definitions of some of the terms we use to describe our business and industry. We use non-GAAP measures in this prospectus, including Net income adjusted for unrealized gain or loss from Cash Flow Swap. For a reconciliation of this measure to net income, see footnote 3 under “— Summary Consolidated Financial Information.”

Our Business

We are an independent refiner and marketer of high value transportation fuels and a premier producer of ammonia and urea ammonia nitrate, or UAN, fertilizers. We are one of only seven petroleum refiners and marketers in the Coffeyville supply area (Kansas, Oklahoma, Missouri, Nebraska and Iowa) and, at current natural gas prices, the lowest cost producer and marketer of ammonia and UAN in North America.

Our petroleum business includes a 108,000 barrel per day, or bpd, complex full coking sour crude refinery in Coffeyville, Kansas. In addition, our supporting businesses include (1) a crude oil gathering system serving central Kansas and northern Oklahoma, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, and (3) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg, and to customers at throughput terminals on Magellan Midstream Partners L.P.’s refined products distribution systems. In addition to rack sales (sales which are made at terminals using tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Partners LP and Valero LP. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, the largest crude oil trading and storage hub in the United States, served by numerous pipelines from locations including the U.S. Gulf Coast and Canada providing us with access to virtually any crude variety in the world capable of being transported by pipeline.

Our nitrogen fertilizer business is the only operation in North America that utilizes a coke gasification process to produce ammonia. A majority of the ammonia produced by our fertilizer plant is further upgraded to UAN fertilizer (a solution of urea, ammonium nitrate and water used as a fertilizer). By using petroleum coke, or pet coke (a coal-like substance that is produced during the refining process), instead of natural gas as raw material, we are the lowest cost producer of ammonia and UAN in North America. Furthermore, on average, over 80% of the pet coke utilized by us is produced and supplied to the fertilizer plant as a by-product of our refinery. As such, we benefit from high natural gas prices, as fertilizer prices increase with natural gas prices, while our input costs remain substantially the same.

We generated combined net sales of $1.7 billion, $2.4 billion and $3.0 billion and operating income of $111.2 million, $270.8 million and $329.7 million for the fiscal years ended December 31, 2004 and 2005, and the twelve months ended September 30, 2006, respectively. For the fiscal years ended December 31, 2004 and 2005 and the twelve months ended September 30, 2006, our petroleum business contributed 76%, 74% and 84%, respectively, of our combined operating income, with substantially all of the remainder contributed by our nitrogen fertilizer business.

Significant Milestones Since the Change of Control in June 2005

Increased Refinery Throughput and Yields. Management’s focus on crude slate optimization (the process of determining the most economic crude oils to be refined), reliability, technical support and operational excellence coupled with prudent expenditures on equipment has significantly improved the operating metrics of the refinery. The refinery’s crude throughput rate (the volume per day processed through the refinery) has increased from an average of less than 90,000 bpd to an average of greater than 102,000 bpd in the second quarter of 2006 with peak daily rates in excess of 108,000 bpd of crude. Crude throughputs averaged 94,000 bpd for the first nine months of 2006, an improvement of over 4,000 bpd over the first nine months of 2005. Recent operational improvements at the refinery have also allowed us to produce higher volumes of favorably priced distillates (primarily No. 1 diesel fuel and kerosene), premium gasoline and boutique gasoline grades and to improve our liquid volume yield.

Diversified Crude Feedstock Variety. We have expanded the variety of crude grades processed in any given month from a limited few to over a dozen. This has improved our crude purchase cost discount to West Texas Intermediate, or WTI, from $2.80 per barrel in the first nine months of 2005 to $4.29 per barrel in the first nine months of 2006.

Expanded Direct Rack Sales. We have significantly expanded and intend to continue to expand rack marketing of refined products (petroleum products such as gasoline and diesel fuel) directly to customers rather than origin bulk sales. We presently sell approximately 23% of our produced transportation fuels at enhanced margins in this manner, which has helped improve our net income for the first nine months of 2006 compared to the first nine months of 2005.

Significant Plant Improvement and Capacity Expansion Projects. Management has identified and developed several significant capital projects with an estimated total cost of approximately $400 million primarily aimed at (1) expanding refinery capacity (throughput the refinery is capable of sustaining on a daily basis), (2) enhancing operating reliability and flexibility, (3) complying with more stringent environmental, health and safety standards, and (4) improving our ability to process heavy sour crude feedstock varieties (petroleum products that are processed and blended into refined products). Our experienced engineering and construction team manages these projects with support from established specialized contractors thus giving us maximum control and oversight of execution. We have already completed multiple initiatives under this program, with targeted completion of substantially all of these capital projects prior to the end of 2007. We intend to finance these capital projects with cash from our operations and occasional borrowings from our revolving credit facility.

We have also undertaken a study to review expansion of the refinery beyond the program described above. Preliminary engineering for the first stage of a potential multi-stage expansion has been approved by our board of directors. We anticipate that each stage of this extended expansion program would decrease the refinery crude cost by enabling the plant to process significant additional volumes of lower cost heavy sour crude from Canada or offshore. If fully implemented, this first phase would be intended for completion in 2009.

Key Market Trends

We have identified several key factors which we believe should favorably contribute to the long-term outlook for the refining and nitrogen fertilizer industries.

For the refining industry, these factors include the following:


	•	High capital costs, historical excess capacity and environmental regulatory requirements that have limited the construction of new refineries in the United States over the past 30 years.


	•	Continuing improvement in the supply and demand fundamentals of the global refining industry as projected by the Energy Information Administration of the U.S. Department of Energy, or the EIA.


	•	Increasing demand for sweet crude oils and higher incremental production of lower cost sour crude that are expected to provide a cost advantage to sour crude processing refiners.


	•	New and evolving U.S. fuel specifications, including reduced sulfur content, reduced vapor pressure and the addition of oxygenates such as ethanol, that should benefit refiners who are able to efficiently produce fuels that meet these specifications.


	•	Limited competitive threat from foreign refiners due to sophisticated U.S. fuel specifications and increasing foreign demand for refined products.


	•	Refining capacity shortage in the mid-continent region, as certain regional markets in the U.S. are subject to insufficient local refining capacity to meet regional demands. This should result in local refiners earning higher margins on product sales than those who must rely on pipelines and other modes of transportation for supply.

For the nitrogen fertilizer industry, these factors include the following:


	•	The impact of a growing world population combined with an expanded use of corn for the production of ethanol both of which are expected to drive worldwide grain demand and farm production, thereby increasing demand for nitrogen-based fertilizers.


	•	High natural gas prices in North America that contribute to higher production costs for natural gas-based U.S. ammonia producers should result in elevated nitrogen fertilizer prices as natural gas price trends generally dictate nitrogen fertilizer price trends.

However, both of our industries are cyclical and volatile and have experienced downturns in the past. See “Risk Factors.”

Our Competitive Strengths

Regional Advantage and Strategic Asset Location. Our refinery is one of only seven refineries located in the Coffeyville supply area within the mid-continent region, where demand for refined products exceeded refining production by approximately 24% in 2005. We estimate that this favorable supply/demand imbalance combined with our lower pipeline transportation cost as compared to the U.S. Gulf Coast refiners has allowed us to generate refining margins, as measured by the 2-1-1 crack spread, that have exceeded U.S. Gulf Coast refining margins by approximately $1.40 per barrel on average for the last four years. The 2-1-1 crack spread is a general industry standard that approximates the refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel. In addition, our nitrogen fertilizer business is geographically advantaged to supply products to markets in Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without incurring intermediate transfer, storage, barge or pipeline freight charges. We estimate that this geographic advantage provides us with a distribution cost benefit over U.S. Gulf Coast ammonia and UAN importers, assuming in each case freight rates and handling charges for U.S. Gulf Coast importers as in effect in September 2006. These cost differentials represent a significant portion of the market price of these commodities.

Access to and Ability to Process Multiple Crude Oils. Since June 2005 we have significantly expanded the variety of crude grades processed in any given month. While our proximity to the Cushing crude oil trading hub minimizes the likelihood of an interruption to our supply, we intend to further diversify our sources of crude oil. Among other initiatives in this regard, we have secured shipper rights on the newly built Spearhead pipeline, which connects Chicago to the Cushing

hub and provides us with access to incremental oil supplies from Canada. We also own and operate a crude gathering system located in northern Oklahoma and central Kansas, which allows us to acquire quality crudes at a discount to WTI.

High Quality, Modern Asset Base with Solid Track Record. Our refinery’s complexity allows us to optimize the yields (the percentage of refined product that is produced from crude and other feedstocks) of higher value transportation fuels (gasoline and distillate), which currently account for approximately 94% of our liquid production output. Complexity is a measure of a refinery’s ability to process lower quality crude in an economic manner; greater complexity makes a refinery more profitable. From 1995 through the first nine months of 2006, we have invested approximately $375 million to modernize our oil refinery and to meet more stringent U.S. environmental, health and safety requirements. As a result, we have achieved significant increases in our refinery crude throughput rate from an average of less than 90,000 bpd prior to June 2005 to an average of over 102,000 bpd in the second quarter of 2006 and over 94,000 bpd for the first nine months of 2006 with peak daily rates in excess of 108,000 bpd. Our fertilizer plant, completed in 2000, is the newest facility of its kind in North America, utilizes less than 1% of the natural gas relative to natural gas-based fertilizer producers and, since 2003, has demonstrated a consistent record of operating near full capacity. This plant underwent a scheduled turnaround in 2006, and we have recently expanded the plant’s spare gasifier to increase its production capacity.

Near Term Internal Expansion Opportunities. With the completion of $400 million of identified and developed significant capital projects, we expect to significantly enhance the profitability of our refinery during periods of high crack spreads while enabling the refinery to operate more profitably at lower crack spreads than is currently possible. A crack spread is a simplified calculation that measures the difference between the price for light products (gasoline, diesel fuel) and crude oil. We also estimate that our contemplated fertilizer plant expansion could increase our capacity to upgrade ammonia into premium priced UAN by 50% to approximately 1,000,000 tons per year.

Experienced Management Team. In conjunction with the acquisition of our business by Coffeyville Acquisition LLC in June 2005, a new senior management team was formed that blended the best of existing management with highly experienced new members. Our senior management team averages over 27 years of refining and fertilizer industry experience and, in coordination with our broader management team, has made significant and rapid improvements on many fronts since the acquisition of Coffeyville Resources, resulting in increased operating income and shareholder value. Mr. John J. (Jack) Lipinski, our Chief Executive Officer, has over 34 years experience in the refining and chemicals industries, and prior to joining us in connection with the acquisition of Coffeyville Resources in June 2005, was in charge of a 550,000 bpd refining system and a multi-plant fertilizer system. Mr. Stanley A. Riemann, our Chief Operating Officer, has over 32 years of experience, and prior to joining us in March 2004, was in charge of one of the largest fertilizer manufacturing systems in the United States. Mr. James T. Rens, our Chief Financial Officer, has over 15 years experience in the energy and fertilizer industries, and prior to joining us in March 2004, was the chief financial officer of two fertilizer manufacturing companies.

Our Business Strategy

Our objective is to continue to increase the economic throughput (the volume of crude processed each day) of our operating facilities, control direct operating expenses and take advantage of market opportunities as they arise by:


	•	Continuing to take advantage of favorable supply and demand dynamics in the mid-continent region (where demand for our products currently outweighs supply);


	•	Selectively investing in significant projects that enhance our operating efficiency and expanding our capacity while rigorously controlling costs;


	•	Increasing our sales and supply capabilities of UAN, and other high value products, while finding lower cost sources of raw materials;


	•	Continuing to focus on being a reliable, low cost producer of petroleum and fertilizer products;


	•	Continuing to focus on the reliability, safety and environmental performance of our operations; and


	•	Selectively evaluating growth opportunities through acquisitions and/or strategic alliances.

Cash Flow Swap

In conjunction with the acquisition of our business by Coffeyville Acquisition LLC, on June 16, 2005, Coffeyville Acquisition LLC entered into a series of commodity derivative arrangements, or the Cash Flow Swap, with J. Aron & Company, or J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. Pursuant to the Cash Flow Swap, sales representing approximately 70% and 17% of then forecasted refinery output for the periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, have been economically hedged. The derivative took the form of three New York Mercantile Exchange, or NYMEX, swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. The Cash Flow Swap was assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. We entered into these swap agreements for the following reasons:


	•	Debt was used as part of the acquisition financing in June 2005 which required the introduction of a financial risk management tool that would mitigate a portion of inherent commodity price based volatility in our cash flow and preserve our ability to service debt; and


	•	Given the size of the capital expenditure program contemplated by us at the time of the June 2005 acquisition, we considered it necessary to enter into a derivative arrangement to reduce the volatility of our cash flow and to ensure an appropriate return on the incremental invested capital.

We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current generally accepted accounting principles in the United States, or GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements. Given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes “Net income adjusted for unrealized gain or loss from Cash Flow Swap” as a key indicator of our business performance and believes that this non-GAAP measure is a useful measure for investors in analyzing our business.

Our History

Prior to March 3, 2004, our assets were operated as a small component of Farmland Industries, Inc., or Farmland, an agricultural cooperative. Farmland filed for bankruptcy protection on May 31, 2002. Coffeyville Resources, LLC, a subsidiary of Coffeyville Group Holdings, LLC, won the

bankruptcy court auction for Farmland’s petroleum business and a nitrogen fertilizer plant and completed the purchase of these assets on March 3, 2004. 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. The Goldman Sachs Funds and the Kelso Funds own substantially all of the common units of Coffeyville Acquisition LLC, which currently owns all of our capital stock.

Prior to this offering, Coffeyville Acquisition LLC directly or indirectly owned all of our subsidiaries. We were formed as a wholly owned subsidiary of Coffeyville Acquisition LLC in order to complete this offering. Concurrently with this offering, we will merge a newly formed direct subsidiary of ours with Coffeyville Refining & Marketing, Inc. and merge a separate newly formed direct subsidiary of ours with Coffeyville Nitrogen Fertilizers, Inc. which will make Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc. direct wholly owned subsidiaries of ours. We refer to these pre-IPO reorganization transactions in the prospectus as the “Transactions.”

Organizational Structure

The following chart illustrates our organizational structure upon completion of this offering:

The Offering


Issuer		CVR Energy, Inc.

Common stock offered by us		shares.

Common stock outstanding immediately after the offering		shares.


Use of proceeds		We estimate that the net proceeds to us in this offering, after deducting the underwriters’ discount of $ million, will be $ million. We intend to use the net proceeds from this offering for debt repayment. We will not receive any proceeds from the purchase by the underwriters of up to shares from the selling stockholder in connection with the exercise by the underwriters of their option. See “Use of Proceeds.”


Proposed symbol		“ .”

Risk Factors		See “Risk Factors” beginning on page 18 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock.

Unless we specifically state otherwise, the information in this prospectus does not take into account the sale of up to shares of common stock, which the underwriters have the option to purchase from the selling stockholder. The information in this prospectus gives effect to a -for- stock split which will occur prior to the completion of this offering.

CVR Energy, Inc. was incorporated in Delaware in September 2006. Our principal executive offices are located at 2277 Plaza Drive, Suite 500 Sugar Land, Texas 77479, and our telephone number is (281) 207-7711. Our website address is www.coffeyvillegroup.com. Information contained on our website is not a part of this prospectus.

The Goldman Sachs Funds and the Kelso Funds are the principal investors in Coffeyville Acquisition LLC, which currently owns all of our capital stock. For further information on these entities and their relationships with us, see “Certain Relationships and Related Party Transactions.”

Summary Consolidated Financial Information

The summary consolidated financial information presented below under the caption Statement of Operations Data for the year ended December 31, 2003, for the 62-day period ended March 2, 2004, for the 304-day period ended December 31, 2004, for the 174-day period ended June 23, 2005 and for the 233-day period ended December 31, 2005, and the summary consolidated financial information presented below under the caption Balance Sheet Data as of December 31, 2004 and 2005, have been derived from our consolidated financial statements included elsewhere in this prospectus, which consolidated financial statements have been audited by KPMG LLP, independent registered public accounting firm. The summary consolidated balance sheet data as of December 31, 2003 is derived from our audited consolidated financial statements that are not included in this prospectus. The summary unaudited interim consolidated financial information presented below under the caption Statement of Operations Data for the 141-day period ended September 30, 2005 and the nine-month period ended September 30, 2006, and the summary consolidated financial information presented below under the caption Balance Sheet Data as of September 30, 2006, have been derived from our unaudited interim consolidated financial statements, which are included elsewhere in this prospectus and have been prepared on the same basis as the audited consolidated financial statements. In the opinion of management, the interim data reflect all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of results for these periods. Operating results for the nine-month period ended September 30, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006. The summary unaudited non-GAAP combined financial information presented under the captions Statement of Operations Data, Other Financial Data, and Key Operating Statistics for the years ended December 31, 2004 and 2005 and for the nine months ended September 30, 2005 have been derived by summing the operating results of Immediate Predecessor’s and Successor’s operating results for the respective periods. We have also included herein certain industry data.

The summary unaudited pro forma condensed consolidated statement of operations data, other financial data and key operating statistics for the fiscal year ended December 31, 2005 give pro forma effect to the acquisition by Coffeyville Acquisition LLC of all of the subsidiaries of Coffeyville Group Holdings, LLC (which we refer to collectively as Immediate Predecessor), in the manner described under “Unaudited Pro Forma Condensed Consolidated Statements of Operations,” as if the acquisition had occurred as of January 1, 2005. We refer to our acquisition of Immediate Predecessor as the Subsequent Acquisition. The summary unaudited as adjusted consolidated financial information presented under the caption Balance Sheet Data as of September 30, 2006 gives effect to this offering, the use of proceeds from this offering and the Transactions as if they occurred on September 30, 2006. The summary unaudited pro forma information does not purport to represent what our results of operations would have been if the Subsequent Acquisition had occurred as of the date indicated or what these results will be for future periods.

Prior to March 3, 2004, our assets were operated as a component of Farmland Industries, Inc. Farmland filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code on May 31, 2002. On March 3, 2004, Coffeyville Resources, LLC completed the purchase of the former Petroleum Division and one facility within the eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division of Farmland (which we refer to collectively as Original Predecessor) from Farmland in a sales process under Chapter 11 of the U.S. Bankruptcy Code. See note 1 to our consolidated financial statements included elsewhere in this prospectus. We refer to this acquisition as the Initial Acquisition. As a result of certain adjustments made in connection with the Initial Acquisition, a new basis of accounting was established on the date of the Initial Acquisition and the results of operations for the 304 days ended December 31, 2004 are not comparable to prior periods.

During Original Predecessor periods, Farmland allocated certain general corporate expenses and interest expense to Original Predecessor. The allocation of these costs is not necessarily indicative of the costs that would have been incurred if Original Predecessor had operated as a stand-alone entity. Further, the historical results are not necessarily indicative of the results to be expected in future periods.

We calculate earnings per share for Successor on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering with respect to the existing shares. All information in this prospectus assumes that in conjunction with the initial public offering, the two direct wholly owned subsidiaries of Successor will merge with two of our direct wholly owned subsidiaries, we will effect a -for- stock split prior to completion of this offering, and we will issue shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering pursuant to the exercise by the underwriters of their option.

We have omitted earnings per share data for Immediate Predecessor because we operated under a different capital structure than what we will operate under at the time of this offering and, therefore, the information is not meaningful.

We have omitted per share data for Original Predecessor because, under Farmland’s cooperative structure, earnings of Original Predecessor were distributed as patronage dividends to members and associate members based on the level of business conducted with Original Predecessor as opposed to a common stockholder’s proportionate share of underlying equity in Original Predecessor.

Original Predecessor was not a separate legal entity, and its operating results were included with 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 qualifying patronage refunds and Farmland did not allocate income taxes to its divisions. As a result, Original Predecessor periods do not reflect any provision for income taxes.

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. See note 1 to our consolidated financial statements included elsewhere in this prospectus. 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. Since the assets and liabilities of Successor and Immediate Predecessor were each presented on a new basis of accounting, the financial information for Successor, Immediate Predecessor and Original Predecessor is not comparable.

Financial data for the 2005 fiscal year is presented as the 174 days ended June 23, 2005 and the 233 days ended December 31, 2005. Financial data for the first nine months of 2005 is presented as the 174 days ended June 23, 2005 and the 141 days ended September 30, 2005. Successor had no financial statement activity during the period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil, and gasoline option agreements entered into with a related party as of May 16, 2005.

The historical data presented below has been derived from financial statements that have been prepared using GAAP and the pro forma data presented below has been derived from the “Unaudited Pro Forma Condensed Consolidated Statements of Operations” included elsewhere in this prospectus. This data should be read in conjunction with the financial statements and related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.

In order to effectively review and assess the historical financial information below, we have included combined columns 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 12 months. The combined columns provide more meaningful information by effectively showing the actual operations of our business.

The combined columns include the 174-day period ended June 23, 2005 and the 141-day period ended September 30, 2005 to provide a comparative nine month period ended September 30, 2005 to the nine month period ended September 30, 2006. Additionally, the 62-day period ended March 2, 2004 and the 304-day period ended December 31, 2004 have been combined 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 233-day period ended December 31, 2005.


	Immediate
	Predecessor			Successor			Combined			Successor
	174 Days Ended			141 Days Ended			Nine Months			Nine Months
	June 23,			September 30,			Ended September 30,			Ended September 30,
	2005			2005			2005			2006
							(non-GAAP)
				(unaudited)			(unaudited)			(unaudited)
	(in millions, except as otherwise indicated)
Statement of Operations Data:
Net sales	$	980.7		$	776.6		$	1,757.3		$	2,329.2
Cost of product sold (exclusive of depreciation and amortization)		768.0			624.9			1,392.9			1,848.1
Direct operating expenses (exclusive of depreciation and amortization)		80.9			36.7			117.6			144.5
Selling, general and administrative expenses (exclusive of depreciation and amortization)		18.4			7.3			25.7			32.8
Depreciation and amortization		1.1			11.9			13.0			36.8

Operating income	$	112.3		$	95.8		$	208.1		$	267.0
Other income (expense)(1)		(8.4	)		0.1			(8.3	)		3.1
Interest (expense)		(7.8	)		(12.2	)		(20.0	)		(33.0	)
Gain (loss) on derivatives		(7.6	)		(487.1	)		(494.7	)		44.7

Income (loss) before taxes	$	88.5		$	(403.4	)	$	(314.9	)	$	281.8
Income tax (expense) benefit		(36.1	)		150.8			114.7			(111.0	)

Net income (loss)(2)	$	52.4		$	(252.6	)	$	(200.2	)	$	170.8
Pro forma earnings per share, basic and diluted
Pro forma weighted average shares, basic and diluted
Segment Financial Data:
Operating income (loss)
Petroleum	$	76.7		$	79.1		$	155.8		$	233.5
Nitrogen fertilizer		35.3			16.7			52.0			34.1
Other		0.3			—			0.3			(0.6	)

Operating income	$	112.3		$	95.8		$	208.1		$	267.0
Depreciation and amortization
Petroleum	$	0.8		$	7.7		$	8.5		$	23.6
Nitrogen fertilizer		0.3			4.2			4.5			12.7
Other		—			—			—			0.5

Depreciation and amortization	$	1.1		$	11.9		$	13.0		$	36.8
Other Financial Data:
Depreciation and amortization	$	1.1		$	11.9		$	13.0		$	36.8
Net income adjusted for unrealized gain or loss from Cash Flow Swap(3)		52.4			4.9			57.3			122.4
Cash flows provided by operating activities(4)		12.7			63.3			n/a			97.9
Cash flows (used in) investing activities		(12.3	)		(697.2	)		(709.5	)		(173.0	)
Cash flows provided by (used in) financing activities		(52.4	)		713.2			660.8			48.5
Capital expenditures for property, plant and equipment		(12.3	)		(12.1	)		(24.4	)		(173.0	)
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)(6)		99,171			105,162			101,344			106,975
Crude oil throughput (barrels per day)(5)(6)		88,012			93,268			89,918			94,061
Refining margin per barrel(7)							$	10.45		$	14.68
NYMEX 2-1-1 crack spread(8)							$	11.57		$	11.60
Direct operating expenses exclusive of depreciation and amortization per barrel(9)							$	3.06		$	3.79


	Immediate
	Predecessor		Successor		Combined			Successor
	174 Days Ended		141 Days Ended		Nine Months			Nine Months
	June 23,		September 30,		Ended September 30,			Ended September 30,
	2005		2005		2005			2006
					(non-GAAP)
			(unaudited)		(unaudited)			(unaudited)
	(in millions, except as otherwise indicated)
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)(5)		193.2		118.1		311.3			283.9
UAN (tons in thousands)(5)		309.9		185.8		495.7			465.0
On-stream factors(10):
Gasification						98.3	%		91.7	%
Ammonia						96.7	%		87.8	%
UAN						94.8	%		87.9	%


	Original
	Predecessor					Immediate Predecessor						Successor			Combined						Pro Forma
	Year			62 Days		304 Days			174 Days			233 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			2004			2005			2005
															(non-GAAP)
															(unaudited)						(unaudited)
	(in millions, except as otherwise indicated)
Statement of Operations Data:
Net sales	$	1,262.2		$	261.1	$	1,479.9		$	980.7		$	1,454.3		$	1,741.0		$	2,435.0		$	2,435.0
Cost of product sold (exclusive of depreciation and amortization)		1,061.9			221.4		1,244.2			768.0			1,168.1			1,465.6			1,936.1			1,936.2
Direct operating expenses (exclusive of depreciation and amortization)		133.1			23.4		117.0			80.9			85.3			140.4			166.2			166.3
Selling, general and administrative expenses (exclusive of depreciation and amortization)		23.6			4.7		16.3			18.4			18.4			21.0			36.8			36.0
Depreciation and amortization		3.3			0.4		2.4			1.1			24.0			2.8			25.1			47.6
Impairment, losses in joint ventures, and other charges(11)		10.9			—		—			—			—			—			—			—

Operating income	$	29.4		$	11.2	$	100.0		$	112.3		$	158.5		$	111.2		$	270.8		$	248.9
Other income (expense)(1)		(0.5	)		—		(6.9	)		(8.4	)		0.4			(6.9	)		(8.0	)		0.2
Interest (expense)		(1.3	)		—		(10.1	)		(7.8	)		(25.0	)		(10.1	)		(32.8	)		(47.6	)
Gain (loss) on derivatives		0.3			—		0.5			(7.6	)		(316.1	)		0.5			(323.7	)		(323.7	)

Income (loss) before taxes	$	27.9		$	11.2	$	83.5		$	88.5		$	(182.2	)	$	94.7		$	(93.7	)	$	(122.2	)
Income tax (expense) benefit		—			—		(33.8	)		(36.1	)		63.0			(33.8	)		26.9			39.3

Net income (loss)(2)	$	27.9		$	11.2	$	49.7		$	52.4		$	(119.2	)	$	60.9		$	(66.8	)	$	(82.9	)


	Original
	Predecessor						Immediate Predecessor						Successor			Combined						Pro Forma
	Year			62 Days			304 Days			174 Days			233 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			2004			2005			2005
																(non-GAAP)
																(unaudited)						(unaudited)
	(in millions, except as otherwise indicated)
Pro forma earnings per share, basic and diluted
Pro forma weighted average shares, basic and diluted
Segment Financial Data:
Operating income (loss)
Petroleum	$	21.5		$	7.7		$	77.1		$	76.7		$	123.0		$	84.8		$	199.7
Nitrogen fertilizer		7.8			3.5			22.9			35.3			35.7			26.4			71.0
Other		0.1			—			—			0.3			(0.2	)		—			0.1

Operating income (loss)	$	29.4		$	11.2		$	100.0		$	112.3		$	158.5		$	111.2		$	270.8
Depreciation and amortization
Petroleum	$	2.1		$	0.3		$	1.5		$	0.8		$	15.6		$	1.8		$	16.4
Nitrogen fertilizer		1.2			0.1			0.9			0.3			8.4			1.0			8.7
Other		—			—			—			—			—			—			—

Depreciation and amortization	$	3.3		$	0.4		$	2.4		$	1.1		$	24.0		$	2.8		$	25.1
Other Financial Data:
Depreciation and amortization	$	3.3		$	0.4		$	2.4		$	1.1		$	24.0		$	2.8		$	25.1		$	47.6
Net income adjusted for unrealized gain or loss from Cash Flow Swap(3)		27.9			11.2			49.7			52.4			23.6			60.9			76.0			59.9
Cash flows provided by (used in) operating activities(4)		20.3			53.2			89.8			12.7			82.5			n/a			n/a
Cash flows (used in) investing activities		(0.8	)		—			(130.8	)		(12.3	)		(730.3	)		(130.8	)		(742.6	)
Cash flows provided by (used in) financing activities		(19.5	)		(53.2	)		93.6			(52.4	)		712.5			40.4			660.1
Capital expenditures for property, plant and equipment		0.8			—			14.2			12.3			45.2			14.2			57.5
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)(6)		95,701			106,645			102,046			99,171			107,177			102,825			103,362
Crude oil throughput (barrels per day)(5)(6)		85,501			92,596			90,418			88,012			93,908			90,787			91,097
Refining margin per barrel(7)	$	3.89														$	5.62		$	10.50
NYMEX 2-1-1 crack spread(8)	$	5.53														$	7.43		$	11.62
Direct operating expenses exclusive of depreciation and amortization per barrel(9)	$	2.57														$	2.65		$	3.27
Nitrogen Fertilizer Business Production Volume:
Ammonia (tons in thousands)(5)		335.7			56.4			252.8			193.2			220.0			309.2			413.2
UAN (tons in thousands)(5)		510.6			93.4			439.2			309.9			353.4			532.6			663.3
On-stream factors(9):
Gasification		90.1	%														92.4	%		98.1	%
Ammonia		89.6	%														79.9	%		96.7	%
UAN		81.6	%														83.3	%		94.3	%


	Original		Immediate				Successor
	Predecessor		Predecessor		Successor		Actual		As Adjusted
	December 31,		December 31,		December 31,		September 30,		September 30,
	2003		2004		2005		2006		2006
							(unaudited)		(unaudited)
	(in millions)

Balance Sheet Data:
Cash and cash equivalents	$	—	$	52.7	$	64.7	$	38.1
Working capital(12)		150.5		106.6		108.0		173.4
Total assets		199.0		229.2		1,221.5		1,397.7
Liabilities subject to compromise(13)		105.2		—		—		—
Total debt, including current portion		—		148.9		499.4		527.8
Management units subject to redemption		—		—		3.7		9.0
Divisional/members equity		58.2		14.1		115.8		303.1


(1)		During the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005, we recognized a loss of $7.2 million and $8.1 million, respectively, on early extinguishment of debt.


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


	Immediate				Combined		Successor
	Predecessor		Successor		Nine Months		Nine Months
	174 Days Ended		141 Days Ended		Ended		Ended
	June 23,		September 30,		September 30,		September 30,
	2005		2005		2005		2006
			(unaudited)		(non-GAAP)		(unaudited)
	(in millions)
Loss on extinguishment of debt(b)	$	8.1	$	—	$	8.1	$	—
Inventory fair market value adjustment(c)		—		16.9		16.9		—
Funded letter of credit expense and interest rate swap not included in interest expense(d)		—		1.4		1.4		0.2
Major scheduled turnaround expense(e)		—		—		—		4.4
Loss on termination of swap(f)		—		25.0		25.0		—
Unrealized (gain) loss from Cash Flow Swap		—		427.1		427.1		(80.3	)


	Original				Immediate
	Predecessor				Predecessor				Successor		Combined				Pro Forma		Twelve
	Year		62 Days		304 Days		174 Days		233 Days		Year				Year		Months
	Ended		Ended		Ended		Ended		Ended		Ended				Ended		Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,				December 31,		September 30,
	2003		2004		2004		2005		2005		2004		2005		2005		2006
											(non-GAAP)						(non-GAAP)
											(unaudited)				(unaudited)		(unaudited)
	(in millions)
Impairment of property, plant and equipment(a)	$	9.6	$	—	$	—	$	—	$	—	$	—	$	—	$	—	$	—
Loss on extinguishment of debt(b)		—		—		7.2		8.1		—		7.2		8.1		—		—
Inventory fair market value adjustment(c)		—		—		3.0		—		16.6		3.0		16.6		16.6		(0.3	)
Funded letter of credit expense and interest rate swap not included in interest expense(d)		—		—		—		—		2.3		—		2.3		4.3		1.1
Major scheduled turnaround expense(e)		—		—		1.8		—		—		1.8		—		—		4.4
Loss on termination of swap(f)		—		—		—		—		25.0		—		25.0		25.0		—
Unrealized (gain) loss from Cash Flow Swap		—		—		—		—		235.9		—		235.9		235.9		(271.5	)


(a)		During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition.


(b)		Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004 and the write-off of $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005.


(c)		Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory.


(d)		Consists of fees which are expensed to Selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the first lien credit facility and the second lien credit facility.

(e)		Represents expenses associated with a major scheduled turnaround at our nitrogen fertilizer plant.

(f)		Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005.


(3)		Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. Under these agreements, sales representing approximately 70% and 17% of then forecasted refinery output for the periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, have been economically hedged. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. See “Description of Our Indebtedness and the Cash Flow Swap.”


		We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect in each period material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance and believes that this non-GAAP measure is a useful measure for investors in analyzing our business. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.


		Net income adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of performance in evaluating our business. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.


		The following is a reconciliation of Net income adjusted for unrealized gain or loss from Cash Flow Swap to Net income:


	Immediate
	Predecessor		Successor			Combined			Successor
	174 Days Ended		141 Days Ended			Nine Months			Nine Months
	June 23,		September 30,			Ended September 30,			Ended September 30,
	2005		2005			2005			2006
						(non-GAAP)
						(unaudited)
			(unaudited)						(unaudited)
	(in millions)
Net income adjusted for unrealized gain or loss from Cash Flow Swap	$	52.4	$	4.9		$	57.3		$	122.4
Plus:
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit		—		(257.5	)		(257.5	)		48.4

Net income (loss)	$	52.4	$	(252.6	)	$	(200.2	)	$	170.8


																	Pro Forma
	Original Predecessor				Immediate Predecessor				Successor			Combined					Year
	Year		62 Days		304 Days		174 Days		233 Days			Year					Ended
	Ended		Ended		Ended		Ended		Ended			Ended					December
	December 31,		March 2,		December 31,		June 23,		December 31,			December 31,					31,
	2003		2004		2004		2005		2005			2004		2005			2005
												(non-GAAP)
												(unaudited)					(unaudited)
	(in millions)
Net income adjusted for unrealized loss from Cash Flow Swap	$	27.9	$	11.2	$	49.7	$	52.4	$	23.6		$	60.9	$	76.0		$	59.9
Plus:
Unrealized (loss) from Cash Flow Swap, net of tax benefit		—		—		—		—		(142.8	)		—		(142.8	)		(142.8	)

Net income (loss)	$	27.9	$	11.2	$	49.7	$	52.4	$	(119.2	)	$	60.9	$	(66.8	)	$	(82.9	)


(4)		The reporting of cash flows from operating activities is impacted by the Initial Acquisition and the Subsequent Acquisition and the change in the basis of accounting that resulted from both of these transactions. Therefore, management believes it is not meaningful to combine cash flows from operating activities for the periods which include the date of the Initial Acquisition and the Subsequent Acquisition.


(5)		Operational information reflected for the 141-day Successor period ended September 30, 2005 includes only 99 days of operational activity. Operational information reflected for the 233-day Successor period ended December 31, 2005 includes only 191 days of operational activity. Successor was formed on May 13, 2005 but had no financial statement activity during the 42-day period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005 which expired unexercised on June 16, 2005.


(6)		Barrels per day is calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facility’s continuous operations.


(7)		Refining margin is a measurement calculated as the difference between net sales and cost of products sold (exclusive of deprecation and amortization). Each of the components used to calculate refining margin (net sales and cost of products sold exclusive of depreciation and amortization) can be taken directly from our statement of operations. Refining margin per barrel is a measurement calculated by dividing the refining margin by our refinery’s crude oil throughput volumes for the respective periods presented. Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of products that we are able to sell refined products. Our calculations of refining margin and refining margin per barrel may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures.


(8)		This information is industry data and is not derived from our audited financial statements or unaudited interim financial statements.


(9)		Direct operating expenses exclusive of depreciation and amortization per barrel is calculated by dividing direct operating expenses exclusive of depreciation and amortization by crude oil throughput volumes for the respective periods presented.


(10)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.


(11)		During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code.


(12)		Excludes liabilities subject to compromise due to Original Predecessor’s bankruptcy of $105.2 million as of December 31, 2003 in calculating Original Predecessor’s working capital.


(13)		While operating under Chapter 11 of the U.S. Bankruptcy Code, Original Predecessor’s financial statements were prepared in accordance with SOP 90-7 “Financial Reporting by Entities in Reorganization under Bankruptcy Code.” SOP 90-7 requires that pre-petition liabilities be segregated in the Balance Sheet.

About This Prospectus

Certain Definitions

In this prospectus,


	•	Original Predecessor refers to the former Petroleum Division and one facility within the eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division of Farmland which Coffeyville Resources, LLC acquired on March 3, 2004 in a sales process under Chapter 11 of the U.S. Bankruptcy Code;

	•	Initial Acquisition refers to the acquisition of Original Predecessor on March 3, 2004 by Coffeyville Resources, LLC;

	•	Immediate Predecessor refers to Coffeyville Group Holdings, LLC and its subsidiaries, including Coffeyville Resources, LLC;

	•	Subsequent Acquisition refers to the acquisition of Immediate Predecessor on June 24, 2005 by Coffeyville Acquisition LLC; and

	•	Successor refers to Coffeyville Acquisition LLC and its consolidated subsidiaries.

Industry and Market Data

The data included in this prospectus regarding the oil refining industry and the nitrogen fertilizer industry, including trends in the market and our position and the position of our competitors within these industries, are based on our estimates, which have been derived from management’s knowledge and experience in the areas in which the relevant businesses operate, and information obtained from customers, distributors, suppliers, trade and business organizations, internal research, publicly available information, industry publications and surveys and other contacts in the areas in which the relevant businesses operate. We have also cited information compiled by industry publications, governmental agencies and publicly available sources. Although we believe that these sources are generally reliable, we have not independently verified data from these sources or obtained third party verification of this data. Estimates of market size and relative positions in a market are difficult to develop and inherently uncertain. Accordingly, investors should not place undue weight on the industry and market share data presented in this prospectus.

Trademarks, Trade Names and Service Marks

This prospectus includes trademarks owned by us, including COFFEYVILLE RESOURCES^TM. This prospectus also contains trademarks, service marks, copyrights and trade names of other companies.

RISK FACTORS

You should carefully consider each of the following risks and all of the information set forth in this prospectus before deciding to invest in our common stock. If any of the following risks and uncertainties develops into actual events, our business, financial condition or results of operations could be materially adversely affected. In that case, the price of our common stock could decline and you could lose part or all of your investment.

Risks Related to Our Petroleum Business

Volatile margins in the refining industry may cause volatility or a decline in our future results of operations and decrease our cash flow.

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

If we are required to obtain our crude oil supply without the benefit of our credit intermediation agreement, our exposure to the risks associated with volatile crude prices may increase and our liquidity may be reduced.

We currently obtain the majority of our crude oil supply through a crude oil credit intermediation agreement with J. Aron, which minimizes the amount of in transit inventory and mitigates crude pricing risks by ensuring pricing takes place extremely close to the time when the crude is refined and the yielded products are sold. In the event this agreement is terminated or is not renewed prior to expiration we may be unable to obtain similar services from another party at the same or better terms as our existing agreement. The current credit intermediation agreement expires on December 31, 2007. Further, if we were required to obtain our crude oil supply without the benefit of an intermediation agreement, our exposure to crude pricing risks may increase, even despite any hedging activity in which we may engage, and our liquidity would be negatively impacted due to the increased inventory and the negative impact of market volatility.

Disruption of our ability to obtain an adequate supply of crude oil could reduce our liquidity and increase our costs.

Our refinery requires approximately 80,000 bpd of crude oil in addition to the light sweet crude oil we gather locally in Kansas and northern Oklahoma. We obtain a significant amount of our non-gathered crude oil, approximately 20% to 30% on average, from Latin America and South America. If these supplies become unavailable to us, we may need to seek supplies from the Middle East, West Africa, Canada and the North Sea. We are subject to the political, geographic, and economic risks attendant to doing business with suppliers located in those regions. Disruption of production in any of such regions for any reason could have a material impact on other regions and our business. In the event that one or more of our traditional suppliers becomes unavailable to us, we may be unable to obtain an adequate supply of crude oil, or we may only be able to obtain our crude oil supply at

unfavorable prices. As a result, we may experience a reduction in our liquidity and our results of operations could be materially adversely affected.

The key event of 2005 in our industry was the hurricane season which produced a record number of named storms, including hurricanes Katrina and Rita. The location and intensity of these storms caused extreme amounts of damage to both crude and natural gas production as well as extensive disruption to many U.S. Gulf Coast refinery operations although we believe that substantially most of this refining capacity has been restored. These events caused both price spikes in the commodity markets as well as substantial increases in crack spreads. Severe weather, including hurricanes along the U.S. Gulf Coast, could interrupt our supply of crude oil. Supplies of crude oil to our refinery are periodically shipped from U.S. Gulf Coast production or terminal facilities, including through the Seaway Pipeline from the U.S. Gulf Coast to Cushing, Oklahoma. U.S. Gulf Coast facilities could be subject to damage or production interruption from hurricanes or other severe weather in the future which could interrupt or materially adversely affect our crude oil supply. If our supply of crude oil is interrupted, our business, financial condition and results of operations could be materially adversely impacted.

Our profitability is linked to the light/heavy and sweet/sour crude oil price spreads. In 2005 and 2006 the light/heavy crude oil price spread increased significantly. A decrease in either of the spreads would negatively impact our profitability.

Our profitability is linked to the price spreads between light and heavy crude oil and sweet and sour crude oil within our plant capabilities. We prefer to refine heavier sour crude oils because they have historically provided wider refining margins than light sweet crude. Accordingly, any tightening of the light/heavy or sweet/sour spreads could reduce our profitability. During 2005 and 2006, relatively high demand for lighter sweet crude due to increasing demand for more highly refined fuels resulted in an attractive light/heavy crude oil price spread and an improved sweet/sour spread compared to 2004. Countries with less complex refining capacity than the United States and Europe continue to require large volumes of light sweet crude in order to meet their demand for transportation fuels. Crude oil prices may not remain at current levels and the light/heavy or sweet/sour spread may decline, which could result in a decline in profitability or operating losses.

Our refinery faces operating hazards and interruptions, including unscheduled maintenance or downtime. The limits on insurance coverage could expose us to potentially significant liability costs to the extent these hazards or interruptions are not fully covered. Insurance companies that currently insure companies in the energy industry may cease to do so or may substantially increase premiums.

Our operations, located primarily in a single location, are subject to significant operating hazards and interruptions. If our refinery experiences a major accident or fire, is damaged by severe weather or other natural disaster, or is otherwise forced to curtail its operations or shut down, we could incur significant losses which could have a material adverse impact on our financial results. In addition, a major accident, fire or other event could damage our refinery or the environment or result in injuries or loss of life. If our refinery experiences a major accident or fire or other event or an interruption in supply or operations, our business could be materially adversely affected if the damage or liability exceeds the amounts of business interruption, property, terrorism and other insurance that we maintain against these risks. As required under our existing credit facilities, we maintain property insurance capped at $1.25 billion which is subject to annual renewal. In the event of a business interruption we would not be entitled to recover our losses until the interruption exceeds 45 days in the aggregate. We are fully exposed to losses in excess of this cap or that occur in the 45 days of our deductible period. These losses may be material.

The energy industry is highly capital intensive, and the entire or partial loss of individual facilities can result in significant costs to both industry participants, such as us, and their insurance carriers. In recent years, several large energy industry claims have resulted in significant increases in the level of

premium costs and deductible periods for participants in the energy industry. For example, during 2005, hurricanes Katrina and Rita caused significant damage to several petroleum refineries along the U.S. Gulf Coast, in addition to numerous oil and gas production facilities and pipelines in that region. As a result of large energy industry claims, insurance companies that have historically participated in underwriting energy-related facilities may discontinue that practice, or demand significantly higher premiums or deductibles to cover these facilities. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at reasonable cost or we may need to significantly increase our retained exposures.

Our refinery consists of a number of processing units, many of which have been in operation for a number of years. One or more of the units may require unscheduled down time for unanticipated maintenance or repairs on a more frequent basis than our scheduled turnaround of every one to five years for each unit, or our planned turnarounds may last longer than anticipated. Scheduled and unscheduled maintenance could reduce our net income during the period of time that any of our units is not operating. For example, we have a scheduled turnaround expected to occur in the first quarter of 2007. This turnaround is expected to last 40-45 days and will include incremental time to complete the expansion projects explained throughout this prospectus. This turnaround will have a significant adverse impact on our first quarter results.

If our access to the pipelines on which we rely for the supply of our feedstock and the distribution of our products is interrupted, our inventory and costs may increase and we may be unable to efficiently distribute our products.

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

Our petroleum business’ financial results are seasonal and generally lower in the first and fourth quarters of the year, which may cause volatility in the price of our common stock.

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

We face significant competition, both within and outside of our industry. Competitors who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us.

The refining industry is highly competitive with respect to both feedstock supply and refined product markets. We may be unable to compete effectively with our competitors within and outside of our industry, which could result in reduced profitability. We compete with numerous other companies for available supplies of crude oil and other feedstocks and for outlets for our refined products. We are not engaged in the petroleum exploration and production business and therefore we do not produce any of our crude oil feedstocks. We do not have a retail business and therefore are dependent upon

others for outlets for our refined products. We do not have any long-term arrangements for much of our output. Many of our competitors in the United States as a whole, and one of our regional competitors, obtain significant portions of their feedstocks from company-owned production and have extensive retail outlets. Competitors that have their own production or extensive retail outlets with brand-name recognition are at times able to offset losses from refining operations with profits from producing or retailing operations, and may be better positioned to withstand periods of depressed refining margins or feedstock shortages. A number of our competitors also have materially greater financial and other resources than us, providing them the ability to add incremental capacity in environments of high crack spreads. These competitors have a greater ability to bear the economic risks inherent in all phases of the refining industry. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in refining industry economics and may add additional competitive pressure on us. In addition, we compete with other industries that provide alternative means to satisfy the energy and fuel requirements of our industrial, commercial and individual consumers. The more successful these alternatives become as a result of governmental regulations, technological advances, consumer demand, improved pricing or otherwise, the greater the impact on pricing and demand for our products and our profitability. There are presently significant governmental and consumer pressures to increase the use of alternative fuels in the United States.

Environmental laws and regulations will require us to make substantial capital expenditures in the future.

Current or future federal, state and local environmental laws and regulations could cause us to expend substantial amounts to install controls or make operational changes to comply with environmental requirements. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit our ability to market and sell our products to end users. Any such future environmental laws or governmental regulations could have a material impact on the results of our operations.

In March 2004, we entered into a Consent Decree with the United States Environmental Protection Agency, or the EPA, and the Kansas Department of Health and Environment, or the KDHE, to address certain allegations of Clean Air Act violations by Farmland at the Coffeyville oil refinery in order to reduce environmental risks and liabilities going forward. Pursuant to the Consent Decree, in the short-term, we have increased the use of catalyst additives to the fluid catalytic cracking unit at the facility to reduce emissions of sulfur dioxide, or SO₂. We will begin adding catalyst to reduce oxides of nitrogen, or NOx, in 2007. A catalyst is a substance that alters, accelerates or instigates chemical changes, but is neither produced, consumed nor altered in the process. In the long term, we will install controls to minimize both SO₂ and NOx emissions, which under terms of the Consent Decree require that final controls be in place by January 1, 2011. In addition, pursuant to the Consent Decree, we assumed certain cleanup obligations at our Coffeyville refinery and Phillipsburg terminal, and we agreed to retrofit some heaters at the refinery with Ultra Low NOx burners. All heater retrofits have been performed and we are currently verifying that the heaters meet the Ultra Low NOx standards required by the Consent Decree. The Ultra Low NOx heater technology is in widespread use throughout the industry. There are other permitting, monitoring, recordkeeping and reporting requirements associated with the Consent Decree, and we are required to provide periodic reports on our compliance with the terms and conditions of the Consent Decree. The overall costs of complying with the Consent Decree over the next four years are expected to be approximately $31 million. To date, we have met all deadlines and requirements of the Consent Decree and we have not had to pay any stipulated penalties, which are required to be paid for failure to comply with various terms and conditions of the Consent Decree. Availability of equipment and technology performance, as well as EPA interpretations of provisions of the Consent Decree that differ from ours, could have a material adverse effect on our ability to meet the requirements imposed by the Consent Decree.

We will make capital expenditures over the next several years in order to comply with regulations under the Clean Air Act establishing stringent low sulfur content specifications for our petroleum

products, including the Tier II gasoline standards, as well as regulations with respect to on- and off-road diesel fuel, which are designed to reduce air emissions from the use of these products. In February 2004, the EPA granted us a “hardship waiver,” which will require us to meet final low sulfur Tier II gasoline standards by January 1, 2011. Based on our preliminary estimates, we believe that compliance with the Tier II gasoline standards and on-road diesel standards will require us to spend approximately $98 million during 2006 (most of which has already been spent), approximately $18 million in 2007 and approximately $25 million between 2008 and 2010. Changes in these laws or interpretations thereof could result in significantly greater expenditures.

Changes in our credit profile may affect our relationship with our suppliers, which could have a material adverse effect on our liquidity.

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

We may have additional capital needs for which our internally generated cash flows and other sources of liquidity may not be adequate.

If we cannot generate cash flow or otherwise secure sufficient liquidity to support our short-term and long-term capital requirements, we may be unable to comply with certain environmental standards or pursue our business strategies, in which case our operations may not perform as well as we currently expect. We have substantial short-term and long-term capital needs, including capital expenditures we are required to make to comply with Tier II gasoline standards, on-road diesel regulations, off-road diesel regulations and the Consent Decree. Our short-term working capital needs are primarily crude oil purchase requirements, which fluctuate with the pricing and sourcing of crude oil. We also have significant long-term needs for cash. We currently estimate that mandatory capital and turnaround expenditures, excluding the non-recurring capital expenditures required to comply with Tier II gasoline standards, on-road diesel regulations, off-road diesel regulations and the Consent Decree described above, to average approximately $43 million per year over the next five years.

Risks Related to Our Nitrogen Fertilizer Business

Our nitrogen fertilizer plant has high fixed costs. If natural gas prices fall below a certain level, our nitrogen fertilizer business may not generate sufficient revenue to operate profitably or cover its costs.

Our nitrogen fertilizer plant has high fixed costs as discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Factors Affecting Results — Nitrogen Fertilizer Business.” As a result, downtime or low productivity due to reduced demand, weather interruptions, equipment failures, low prices for our products or other causes can result in significant operating losses. Unlike our competitors, whose primary costs are related to the purchase of natural gas and whose fixed costs are minimal, we have high fixed costs not dependent on the price of natural gas. A decline in natural gas prices generally has the effect of reducing the base sale price for our products while our costs remain substantially the same. Any decline in the price of our fertilizer products could have a material negative impact on our profitability and results of operations.

Our nitrogen fertilizer business is cyclical, which exposes us to potentially significant fluctuations in our financial condition and results of operations, which could result in volatility in the price of our common stock.

A significant portion of our nitrogen fertilizer product sales consists of sales of agricultural commodity products, exposing us to fluctuations in supply and demand in the agricultural industry. These fluctuations historically have had and could in the future have significant effects on prices

across all of our nitrogen fertilizer products and, in turn, our nitrogen fertilizer business’ results of operations and financial condition, which could result in significant volatility in the price of our common stock. The prices of nitrogen fertilizer products depend on a number of factors, including general economic conditions, cyclical trends in end-user markets, supply and demand imbalances, and weather conditions, which have a greater relevance because of the seasonal nature of fertilizer application. Changes in supply result from capacity additions or reductions and from changes in inventory levels. Demand for fertilizer products is dependent, in part, on demand for crop nutrients by the global agricultural industry. Periods of high demand, high capacity utilization, and increasing operating margins have tended to result in new plant investment and increased production until supply exceeds demand, followed by periods of declining prices and declining capacity utilization until the cycle is repeated.

Our fertilizer products are global commodities, and we face intense competition from other nitrogen fertilizer producers.

We are subject to intense price competition in our fertilizer business from both U.S. and foreign sources, including competitors operating in the Persian Gulf, Asia-Pacific, the Caribbean and the former Soviet Union. Fertilizers are global commodities, with little or no product differentiation, and customers make their purchasing decisions principally on the basis of delivered price and availability of the product. We compete with a number of U.S. producers and producers in other countries, including state-owned and government-subsidized entities. The United States and the European Commission each have trade regulatory measures in effect which are designed to address this type of unfair trade. Changes in these measures could have an adverse impact on our sales and profitability of the particular products involved. Some of our competitors have greater total resources and are less dependent on earnings from fertilizer sales, which makes them less vulnerable to industry downturns and better positioned to pursue new expansion and development opportunities. In addition, recent consolidation in the fertilizer industry has increased the resources of several of our competitors. In light of this industry consolidation, our competitive position could suffer to the extent we are not able to expand our own resources either through investments in new or existing operations or through acquisitions, joint ventures or partnerships. Our inability to compete successfully could result in the loss of customers, which could adversely affect our sales and profitability.

Adverse weather conditions during peak fertilizer application periods may have a negative effect upon our results of operations and financial condition, as our agricultural customers are geographically concentrated.

Sales of our fertilizer products to agricultural customers are concentrated in the Great Plains and Midwest states and are seasonal in nature. For example, our nitrogen fertilizer business generates greater net sales and operating income in the spring. Accordingly, an adverse weather pattern affecting agriculture in these regions or during this season could have a negative effect on fertilizer demand, which could, in turn, result in a decline in our net sales, lower margins and otherwise negatively affect our financial condition and results of operations. Our quarterly results may vary significantly from one year to the next due primarily to weather-related shifts in planting schedules and purchase patterns, as well as the relationship between natural gas and nitrogen fertilizer product prices.

Our margins and results of operations may be adversely affected by the supply and price levels of pet coke and other essential raw materials.

Pet coke is a key raw material used in the manufacture of our nitrogen fertilizer products. Increases in the price of pet coke could result in a decrease in our profit margins or results of operations. Our profitability is directly affected by the price and availability of pet coke obtained from our oil refinery and purchased from third parties. We obtain the majority of the pet coke we need from our adjacent oil refinery, and procure the remainder on the open market. We are therefore sensitive to

fluctuations in the price of pet coke on the open market. Pet coke prices could significantly increase in the future. In addition, the BOC air separation plant that provides oxygen, nitrogen, and compressed dry air to our nitrogen fertilizer plant’s gasifier has experienced numerous short-term interruptions (one to five minute), thereby causing interruptions in our gasifier operations. Our operations require a reliable supply of raw materials. A disruption of our reliable supply could prevent us from producing our products at current levels and our reputation, customer relationships and results of operations may be materially harmed.

We may not be able to maintain an adequate supply of pet coke and other essential raw materials. In addition, we could experience production delays or cost increases if alternative sources of supply prove to be more expensive or difficult to obtain. If our raw material costs were to increase, or if we were to experience an extended interruption in the supply of raw materials, including pet coke, to our production facilities, we could lose sale opportunities, damage our relationships with or lose customers, suffer lower margins, and experience other negative effects to our business, results of operations and financial condition. In addition, if natural gas prices in the United States were to decline to a level that prompts those U.S. producers who have permanently or temporarily closed production facilities to resume fertilizer production, this would likely contribute to a global supply/demand imbalance that could negatively affect our margins, results of operations and financial condition.

Ammonia can be very volatile. If we are held liable for accidents involving ammonia that cause severe damage to property and/or injury to the environment and human health, our financial condition and the price of our common stock could decline. In addition, the costs of transporting ammonia could increase significantly in the future.

We manufacture, process, store, handle, distribute and transport ammonia, which is very volatile. Accidents, releases or mishandling involving ammonia could cause severe damage or injury to property, the environment and human health, as well as a possible disruption of supplies and markets. Such an event could result in civil lawsuits and regulatory enforcement proceedings, both of which could lead to significant liabilities. Any damage to persons, equipment or property or other disruption of our ability to produce or distribute our products could result in a significant decrease in operating revenues and significant additional cost to replace or repair and insure our assets, which could negatively affect our operating results and financial condition. In addition, we may incur significant losses or costs relating to the operation of railcars used for the purpose of carrying various products, including ammonia. Due to the dangerous and potentially toxic nature of the cargo, in particular ammonia on board railcars, a railcar accident may result in uncontrolled or catastrophic circumstances, including fires, explosions, and pollution. These circumstances may result in severe damage and/or injury to property, the environment and human health. In the event of pollution, we may be strictly liable. If we are strictly liable, we could be held responsible even if we are not at fault and we complied with the laws and regulations in effect at the time. Litigation arising from accidents involving ammonia may result in our being named as a defendant in lawsuits asserting claims for large amounts of damages, which could have a material adverse effect on our financial condition and the price of our common stock.

Given the risks inherent in transporting ammonia, the costs of transporting ammonia could increase significantly in the future. Ammonia is most typically transported by railcar. A number of initiatives are underway in the railroad and chemicals industries which may result in changes to railcar design in order to minimize railway accidents involving hazardous materials. If any such design changes are implemented, or if accidents involving hazardous freight increases the insurance and other costs of railcars, our freight costs could significantly increase.

Prior to our acquisition of the nitrogen fertilizer plant in 2004 and continuing into our ownership, the facility experienced equipment malfunctions, resulting in air releases of ammonia into the environment. The malfunctioning critical equipment has since been replaced. We have reported the excess emissions of ammonia to the EPA and the KDHE as part of an air permitting audit of the

facility. Additional equipment or repairs may be required and any significant government enforcement or third-party claims could result from the excess ammonia emissions.

Environmental laws and regulations could require us to make substantial capital expenditures in the future.

We manufacture, process, store, handle, distribute and transport fertilizer products, including ammonia, that are subject to federal, state and local environmental laws and regulations. Presently existing or future environmental laws and regulations could cause us to expend substantial amounts to install controls or make operational changes to comply with changes in environmental requirements. In addition, future environmental laws and regulations, or new interpretations of existing laws or regulations, could limit our ability to market and sell our products to end users. Any such future environmental laws or governmental regulations may have a significant impact on our results of operations.

Our nitrogen fertilizer operations are dependent on a few third-party suppliers. Failure by key third-party suppliers of oxygen, nitrogen and electricity to perform in accordance with their contractual obligations may have a negative effect upon our results of operations and financial condition.

Our operations depend in large part on the performance of third-party suppliers, including The BOC Group, for the supply of oxygen and nitrogen, and the City of Coffeyville for the supply of electricity. The contract with The BOC Group extends through 2020 and the electricity contract extends through 2019. Should either of those two suppliers fail to perform in accordance with the existing contractual arrangements, our gasification operation would be forced to a halt. Alternative sources of supply of oxygen, nitrogen or electricity could be difficult to obtain. Any shutdown of our operations could have a material negative effect upon our results of operations and financial condition.

Risks Related to Our Entire Business

Our operations involve environmental risks that may require us to make substantial capital expenditures to remain in compliance or to remediate current or future contamination that could give rise to material liabilities.

Our results of operations may be affected by increased costs resulting from compliance with the extensive federal, state and local environmental laws and regulations to which our facilities are subject and from contamination of our facilities as a result of accidental spills, discharges or other historical releases of petroleum or hazardous substances.

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

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

for environmental compliance could have a material adverse effect on our financial condition and results of operations.

Our business is inherently subject to accidental spills, discharges or other releases of petroleum or hazardous substances into the environment. Past or future spills related to any of our operations, including our refinery, pipelines, product terminals, fertilizer plant or transportation of products or hazardous substances from those facilities, may give rise to liability (including strict liability, or liability without fault, and potential cleanup responsibility) to governmental entities or private parties under federal, state or local environmental laws, as well as under common law. For example, we could be held strictly liable under the Comprehensive Environmental Responsibility, Compensation and Liability Act, or CERCLA, for past or future spills without regard to fault or whether our actions were in compliance with the law at the time of the spills. Pursuant to CERCLA and similar state statutes, we could be held liable for contamination associated with facilities we currently own or operate, facilities we formerly owned or operated and facilities to which we transported or arranged for the transportation of wastes or by-products containing hazardous substances for treatment, storage, or disposal. The potential penalties and clean-up costs for past or future releases or spills, liability to third parties for damage to their property or exposure to hazardous substances, or the need to address newly discovered information or conditions that may require response actions could be significant and could have a material adverse effect on our business, financial condition and results of operations.

Two of our facilities, including our Coffeyville oil refinery and the Phillipsburg terminal (which operated as a refinery until 1991), have environmental contamination. We have assumed Farmland’s responsibilities under certain Resource Conservation and Recovery Act, or RCRA, corrective action orders related to contamination at or that originated from the Coffeyville refinery (which includes portions of the fertilizer plant) and the Phillipsburg terminal. If significant unforeseen liabilities that have been undetected to date by our extensive soil and groundwater investigation and sampling programs arise in the areas where we have assumed liability for the corrective action, that liability could have a material adverse effect on our results of operations and financial condition and may not be covered by insurance.

In addition, we may face liability for alleged personal injury or property damage due to exposure to chemicals or other hazardous substances located at or released from our facilities. We may also face liability for personal injury, property damage, natural resource damage or for cleanup costs for the alleged migration of contamination or other hazardous substances from our facilities to adjacent and other nearby properties.

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

We have a limited operating history as a stand-alone company.

Our limited historical financial performance as a stand-alone company makes it difficult for you to evaluate our business and results of operations to date and to assess our future prospects and viability. Our brief operating history has resulted in strong period-over-period revenue and profitability growth rates that may not continue in the future. We have been operating during a recent period of significant growth in the profitability of the refined products industry which may not continue or could reverse. As a result, our results of operations may be lower than we currently expect and the price of our common stock may be volatile.

Our commodity derivative activities could result in losses and may result in period-to-period earnings volatility.

The nature of our operations results in exposure to fluctuations in commodity prices. If we do not effectively manage our derivative activities, we could incur significant losses. We monitor our exposure and, when appropriate, utilize derivative financial instruments and physical delivery contracts to mitigate the potential impact from changes in commodity prices. If commodity prices change from levels specified in our various derivative agreements, a fixed price contract or an option price structure could limit us from receiving the full benefit of commodity price changes. In addition, by entering into these derivative activities, we may suffer financial loss if we do not produce oil to fulfill our obligations. In the event we are required to pay a margin call on a derivative contract, we may be unable to benefit fully from an increase in the value of the commodities we sell. In addition, we may be required to make a margin payment before we are able to realize a gain on a sale resulting in a reduction in cash flow, particularly if prices decline by the time we are able to sell.

In June 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap, which is not subject to margin calls, in the form of three swap agreements for the period from July 1, 2005 to June 30, 2010 with J. Aron in connection with the Subsequent Acquisition. These agreements were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. Pursuant to the Cash Flow Swap, sales representing approximately 70% and 17% of then forecasted refinery output for the periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, have been economically hedged. In addition, under the terms of the existing credit facilities, management has limited discretion to change the amount of hedged volumes under the Cash Flow Swap therefore affecting our exposure to market volatility. Because this derivative is based on NYMEX prices while our revenue is based on prices in the Coffeyville supply area, the contracts cannot completely eliminate all risk of price volatility. If the price of products on NYMEX is different from the value contracted in the swap, then we will receive from or owe to the counterparty the difference on each unit of product that is contracted in the swap. In addition, as a result of the accounting treatment of these contracts, unrealized gains and losses are charged to our earnings based on the increase or decrease in the market value of the unsettled position and the inclusion of such derivative gains or losses in earnings may produce significant period-to-period earnings volatility that is not necessarily reflective of our underlying operating performance. The positions under the Cash Flow Swap resulted in unrealized gains of $80.3 million for the nine months ended September 30, 2006. As of September 30, 2006, a $1.00 change in quoted prices for the crack spreads utilized in the Cash Flow Swap would result in a $71.2 million change to the fair value of derivative commodity position and the same change to net income. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Flow Swap.”

We depend on our significant customers, and the loss of one or several of our significant customers may have a material adverse impact on our results of operations and financial condition.

We have a high concentration of customers in both our petroleum and nitrogen fertilizer businesses. Our four largest customers in the petroleum business represented 58.7% and 45.6% of our petroleum sales for the year ended December 31, 2005 and the nine months ended September 30, 2006, respectively. Further, in the aggregate our top five ammonia customers represented 55.2% and 49.6% of our ammonia sales for the year ended December 31, 2005 and the nine months ended September 30, 2006, respectively, and our top five UAN customers represented 43.1% and 30.0% of our UAN sales, respectively for the same periods. Several of our significant petroleum, ammonia and UAN customers each account for more than 10% of sales of petroleum, ammonia and UAN, respectively. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of our customers. The loss of one or several of our significant customers, or a significant reduction in purchase volume by any of them, could have a material adverse effect on our results of operations and financial condition.

We may not be able to successfully implement our business strategies, which include completion of significant capital programs.

One of our business strategies is to implement a number of capital expenditure projects designed to increase productivity and profitability of our facilities. Many factors may prevent or hinder our implementation of some or all of these projects, including compliance with or liability under environmental regulations, a downturn in refining margins, technical or mechanical problems, lack of availability of capital and other factors. Costs and delays have increased significantly during the past two years and the large number of capital projects underway in the industry has led to shortages in skilled craftsmen, engineering services and equipment manufacturing. Our capital projects were designed during periods of strong profitability for refiners which may not continue at the time these projects are undertaken. Failure to successfully implement our profit-enhancing strategy may materially adversely affect our business prospects and competitive position in the industry.

We are scheduled to execute a major turnaround and expansion beginning in the first quarter of 2007. Major equipment is scheduled to be delivered before the turnaround commences. These projects could be significantly delayed if equipment is not delivered on time or if adequate labor is not available. We may incur additional costs and these projects could run significantly over budget given escalation of labor and equipment costs recently experienced across the refining industry.

We are a holding company and depend upon our subsidiaries for our cash flow.

We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. Consequently, our cash flow and our ability to meet our obligations or to pay dividends or make other distributions in the future will depend upon the cash flow of our subsidiaries and the payment of funds by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. In addition, Coffeyville Resources, LLC, our indirect subsidiary and the primary obligor under our existing credit facilities, is a holding company and its ability to meet its debt service obligations depends on the cash flow of its subsidiaries. The ability of our subsidiaries to make any payments to us will depend on their earnings, the terms of their indebtedness, including the terms of our First Lien Credit Facility and Second Lien Credit Facility, tax considerations and legal restrictions.

Our significant indebtedness may affect our ability to operate our business, and may have a material adverse effect on our financial condition and results of operation.

As of September 30, 2006, we had total debt of $527.8 million and availability of $93.6 million under our revolving credit facility. We and our subsidiaries may be able to incur significant additional indebtedness in the future. If new indebtedness is added to our current indebtedness, the risks described below could increase. Our high level of indebtedness could have important consequences, such as:


	•	limiting our ability to obtain additional financing to fund our working capital, acquisitions, expenditures, debt service requirements or for other purposes;

	•	limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt;

	•	limiting our ability to compete with other companies who are not as highly leveraged;

	•	placing restrictive financial and operating covenants in the agreements governing our and our subsidiaries’ long-term indebtedness and bank loans, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us;

	•	exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries’ debt instruments that could have a material adverse effect on our business, financial condition and operating results;

	•	increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and


	•	limiting our ability to react to changing market conditions in our industry and in our customers’ industries.

In addition, borrowings under our First Lien Credit Facility and Second Lien Credit Facility bear interest at variable rates. If market interest rates increase, such variable-rate debt will create higher debt service requirements, which could adversely affect our cash flow. Our interest expense for the year ended December 31, 2005 was $47.6 million on a pro forma basis. Each 1.0% increase or decrease in the applicable interest rates under our First Lien Credit Facility and Second Lien Credit Facility would correspondingly change our interest expense by approximately $5.0 million per year.

In addition to our debt service obligations, our operations require substantial investments on a continuing basis. Our ability to make scheduled debt payments, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors. In addition, we are and will be subject to covenants contained in agreements governing our present and future indebtedness. These covenants include and will likely include restrictions on certain payments, the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under our First Lien Credit Facility and Second Lien Credit Facility. Upon a default, unless waived, the lenders under our First Lien Credit Facility and Second Lien Credit Facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our or our subsidiaries’ assets, and force us and our subsidiaries into bankruptcy or liquidation. In addition, any defaults under the First Lien Credit Facility and Second Lien Credit Facility or any other debt could trigger cross defaults under other or future credit agreements. Our operating results may not be sufficient to service our indebtedness or to fund our other expenditures and we may not be able to obtain financing to meet these requirements.

If we lose any of our key personnel, we may be unable to effectively manage our business or continue our growth.

Our future performance depends to a significant degree upon the continued contributions of our senior management team and key technical personnel. The loss or unavailability to us of any member of our senior management team or a key technical employee could negatively affect our ability to operate our business and pursue our strategy. We face competition for these professionals from our competitors, our customers and other companies operating in our industry. To the extent that the services of members of our senior management team and key technical personnel would be unavailable to us for any reason, we would be required to hire other personnel to manage and operate our company and to develop our products and strategy. We may not be able to locate or employ such qualified personnel on acceptable terms or at all.

A substantial portion of our workforce is unionized and we are subject to the risk of labor disputes and adverse employee relations, which may disrupt our business and increase our costs.

As of September 30, 2006, approximately 39% of our employees were represented by labor unions under collective bargaining agreements expiring in 2009. We may not be able to renegotiate our collective bargaining agreements when they expire on satisfactory terms or at all. A failure to do so may increase our costs. In addition, our existing labor agreements may not prevent a strike or work stoppage at any of our facilities in the future, and any work stoppage could negatively affect our results of operations and financial condition.

The requirements of being a public company, including compliance with the reporting requirements of the Exchange Act and the requirements of the Sarbanes-Oxley Act, may strain our resources, increase our costs and distract management, and we may be unable to comply with these requirements in a timely or cost-effective manner.

As a public company, we will be subject to the reporting requirements of the Securities Exchange Act of 1934, or the Exchange Act, and the corporate governance standards of the Sarbanes-Oxley Act of 2002, or Sarbanes-Oxley Act. These requirements may place a strain on our management, systems and resources. The Exchange Act will require that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act will require that we maintain effective disclosure controls and procedures and internal controls over financial reporting. Due to our limited operating history as a stand-alone company, our disclosure controls and procedures and internal controls may not meet all of the standards applicable to public companies. In order to maintain and improve the effectiveness of our disclosure controls and procedures and internal control over financial reporting, significant resources and management oversight will be required. This may divert management’s attention from other business concerns, which could have a material adverse effect on our business, financial condition, results of operations and the price of our common stock.

We will be exposed to risks relating to evaluations of controls required by Section 404 of the Sarbanes-Oxley Act.

We are in the process of evaluating our internal controls systems to allow management to report on, and our independent auditors to audit, our internal controls over financial reporting. We will be performing the system and process evaluation and testing (and any necessary remediation) required to comply with the management certification and auditor attestation requirements of Section 404 of the Sarbanes-Oxley Act, and may be required to comply with Section 404 as early as December 31, 2008. Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable U.S. Securities and Exchange Commission, or SEC, and Public Company Accounting Oversight Board rules and regulations that remain unremediated. As a public company, we will be required to report, among other things, control deficiencies that constitute a “material weakness” or changes in internal controls that, or that are reasonably likely to, materially affect internal controls over financial reporting. A “material weakness” is a significant deficiency or combination of significant deficiencies that results in more than a remote likelihood that a material misstatement of the annual or interim financial statements will not be prevented or detected.

If we fail to implement the requirements of Section 404 in a timely manner, we might be subject to sanctions or investigation by regulatory authorities such as the SEC or the PCAOB. If we do not implement improvements to our disclosure controls and procedures or to our internal controls in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal controls over financial reporting pursuant to an audit of our internal controls over financial reporting. This may subject us to adverse regulatory consequences or a loss of confidence in the reliability of our financial statements. We could also suffer a loss of confidence in the reliability of our financial statements if our independent registered public accounting firm reports a material weakness in our internal controls, if we do not develop and maintain effective controls and procedures or if we are otherwise unable to deliver timely and reliable financial information. Any loss of confidence in the reliability of our financial statements or other negative reaction to our failure to develop timely or adequate disclosure controls and procedures or internal controls could result in a decline in the price of our common stock. In addition, if we fail to remedy any material weakness, our financial statements may be inaccurate, we may face restricted access to the capital markets and our stock price may be adversely affected.

We are a “controlled company” within the meaning of the rules and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements.

A company of which more than 50% of the voting power is held by an individual, a group or another company is a “controlled company” within the meaning of the rules and may elect not to comply with certain corporate governance requirements of the , including:


	•	the requirement that a majority of our board of directors consist of independent directors;

	•	the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

	•	the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

Following this offering, we may utilize some or all of these exemptions. Accordingly, you may not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the .

New regulations concerning the transportation of hazardous chemicals, risks of terrorism, the security of chemical manufacturing facilities and increased insurance costs could result in higher operating costs.

The costs of complying with regulations relating to the transportation of hazardous chemicals and security associated with our refining and nitrogen fertilizer facilities may have a negative impact on our operating results and may cause the price of our common stock to decline. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Simultaneously, local, state and federal governments have begun a regulatory process that could lead to new regulations impacting the security of refinery and chemical plant locations and the transportation of petroleum and hazardous chemicals. Our business or our customers’ businesses could be materially adversely affected because of the cost of complying with new regulations.

If we are not able to successfully defend against third-party claims of intellectual property infringement, our business may be adversely affected.

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

If we are not able to continue to license the technology used in our operations, our business may be adversely affected.

We have licensed, and may license in the future, a combination of patent, trade secret and other intellectual property rights of third parties for use in our business. If any of our license agreements were to be terminated, we may not be able to obtain licenses to alternative technology adequate to substitute for technology we no longer license, or we may only be able to obtain licenses for such alternative technology on terms that are not commercially reasonable or acceptable to us. In addition, any substitution of new technology for currently-licensed technology may require us to make substantial changes to our manufacturing processes or equipment or to our products, and may have a material adverse effect on our business, profitability or growth prospects.

Risks Related to this Offering

There is no existing market for our common stock, and we do not know if one will develop to provide you with adequate liquidity. If our stock price fluctuates after this offering, you could lose a significant part of your investment.

Prior to this offering, there has not been a public market for our common stock. If an active trading market does not develop, you may have difficulty selling any of our common stock that you buy. The initial public offering price for the shares will be determined by negotiations between us, the selling stockholder and the underwriters and may not be indicative of prices that will prevail in the open market following this offering. Consequently, you may not be able to sell shares of our common stock at prices equal to or greater than the price paid by you in this offering. The market price of our common stock may be influenced by many factors including:


	•	the failure of securities analysts to cover our common stock after this offering or changes in financial estimates by analysts;

	•	announcements by us or our competitors of significant contracts or acquisitions;

	•	variations in quarterly results of operations;

	•	loss of a large customer or supplier;

	•	general economic conditions;

	•	terrorist acts;

	•	future sales of our common stock; and

	•	investor perceptions of us and the industries in which our products are used.

As a result of these factors, investors in our common stock may not be able to resell their shares at or above the initial offering price. In addition, the stock market in general has experienced extreme price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of companies like us. These broad market and industry factors may materially reduce the market price of our common stock, regardless of our operating performance.

Following the completion of this offering, the Goldman Sachs Funds and the Kelso Funds will continue to control us and may have conflicts of interest with other stockholders. Conflicts of interest may arise because our principal stockholders or their affiliates have continuing agreements and business relationships with us.

Upon completion of this offering, the Goldman Sachs Funds and the Kelso Funds will control % of our outstanding common stock, or % if the underwriters exercise their option in full, through their controlling interest in Coffeyville Acquisition LLC, which will own shares of our common stock. As a result, the Goldman Sachs Funds and the Kelso Funds will continue to be able to control the election of our directors, determine our corporate and management policies and determine, without the consent of our other stockholders, the outcome of any corporate transaction or other matter submitted to our stockholders for approval, including potential mergers or acquisitions, asset

sales and other significant corporate transactions. The Goldman Sachs Funds and the Kelso Funds will also have sufficient voting power to amend our organization documents.

Conflicts of interest may arise between our principal stockholders and us. Affiliates of some of our principal stockholders engage in transactions with our company. We obtain the majority of our crude oil supply through a crude oil credit intermediation agreement with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and an affiliate of the Goldman Sachs Funds, and Coffeyville Resources, LLC currently has outstanding commodity derivative contracts (swap agreements) with J. Aron for the period from July 1, 2005 to June 30, 2010. See “Certain Relationships and Related Party Transactions.” Further, the Goldman Sachs Funds and the Kelso Funds are in the business of making investments in companies and may, from time to time, acquire and hold interests in businesses that compete directly or indirectly with us and they may either directly, or through affiliates, also maintain business relationships with companies that may directly compete with us. In general, the Goldman Sachs Funds and the Kelso Funds or their affiliates could pursue business interests or exercise their voting power as stockholders in ways that are detrimental to us, but beneficial to themselves or to other companies in which they invest or with whom they have a material relationship. Conflicts of interest could also arise with respect to business opportunities that could be advantageous to the Goldman Sachs Funds and the Kelso Funds and they may pursue acquisition opportunities that may be complementary to our business, and as a result, those acquisition opportunities may not be available to us.

Since June 24, 2005, there have been no equity distributions to the Goldman Sachs Funds, the Kelso Funds or any of their affiliates. However, the Goldman Sachs Funds and the Kelso Funds have received and continue to receive advisory and other fees pursuant to separate consulting and advisory agreements between Coffeyville Acquisition LLC and each of Goldman, Sachs & Co. and Kelso & Company, L.P. See “Certain Relationships and Related Party Transactions.”

As a result of these relationships, the interests of the Goldman Sachs Funds and the Kelso Funds may not coincide with the interests of our company or other holders of our common stock. So long as the Goldman Sachs Funds and the Kelso Funds continue to control a significant amount of the outstanding shares of our common stock, the Goldman Sachs Funds and the Kelso Funds will continue to be able to strongly influence or effectively control our decisions, including potential mergers or acquisitions, asset sales and other significant corporate transactions.

You will incur immediate and substantial dilution.

The initial public offering price of our common stock is substantially higher than the adjusted net tangible book value per share of our outstanding common stock. As a result, if you purchase shares in this offering, you will incur immediate and substantial dilution in the amount of $ per share. See “Dilution.”

Shares eligible for future sale may cause the price of our common stock to decline.

Sales of substantial amounts of our common stock in the public market, or the perception that these sales may occur, could cause the market price of our common stock to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our amended and restated articles of incorporation, we are authorized to issue up to shares of common stock, of which shares of common stock will be outstanding following this offering. Of these shares, shares of common stock sold in this offering will be freely transferable without restriction or further registration under the Securities Act by persons other than “affiliates,” as that term is defined in Rule 144 under the Securities Act. Our selling stockholder, our directors and executive officers will enter into lock-up agreements, pursuant to which they are expected to agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any shares of our common stock for a period of 180 days from the date of this prospectus, subject to extension in certain circumstances. See “Shares Eligible for Future Sale.”

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. Statements that are predictive in nature, that depend upon or refer to future events or conditions or that include the words “believe,” “expect,” “anticipate,” “intend,” “estimate” and other expressions that are predictions of or indicate future events and trends and that do not relate to historical matters identify forward-looking statements. Our forward-looking statements include statements about our business strategy, our industry, our future profitability, our expected capital expenditures and the impact of such expenditures on our performance, the costs of operating as a public company, our capital programs and environmental expenditures. These statements involve known and unknown risks, uncertainties and other factors, including the factors described under “Risk Factors,” that may cause our actual results and performance to be materially different from any future results or performance expressed or implied by these forward-looking statements. Such risks and uncertainties include, among other things:


	•	volatile margins in the refining industry;

	•	exposure to the risks associated with volatile crude prices;

	•	disruption of our ability to obtain an adequate supply of crude oil;

	•	decreases in the light/heavy and/or the sweet/sour crude oil price spreads;

	•	refinery operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage;

	•	interruption of the pipelines supplying feedstock and in the distribution of our products;

	•	the seasonal nature of our petroleum business;

	•	competition in the petroleum and nitrogen fertilizer businesses;

	•	capital expenditures required by environmental laws and regulations;

	•	changes in our credit profile;

	•	the availability of adequate cash and other sources of liquidity for our capital needs;

	•	fluctuations in the price of natural gas;

	•	the cyclical nature of our nitrogen fertilizer business;

	•	adverse weather conditions;

	•	the supply and price levels of essential raw materials;

	•	the volatile nature of ammonia, potential liability for accidents involving ammonia that cause severe damage to property and/or injury to the environment and human health and potential increased costs relating to transport of ammonia;

	•	the dependence of our nitrogen fertilizer operations on a few third-party suppliers;

	•	our limited operating history as a stand-alone company;

	•	our commodity derivative activities;

	•	our dependence on significant customers;

	•	our potential inability to successfully implement our business strategies, including the completion of significant capital programs;

	•	our significant indebtedness;

	•	the dependence on our subsidiaries for cash to meet our debt obligations;

	•	the potential loss of key personnel;


	•	labor disputes and adverse employee relations;

	•	potential increases in costs and distraction of management resulting from the requirements of being a public company;

	•	risks relating to evaluations of internal controls required by Section 404 of the Sarbanes-Oxley Act;

	•	the operation of our company as a “controlled company”;

	•	new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities;

	•	successfully defending against third-party claims of intellectual property infringement; and

	•	our ability to continue to license the technology used in our operations.

You should not place undue reliance on our forward-looking statements. Although forward-looking statements reflect our good faith beliefs, reliance should not be placed on forward-looking statements because they involve known and unknown risks, uncertainties and other factors, which may cause our actual results, performance or achievements to differ materially from anticipated future results, performance or achievements expressed or implied by such forward-looking statements. We undertake no obligation to publicly update or revise any forward-looking statement, whether as a result of new information, future events, changed circumstances or otherwise.

USE OF PROCEEDS

We expect to receive $ million of gross proceeds from the sale of shares by us in this offering, based on an assumed initial public offering price of $ per share, the mid-point of the range set forth on the cover page of this prospectus. We expect to use the net proceeds of this offering for debt repayment. In particular, we intend to use $ million to repay indebtedness under the first lien credit facility, or the First Lien Credit Facility, and $ million to repay indebtedness under the second lien credit facility, or the Second Lien Credit Facility. We will not receive any proceeds from the purchase by the underwriters of up to shares from the selling stockholder.

Our subsidiary, Coffeyville Resources, LLC, entered into the First Lien Credit Facility and the Second Lien Credit Facility in connection with the Subsequent Acquisition in June 2005. The First Lien Credit Facility matures on June 23, 2012. The Second Lien Credit Facility matures on June 24, 2013. The tranche C term loans of the First Lien Credit Facility bear interest at either LIBOR plus 2.25% or, at the borrower’s election, the prime rate plus 1.25%, subject to adjustment in specified circumstances. Borrowings under the Second Lien Credit Facility bear interest at LIBOR plus 6.75% or, at the borrower’s election, the prime rate plus 5.75%. At September 30, 2006, the interest rate on the tranche C term loans of the First Lien Credit Facility was 7.631% and the interest rate on the Second Lien Credit Facility was 12.125%. At September 30, 2006, $222.8 million, $30 million and $0.0 million was outstanding under the tranche C term loan facility, the delayed draw term loan facility and the revolving credit facility under the First Lien Credit Facility and $275 million was outstanding under the Second Lien Credit Facility. The net proceeds from the tranche B term loans of $225.0 million, second lien term loans of $275.0 million and the $12.6 million of revolving loan facilities (together with a $227.7 million equity contribution from Coffeyville Acquisition LLC) were utilized to fund the following upon the closing of the Subsequent Acquisition: $685.8 million for cash proceeds to Immediate Predecessor, including $12.6 million of legal, accounting, advisory, transaction and other expenses associated with the Subsequent Acquisition; $49.6 million of other fees and expenses related to the Subsequent Acquisition; and $4.9 million of cash to fund our operating accounts.

DIVIDEND POLICY

Following the completion of this offering, we do not anticipate paying any cash dividends in the foreseeable future. We currently intend to retain future earnings, if any, to finance operations and the expansion of our business. Any future determination to pay cash dividends will be at the discretion of our board of directors and will be dependent upon our financial condition, results of operations, capital requirements and other factors that the board deems relevant. In addition, the covenants contained in Coffeyville Resources, LLC’s First Lien Credit Facility and Second Lien Credit Facility limit the ability of our subsidiaries to pay dividends to us, which limits our ability to pay dividends. Our ability to pay dividends also may be limited by covenants contained in the instruments governing future indebtedness that we or our subsidiaries may incur in the future. See “Description of Our Indebtedness and the Cash Flow Swap.”

CAPITALIZATION

The following table describes our cash and cash equivalents and our consolidated capitalization as of September 30, 2006:


	•	on an actual basis for Coffeyville Acquisition LLC; and

	•	as adjusted to give effect to the sale by us of shares in this offering at an assumed initial offering price of $ per share, the mid-point of the range set forth on the cover page of this prospectus, the use of proceeds from this offering and the Transactions.

You should read this table in conjunction with “Use of Proceeds,” “Selected Historical Consolidated Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and related notes included elsewhere in this prospectus.


	As of September 30, 2006
	Actual		As Adjusted
	(in millions)

Cash and cash equivalents	$	38.1	$

Term debt (including current portion)
First lien credit facility(1)	$	252.8	$
Second lien credit facility		275.0
Total term debt		527.8
Management voting common units subject to redemption, 227,500 units		9.0
Members’ equity(2):
Members’ voting common equity, 25,588,500 units		300.7
Operating override units, 919,630 units		1.5
Value override units, 1,839,265 units		0.9
Total members’ equity		303.1
Stockholders’ equity(2):
Common stock, $0.01 par value per share, shares authorized; shares issued and outstanding as adjusted		—
Preferred stock, $0.01 par value; shares authorized; no shares issued and outstanding as adjusted		—
Additional paid-in capital(2)		—
Total stockholders’ equity		—

Total capitalization	$	839.9	$


(1)		As of September 30, 2006, we had availability of $93.6 million under the revolving credit facility.


(2)		On an actual basis, the Members’ equity reflects the unit ownership at Coffeyville Acquisition LLC which is structured as a partnership for tax purposes. Upon completion of this offering, the reporting entity will be CVR Energy, Inc., a corporation. The ownership at Coffeyville Acquisition LLC will not be reported, and as such, the components of Members’ equity do not appear in the “As Adjusted” column. Upon completion of this offering, common stock in CVR Energy, Inc. will be issued and reflected in Common stock in the “As Adjusted” column. Members’ equity will be eliminated and replaced with Stockholders’ equity to reflect the new corporate structure. Any difference in the total value of equity upon completion of this offering and the par value of the common stock issued will be reflected in Additional paid-in capital.

DILUTION

Purchasers of common stock offered by this prospectus will suffer immediate and substantial dilution in net tangible book value per share. Our pro forma net tangible book value as of September 30, 2006 was approximately $ million, or approximately $ per share of common stock. Pro forma net tangible book value per share represents the amount of tangible assets less total liabilities, divided by the number of shares of common stock outstanding.

Dilution in net tangible book value per share represents the difference between the amount per share paid by purchasers of our common stock in this offering and the pro forma net tangible book value per share of our common stock immediately after this offering. After giving effect to the sale of shares of common stock in this offering at an assumed initial public offering price of $ per share, the mid-point of the range set forth on the cover page of this prospectus, and after deduction of the estimated underwriting discounts and commissions and estimated offering expenses payable by us, our pro forma net tangible book value as of September 30, 2006 would have been approximately $ million, or $ per share. This represents an immediate increase in net tangible book value of $ per share of common stock to our existing stockholder and an immediate pro forma dilution of $ per share to purchasers of common stock in this offering. The following table illustrates this dilution on a per share basis.


Assumed initial public offering price per share		$
Pro forma net tangible book value per shares of September 30, 2006	$

Pro forma increase per share attributable to new investors	$

Net tangible book value per share after the offering		$

Dilution per share to new investors		$

The following table sets forth as of September 30, 2006 the number of shares of common stock purchased or to be purchased from us, total consideration paid or to be paid and the average price per share paid by our existing stockholder and by new investors, before deducting estimated underwriting discounts and commissions and estimated offering expenses payable by us at an assumed initial public offering price of $ per share.


	Shares Purchased				Total Consideration				Average Price
	Number	Percent			Amount	Percent			Per Share

Existing stockholder				%	$			%
New investors

Total			100.0	%	$		100.0	%

UNAUDITED PRO FORMA CONDENSED CONSOLIDATED STATEMENT OF OPERATIONS

CVR Energy, Inc. was incorporated in Delaware in September 2006. CVR Energy has assumed that concurrent with this offering, a newly formed direct subsidiary of CVR Energy will merge with Coffeyville Refining & Marketing, Inc. and a separate newly formed direct subsidiary of CVR Energy will merge with Coffeyville Nitrogen Fertilizers, Inc. which will make Coffeyville Refining & Marketing and Coffeyville Nitrogen Fertilizers directly owned subsidiaries of CVR Energy. CVR Energy currently has no assets, liabilities, revenues, or financial activity of its own. It was organized in connection with and in order to consummate this offering. The pre-IPO reorganization transactions will have no financial impact on our results of operations.

Coffeyville Acquisition LLC was formed in May 2005 to effect the acquisition, pursuant to a stock purchase agreement dated May 15, 2005, of all of the subsidiaries of Coffeyville Group Holdings LLC, which we refer to as the Subsequent Acquisition.

The following unaudited pro forma condensed consolidated statement of operations of CVR Energy, Inc. for the year ended December 31, 2005 has been derived from (1) the historical statement of operations of Coffeyville Group Holdings, LLC and subsidiaries, excluding the operations of Leiber Holdings, LLC, which we collectively refer to as Immediate Predecessor, for the 174-day period ended June 23, 2005 and (2) the historical statement of operations of Coffeyville Acquisition LLC and subsidiaries, which we refer to as the Successor, for the 233-day period ended December 31, 2005, adjusted to give pro forma effect to the Subsequent Acquisition as if it occurred on January 1, 2005.

The operations of Leiber were not included in the historical statement of operations of the Immediate Predecessor as Leiber’s operations were unrelated to, and were not part of, the ongoing operations of the Company. The Immediate Predecessor owned for a brief period from October 8, 2004 through June 23, 2005, a portion of a joint venture which included the operations of Leiber. The Leiber business was a designer handbag business whose operations had no correlation to the business of the Company. The management was not the same as the Immediate Predecessor’s or the Successor’s, nor were there any intercompany transactions between Leiber and the Immediate Predecessor or the Successor, aside from certain contributions. There have been no relevant amounts related to the Leiber business with respect to the ongoing business of the Company. Due to this, the pro forma condensed consolidated statement of operations has been prepared consistent with the historical financial statement of operations which excluded the operations of Leiber.

The historical results of operations of the Immediate Predecessor and Successor during 2005 overlap for 42 days: we present the Immediate Predecessor for 174 days ended June 23, 2005 and the Successor period for the 233 days ended December 31, 2005. The reason for the overlap is that Successor was formed on May 13, 2005 but had no financial statement activity during the 42-day period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005 which expired unexercised on June 16, 2005. As a result, although the Successor’s financial statement period begins on May 13, 2005, the activity of the subsidiaries of Coffeyville Group Holdings LLC were not included in the financial information of Coffeyville Acquisition LLC until June 24, 2005 when the Subsequent Acquisition occurred. The financial activity of the subsidiaries of Coffeyville Group Holdings LLC through June 23, 2005 is included in the Immediate Precedessor results of operations.

The unaudited pro forma condensed consolidated statement of operations are provided for informational purposes only and do not purport to represent or be indicative of the results that actually would have been obtained had the transactions described above occurred on January 1, 2005 and are not intended to project our results of operations for any future period.

The pro forma adjustments are based on available information and certain assumptions that we believe are reasonable. The pro forma adjustments and certain assumptions are described in the accompanying notes. Other information included under this heading has been presented to provide additional analysis. The allocation of the purchase price of the Subsequent Acquisition to the net

assets acquired has been performed in accordance with Statement of Financial Accounting Standards (SFAS) 141.

The unaudited pro forma statement of operations set forth below should be read in conjunction with the historical financial statements, the related notes and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.

CVR Energy, Inc.
Unaudited Pro Forma Condensed Consolidated Statement of Operations
For the Year Ended December 31, 2005


	Historical
	Immediate			Historical			Pro Forma
	Predecessor			Successor			Adjustments To
	174 Days			233 Days			Give Effect			Pro Forma
	Ended			Ended			to the			Year Ended
	June 23,			December 31,			Subsequent			December 31,
	2005			2005			Acquisition			2005
Net Sales		980,706,261			1,454,259,542			—			2,434,965,803
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		768,067,178			1,168,137,217			—			1,936,204,395
Direct operating expenses (exclusive of depreciation and amortization)		80,913,862			85,313,202			24,481	(c)		166,251,545
Depreciation and amortization		1,128,005			23,954,031			22,376,281	(a)		47,643,362
								185,045	(b)
Selling, general and administrative expenses (exclusive of depreciation and amortization)		18,341,522			18,320,030			(2,645,573	)(c)		35,980,250
								1,964,271	(d)

Total operating expenses		868,450,567			1,295,724,480			21,904,505			2,186,079,552

Operating income		112,255,694			158,535,062			(21,904,505	)		248,886,251
Other income (expense):
Interest expense		(7,801,821	)		(25,007,159	)		(14,779,995	) (e)		(47,588,975	)
Loss on derivatives		(7,664,725	)		(316,062,111	)		—			(323,726,836	)
Loss on extinguishment of debt		(8,093,754	)		—			8,093,754	(f)		—
Other income (expense)		(250,929	)		409,074			—			158,145

Net income (loss) before income taxes		88,444,465			(182,125,134	)		(28,590,746	)		(122,271,415	)
Income taxes expense (benefit)		36,047,516			(62,968,044	)		(12,422,645	)(g)		(39,343,173	)

Net income (loss)		52,396,949			(119,157,090	)		(16,168,101	)		(82,928,242	)

Pro forma earnings per share, basic and diluted(h)				$	—					$	—

Pro forma weighted average earnings per share, basic and diluted(h)


(a)		To reflect the increase in depreciation resulting from the step-up of property, plant, and equipment, depreciated on a straight-line basis over 3 to 30 years.

The allocation of the purchase price at June 24, 2005, the date of the Subsequent Acquisition, as more fully described in note 1 to the consolidated financial statements, was as follows (in thousands):


Assets acquired
Cash	$	666.5
Accounts receivable		37,329.0
Inventories		156,171.3
Prepaid expenses and other current assets		4,865.2
Intangibles, contractual agreements		1,322.0
Goodwill		83,774.9
Other long-term assets		3,837.6
Property, plant, and equipment		750,910.2

Total assets acquired	$	1,038,876.7

Liabilities assumed
Accounts payable	$	47,259.1
Other current liabilities		16,017.2
Current income taxes		5,076.0
Deferred income taxes		276,888.8
Other long-term liabilities		7,843.5

Total liabilities assumed	$	353,084.6

Cash paid for acquisition of Immediate Predecessor	$	685,792.1


(b)		To increase amortization expense due to the amortization of identifiable intangibles using a straight-line method over a weighted average life of eight years.


(c)		(1) To reverse the share based compensation expense associated with senior management share based compensation plans of Immediate Predecessor of $3,985,991, and (2) to recognize share based compensation expense of $1,364,899 of Successor as if the senior management share based compensation plans of Successor had gone into effect on January 1, 2005, based on the valuation as of the purchase date, (June 24, 2005), as adjusted for the additional vesting period from January 1, 2005 to June 24, 2005. These adjustments are necessary as they directly correlate with the Subsequent Acquisition. If the Subsequent Acquisition had occurred on January 1, 2005, the share based compensation plans would have been those of Successor, and not the Immediate Predecessor.


(d)		To reflect the increase in fees related to the funded letter of credit in support of the cash flow swaps, which are required under the terms of the senior secured credit facility refinanced on June 24, 2005.

(e)		To increase interest expense for (1) interest resulting from the issuance of debt to refinance our senior secured credit facility on June 24, 2005 to finance the cash portion of the purchase price giving pro forma effect to the refinancing of our debt as if it had occurred on January 1, 2005 and (2) the amortization of deferred financing cost resulting from $24.6 million of deferred financing charges related to the debt incurred on June 24, 2005 amortized using an effective interest amortization method over the term of the debt. An assumed average interest rate of 8.48% based on the interest rate in effect on the term loan as of June 24, 2005 was used to calculate interest expense on an average annual balance of $498.9 million of term debt as if the First Lien Credit Facility and the Second Lien Credit Facility were entered into on January 1, 2005.


(f)		To reverse the write-off of $8.1 million of deferred financing costs incurred in connection with the refinancing of our senior secured credit facility on June 24, 2005. This adjustment directly correlates to the Subsequent Acquisition. In connection with the Subsequent Acquisition, we entered into a refinancing transaction. These costs, which are costs attributable to the Immediate Predecessor, would have been written off in 2004 and not in 2005 had the Subsequent Acquisition occurred as of January 1, 2005.


(g)		To reflect the income tax effect of the pro forma pre-tax loss adjustments of $28,590,746 for the year ended December 31, 2005, based on an effective tax rate of 43.5%. The effective tax rate was determined by applying a combined federal and state statutory income tax rate of approximately 39.7% to pro forma pre-tax loss adjustments of $31,291,296. There was no tax effect on pro forma adjustments of pre-tax income of $2,700,550 relating to non-deductible unearned compensation expense.


(h)		To calculate earnings per share on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering with respect to the existing shares. All information in this prospectus assumes that prior to the initial public offering, two newly formed direct wholly owned subsidiaries of CVR Energy will merge with two wholly owned subsidiaries of Coffeyville Acquisition LLC, CVR Energy will effect a for stock split prior to completion of this offering and CVR Energy will issue shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering pursuant to the exercise by the underwriters of their option.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

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

The selected consolidated financial information presented below under the caption Statement of Operations Data for the year ended December 31, 2003, for the 62-day period ended March 2, 2004, for the 304 days ended December 31, 2004, for the 174-day period ended June 23, 2005 and for the 233-day period ended December 31, 2005, and the selected consolidated financial information presented below under the caption Balance Sheet Data as of December 31, 2004 and 2005 have been derived from our audited consolidated financial statements included elsewhere in this prospectus, which financial statements have been audited by KPMG LLP, independent registered public accounting firm. The consolidated financial information presented below under the caption Statement of Operations Data for the years ended December 31, 2001 and 2002, and the consolidated financial information presented below under the caption Balance Sheet Data at December 31, 2001, 2002 and 2003, are derived from our audited consolidated financial statements that are not included in this prospectus. The selected unaudited interim consolidated financial information presented below under the caption Statement of Operations Data presented below for the 141-day period ended September 30, 2005 and the nine month period ended September 30, 2006, and the selected unaudited interim consolidated financial information presented below under the caption Balance Sheet Data as of September 30, 2006, have been derived from our unaudited interim consolidated financial statements, which are included elsewhere in this prospectus and have been prepared on the same basis as the audited consolidated financial statements. In the opinion of management, the interim data reflect all adjustments, consisting only of normal and recurring adjustments, necessary for a fair presentation of results for these periods. Operating results for the nine month period ended September 30, 2006 are not necessarily indicative of the results that may be expected for the year ended December 31, 2006.

Prior to March 3, 2004, our assets were operated as a component of Farmland. Farmland filed for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code on May 31, 2002. On March 3, 2004, Coffeyville Resources, LLC completed the purchase of these assets from Farmland in a sales process under Chapter 11 of the U.S. Bankruptcy Code. See note 1 to our consolidated financial statements included elsewhere in this prospectus. 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 304 days ended December 31, 2004 are not comparable to prior periods.


	Immediate
	Predecessor			Successor			Successor
	174 Days			141 Days			Nine Months
	Ended			Ended			Ended
	June 23,			September 30,			September 30,
	2005			2005			2006
				(unaudited)			(unaudited)
	(in millions, except as otherwise indicated)
Statement of Operations Data:
Net sales	$	980.7		$	776.6		$	2,329.2
Cost of product sold (exclusive of depreciation and amortization)		768.0			624.9			1,848.1
Direct operating expenses (exclusive of depreciation and amortization)		80.9			36.7			144.5
Selling, general and administrative expenses (exclusive of depreciation and amortization)		18.4			7.3			32.8
Depreciation and amortization		1.1			11.9			36.8

Operating income	$	112.3		$	95.8		$	267.0
Other income (expense) and gain (loss) on sale in joint ventures(1)		(8.4	)		0.1			3.1
Interest (expense)		(7.8	)		(12.2	)		(33.0	)
Gain (loss) on derivatives		(7.6	)		(487.1	)		44.7

Income (loss) before taxes	$	88.5		$	(403.4	)	$	281.8
Income tax (expense) benefit		(36.1	)		150.8			(111.0	)

Net income (loss)(2)	$	52.4		$	(252.6	)	$	170.8
Pro forma earnings per share, basic and diluted
Pro forma weighted average shares, basic and diluted
Historical dividends per unit(3):
Preferred	$	0.70		$	—		$	—
Common	$	0.70		$	—		$	—
Balance Sheet Data:
Cash and cash equivalents							$	38.1
Working capital								173.4
Total assets								1,397.7
Total debt, including current portion								527.8
Management units subject to redemption								9,0
Divisional/members’ equity								303.1
Other Financial Data:
Depreciation and amortization	$	1.1		$	11.9		$	36.8
Net income adjusted for unrealized gain or loss from Cash Flow Swap(4)		52.4			4.9			122.0
Cash flows provided by operating activities		12.7			63.3			97.9
Cash flows (used in) investing activities		(12.3	)		(697.2	)		(173.0	)
Cash flows provided by (used in) financing activities		(52.4	)		713.2			48.5
Capital expenditures for property, plant and equipment		(12.3	)		(12.1	)		(173.0	)
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)(6)		99,171			105,162			106,975
Crude oil throughput (barrels per day)(5)(6)		88,012			93,268			94,061
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)(5)		193.2			118.1			283.9
UAN (tons in thousands)(5)		309.9			185.8			465.0


	Original Predecessor											Immediate Predecessor						Successor
										62 Days		304 Days			174 Days			233 Days
	Year Ended									Ended		Ended			Ended			Ended
	December 31,									March 2,		December 31,			June 23,			December 31,
	2001			2002			2003			2004		2004			2005			2005
	(in millions, except as otherwise indicated)
Statement of Operations Data:
Net sales	$	1,630.2		$	887.5		$	1,262.2		$	261.1	$	1,479.9		$	980.7		$	1,454.3
Cost of product sold (exclusive of depreciation and amortization)		1,458.0			765.8			1,061.9			221.4		1,244.2			768.0			1,168.1
Direct operating expenses (exclusive of depreciation and amortization)		146.3			149.4			133.1			23.4		117.0			80.9			85.3
Selling, general and administrative expenses (exclusive of depreciation and amortization)		24.8			16.3			23.6			4.7		16.3			18.4			18.4
Depreciation and amortization		19.1			30.8			3.3			0.4		2.4			1.1			24.0
Impairment, earnings (losses) in joint ventures, and other charges(7)		(2.8	)		(375.1	)		(10.9	)		—		—			—			—

Operating income (loss)	$	(20.8	)	$	(449.9	)	$	29.4		$	11.2	$	100.0		$	112.3		$	158.5
Other income (expense) and gain (loss) on sale in joint ventures(1)		19.2			0.1			(0.5	)		—		(6.9	)		(8.4	)		0.4
Interest (expense)		(18.3	)		(11.7	)		(1.3	)		—		(10.1	)		(7.8	)		(25.0	)
Gain (loss) on derivatives		0.5			(4.2	)		0.3			—		0.5			(7.6	)		(316.1	)

Income (loss) before taxes	$	(19.4	)	$	(465.7	)	$	27.9		$	11.2	$	83.5		$	88.5		$	(182.2	)
Income tax (expense) benefit		—			—			—			—		(33.8	)		(36.1	)		63.0

Net income (loss)(2)	$	(19.4	)	$	(465.7	)	$	27.9		$	11.2	$	49.7		$	52.4		$	(119.2	)
Pro forma earnings per share, basic and diluted
Pro forma weighted average shares, basic and diluted
Historical dividends per unit(3):
Preferred												$	1.50		$	0.70
Common												$	0.48		$	0.70
Balance Sheet Data:
Cash and cash equivalents	$	0.0		$	0.0		$	0.0				$	52.7					$	64.7
Working capital(8)		71.2			122.2			150.5					106.6						108.0
Total assets		300.3			172.3			199.0					229.2						1,221.5
Liabilities subject to compromise(9)		—			105.2			105.2					—						—
Total debt, including current portion		—			—			—					148.9						499.4
Management units subject to redemption		—			—			—					—						3.7
Divisional/members’ equity		241.4			49.8			58.2					14.1						115.8
Other Financial Data:
Depreciation and amortization	$	19.1		$	30.8		$	3.3		$	0.4	$	2.4		$	1.1		$	24.0
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4)		(19.4	)		(465.7	)		27.9			11.2		49.7			52.4			23.6
Cash flows provided by (used in) operating activities		65.4			(1.7	)		20.3			53.2		89.8			12.7			82.5
Cash flows (used in) investing activities		17.9			(272.4	)		(0.8	)		—		(130.8	)		(12.3	)		(730.3	)


	Original Predecessor											Immediate Predecessor					Successor
									62 Days			304 Days		174 Days			233 Days
	Year Ended								Ended			Ended		Ended			Ended
	December 31,								March 2,			December 31,		June 23,			December 31,
	2001			2002		2003			2004			2004		2005			2005
	(in millions, except as otherwise indicated)
Cash flows provided by (used in) financing activities		(83.3	)		274.1		(19.5	)		(53.2	)		93.6		(52.4	)		712.5
Capital expenditures for property, plant and equipment		8.2			272.4		0.8			—			14.2		12.3			45.2
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)(6)		94,758			84,343		95,701			106,645			102,046		99,171			107,177
Crude oil throughput (barrels per day)(5)(6)		84,605			74,446		85,501			92,596			90,418		88,012			93,908
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)(5)		198.5			265.1		335.7			56.4			252.8		193.2			220.0
UAN (tons in thousands)(5)		286.2			434.6		510.6			93.4			439.2		309.9			353.4


(1)		Includes a gain on the sale of a joint venture interest of $18.0 million that was recorded in 2001 for the disposition of our share in Country Energy, LLC. During the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005, we recognized a loss of $7.2 million and $8.1 million, respectively, on early extinguishment of debt, respectively.


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


	Immediate Predecessor		Successor		Successor
	174 Days Ended		141 Days Ended		Nine Months Ended
	June 23,		September 30,		September 30,
	2005		2005		2006
			(unaudited)		(unaudited)
			(in millions)
Loss on extinguishment of debt(d)	$	8.1	$	—	$	—
Inventory fair market value adjustment(e)		—		16.9		—
Funded letter of credit and interest rate swap not included in interest expense(f)		—		1.4		0.2
Major scheduled turnaround expense(g)		—		—		4.4
Loss on termination of swap(h)		—		25.0		—
Unrealized (gain) loss from Cash Flow Swap		—		427.1		(80.3	)


	Original Predecessor									Immediate Predecessor				Successor
	Year							62 Days		304 Days		174 Days		233 Days
	Ended							Ended		Ended		Ended		Ended
	December 31,							March 2,		December 31,		June 23,		December 31,
	2001			2002		2003		2004		2004		2005		2005
	(in millions)
Impairment of property, plant and equipment(a)	$	—		$	375.1	$	9.6	$	—	$	—	$	—	$	—
Fertilizer lease payments(b)		18.7			0.3		—		—		—		—		—
Loss on extinguishment of debt(c)		—			—		—		—		7.2		8.1		—
Inventory fair market value adjustment(d)		—			—		—		—		3.0		—		16.6
Funded letter of credit expense and interest rate swap not included in interest expense(e)		—			—		—		—		—		—		2.3
Major scheduled turnaround expense(f)		—			17.0		—		—		1.8		—		—
Loss on termination of swap(g)		—			—		—		—		—		—		25.0
Unrealized loss from Cash Flow Swap		—			—		—		—		—		—		235.9
(Gain) on sale of joint venture(h)		(18.0	)		—		—		—		—		—		—


(a)		During the year ended December 31, 2002, we recorded a $375.1 million asset impairment related to the write-down of our refinery and nitrogen fertilizer plant to estimated fair value. During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition.

(b)		Reflects the impact of an operating lease structure utilized by Farmland to finance the nitrogen fertilizer plant which operating lease structure is not currently in use. The cost of this plant under the operating lease was $263.0 million and the rental payments were $18.7 million and $0.3 million for the periods ended December 31, 2001 and 2002, respectively. In February 2002, Farmland refinanced the operating lease into a secured loan structure, which effectively terminated the lease and all of Farmland’s obligations under the lease.


(c)		Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004 and the write-off of $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005.


(d)		Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory.


(e)		Consists of fees which are expensed to Selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the First Lien Credit Facility and the Second Lien Credit Facility.


(f)		Represents expense associated with a major scheduled turnaround.


(g)		Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005.


(h)		Reflects the gain on the sale of $18.0 million, which was recorded for the disposition of Original Predecessor’s share in Country Energy, LLC.


(3)		Historical dividends per unit for the 304-day period ended December 31, 2004 and the 174-day period ended June 23, 2005 are calculated based on the ownership structure of Immediate Predecessor.


(4)		Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned by Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. Under these agreements, sales representing approximately 70% and 17% of then forecasted refinery output for the


		periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, have been economically hedged. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. See “Description of Our Indebtedness and the Cash Flow Swap.”


		We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements, which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for gain or loss from Cash Flow Swap as a key indicator of our business performance and believes that this non-GAAP measure is a useful measure for investors in analyzing our business. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.


		Net income adjusted for gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of performance in evaluating our business. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.


		The following is a reconciliation of Net income adjusted for unrealized gain or loss from Cash Flow Swap to Net income:


	Immediate
	Predecessor		Successor			Successor
	174 Days		141 Days			Nine Months
	Ended		Ended			Ended
	June 23,		September 30,			September 30,
	2005		2005			2006
			(unaudited)			(unaudited)
	(in millions)
Net income adjusted for unrealized gain or loss from Cash Flow Swap	$	52.4	$	4.9		$	122.4
Plus:
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit		—		(257.5	)		48.4

Net income (loss)	$	52.4	$	(252.6	)	$	170.8


	Original Predecessor										Immediate Predecessor				Successor
									62 Days		304 Days		174 Days		233 Days
	Year Ended								Ended		Ended		Ended		Ended
	December 31,								March 2,		December 31,		June 23,		December 31,
	2001			2002			2003		2004		2004		2005		2005
	(in millions)

Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap	$	(19.4	)	$	(465.7	)	$	27.9	$	11.2	$	49.7	$	52.4	$	23.6
Plus:
Unrealized (loss) from Cash Flow Swap, net of tax benefit		—			—			—		—		—		—		(142.8	)

Net income (loss)	$	(19.4	)	$	(465.7	)	$	27.9	$	11.2	$	49.7	$	52.4	$	(119.2	)


(5)		Operational information reflected for the 141-day Successor period ended September 30, 2005 includes only 99 days of operational activity. Operational information reflected for the 233-day Successor period ended December 31, 2005 includes only 191 days of operational activity. Successor was formed on May 13, 2005 but had no financial statement activity during


		the 42-day period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005 which expired unexercised on June 16, 2005.

(6)		Barrels per day is calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facility’s continuous operations.

(7)		Includes the following:


•		During the year ended December 31, 2001, we recognized expenses of $2.8 million for our share of losses of Country Energy, LLC.

•		During the year ended December 31, 2002, we recorded a $375.1 million asset impairment related to the write-down of the refinery and nitrogen fertilizer plant to estimated fair value.

•		During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code.


(8)		Excludes liabilities subject to compromise due to Original Predecessor’s bankruptcy of $105.2 million as of December 31, 2002 and 2003 in calculating Original Predecessor’s working capital.

(9)		While operating under Chapter 11 of the U.S. Bankruptcy Code, Original Predecessor’s financial statements were prepared in accordance with SOP 90-7 “Financial Reporting by Entities in Reorganization under Bankruptcy Code.” SOP 90-7 requires that pre-petition liabilities be segregated in the Balance Sheet.

MANAGEMENT’S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Overview and Executive Summary

We are an independent refiner and marketer of high value transportation fuels and a premier producer of ammonia and UAN fertilizers. We are one of only seven petroleum refiners and marketers in the Coffeyville supply area (Kansas, Oklahoma, Missouri, Nebraska and Iowa) and, at current natural gas prices, the lowest cost producer and marketer of ammonia and UAN in North America.

We have two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2004 and 2005 and the twelve months ended September 30, 2006, we generated combined net sales of $1.7 billion, $2.4 billion and $3.0 billion, respectively. Our petroleum business generated $1.6 billion, $2.3 billion and $2.8 billion of our combined net sales, respectively, over these periods, with our nitrogen fertilizer business generating substantially all of the remainder. In addition, during these three periods, our petroleum business contributed 76%, 74% and 84% of our combined operating income, respectively, with our nitrogen fertilizer business contributing substantially all of the remainder.

Our petroleum business includes a 108,000 bpd complex full coking sour crude refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system serving central Kansas and northern Oklahoma, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, and (3) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and at throughput terminals on Magellan’s refined products distribution systems. In addition to rack sales (sales which are made at terminals using tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and Valero. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, the largest crude oil trading and storage hub in the United States, served by numerous pipelines from locations including the U.S. Gulf Coast and Canada, which provides us with access to virtually any crude variety in the world capable of being transported by pipeline.

Throughput (the volume processed at a facility) at the refinery has markedly increased since July 2005. Management’s focus on crude slate optimization (the process of determining the most economic crude oils to be refined), reliability, technical support and operational excellence coupled with prudent expenditures on equipment has significantly improved the operating metrics of the refinery. Historically, the Coffeyville refinery operated at an average crude throughput rate of less than 90,000 bpd. In the second quarter of 2006, the plant averaged over 102,000 bpd of crude throughput and over 94,000 bpd for the first nine months of 2006 with peak daily rates in excess of 108,000 bpd. Not only were rates increased but yields were simultaneously improved. Since June 2005 the refinery has eclipsed monthly record (30 day) processing rates on approximately two thirds of the individual units on site.

Crude is supplied to our refinery through our owned and leased gathering system and by a Plains pipeline from Cushing, Oklahoma. We maintain capacity on the Spearhead Pipeline from Canada and receive foreign and deepwater domestic crudes via the Seaway Pipeline system. We also maintain leased storage in Cushing to facilitate optimal crude purchasing and blending. We have significantly expanded the variety of crude grades processed in any given month from a limited few to

nearly a dozen, including onshore and offshore domestic grades, various Canadian sours, heavy sours and sweet synthetics, and a variety of South American and West African imported grades. As a result of the crude slate optimization, we have improved the crude purchase cost discount to WTI from $2.80 per barrel in the first nine months of 2005 compared to $4.29 per barrel in the first nine months of 2006.

Prior to July 2005, we did not maintain shipper status on the Magellan pipeline system. Instead, rack marketing was limited to our owned terminals. Today, while we still rack market at our own terminals, our growing rack marketing network sells approximately 23% of produced transportation fuels at enhanced margins. For the first nine months of 2006, we improved net income on rack sales compared to alternative pipeline bulk sales that occurred in the first nine months of 2005.

Our nitrogen fertilizer business in Coffeyville, Kansas includes a unique pet coke gasification facility that produces high purity hydrogen which in turn is converted to ammonia at our ammonia synthesis plant. Ammonia is further upgraded into UAN solution in our UAN plant. Pet coke is a low value by-product of the refinery coking process. On average more than 80% of the pet coke consumed by the fertilizer plant is produced by our refinery.

We are the lowest cost producer of ammonia and UAN in North America, assuming natural gas prices remain at current levels. Our fertilizer plant is the only commercial facility in North America utilizing a coke gasification process to produce nitrogen fertilizers. Our redundant train gasifier provides exceptional on-stream reliability and the use of low cost by-product pet coke feed to produce hydrogen provides us with a significant competitive advantage due to high and volatile natural gas prices. Our competition utilizes natural gas to produce ammonia. Continual operational improvements resulted in producing over 800,000 tons of product in 2005. Recently, the first phase of a planned expansion successfully resulted in further output. We are also considering a fertilizer plant expansion, which we estimate could increase our capacity to upgrade ammonia into premium priced UAN by 50% to approximately 1,000,000 tons per year.

Management has identified and developed several significant capital projects with a total cost of approximately $400 million. Substantially all of these capital expenditures are expected to be made before the end of 2007. Our experienced engineering and construction team is managing these projects in-house with support from established specialized contractors, thus giving us maximum control and oversight of execution. Major projects include construction of a new diesel hydrotreater, a new continuous catalytic reformer, a new sulfur recovery unit, a new plant-wide flare system, a technology upgrade to the fluid catalytic cracking unit and a refinery-wide capacity expansion. The spare gasifier at our fertilizer plant was expanded and it is expected that ammonia production will increase by at least 6,500 tons per year. The refinery expansion is expected to allow us to process up to 120,000 bpd of crude. Once completed, these projects are intended to significantly enhance the profitability of the refinery in environments of high crack spreads and allow the refinery to operate more profitably at lower crack spreads than is currently possible.

Factors Affecting Comparability

Our results over the past three years have been 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, LLC completed the acquisition of the former Farmland petroleum division and one facility within Farmland’s eight-plant nitrogen fertilizer manufacturing and marketing division which now comprise our business. 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. Prior to March 3, 2004, Farmland’s petroleum division was primarily comprised of our current petroleum business. Our nitrogen fertilizer plant, however, was the only coke gasification facility within Farmland’s eight-plant nitrogen fertilizer manufacturing and marketing division.

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 corresponding period in 2003. 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 assume the accounts receivable or 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. 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 233 days ended December 31, 2005 are not comparable to prior periods. In connection with the acquisition, Coffeyville Resources, LLC entered into a series of commodity derivative contracts, the Cash Flow Swap, in the form of three long-term swap agreements pursuant to which sales representing approximately 70% and 17% of then forecasted refinery output for the periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, has been economically hedged. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under Statement of Financial Accounting Standards, or SFAS, No. 133, Accounting for Derivative Instruments and Activities. Therefore, in the financial statements for all periods after July 1, 2005, the statement of operations reflects all the realized and unrealized gains and losses from this swap. For the 233 day period ending December 31, 2005, we recorded realized and unrealized losses of $59.3 million and $235.9 million, respectively. For the nine month period ending September 30, 2006, we recorded net realized losses of $46.1 million and net unrealized gains of $80.3 million.

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 businesses were approximately $12.7 million and $3.9 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. With the exception of insurance, the net impact to our financial statements as a result of these allocations is higher selling, general and administrative expense for the period from January 1, 2003 to March 2, 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 that had not been carried by Farmland. Examples of this additional insurance coverage are business interruption insurance and a remediation cost cap policy related to assumed RCRA corrective orders related to contamination at or that originated from our refinery and the Phillipsburg terminal. The preceding examples and other coverage changes resulted in additional insurance costs for us.

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 this Statement, 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 petroleum assets and the carrying amount of our nitrogen fertilizer plant in Coffeyville exceeded their estimated future undiscounted net cash flow. Impairment charges of $144.3 million and $230.8 million were recognized for each of the refinery and 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, LLC 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 $3.9 million and $5.7 million, respectively, for the refinery and fertilizer assets.

Original Predecessor Agreements with CHS, Inc. and Agriliance, LLC

In December 2001, Farmland entered into an agreement to sell to CHS, Inc. all of Farmland’s refined products produced at the Coffeyville refinery through November 2003. The selling price for this production was set by reference to daily market prices within a defined geographic region. Subsequent to the expiration of the CHS agreement, the petroleum business began marketing its refined products in the open market to multiple customers.

The revenue received by the petroleum business under the CHS agreement was limited due to the pricing formula and product mix. From December 2001 through November 2003, under the CHS agreement, both sales of bulk pipeline shipments and truckload quantities at the Coffeyville truck rack were priced at Group III Platts Low. Currently, all sales at the Coffeyville truck rack are sold at the Platts mean price or higher. Our term contracted bulk product sales are priced between the Platts low and Platts mean prices. All other bulk sales are sold at spot market prices. In addition, we are selling several value added products that were not produced under the CHS agreement.

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 Agriliance, LLC. Under the agreement, Agriliance, LLC was responsible for marketing substantially all of the nitrogen made by Farmland on a basis deemed meaningful to their internal management. 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 netbacks on sales of fertilizer products as a percentage of market average prices. For example, in 2004 we generated average netbacks as a percentage of market averages of 90.1% and 80.2% for ammonia and UAN, respectively, compared to average netbacks as a percentage of market averages of 86.6% and 75.9% for ammonia and UAN, respectively, in 2003.

Refinancing and Prior Indebtedness

At March 3, 2004, Immediate Predecessor entered into an agreement with a financial institution for a term loan of $21.9 million with an interest rate based on the greater of the Index Rate (the greater of prime or the federal funds rate plus 50 basis points per year) plus 4.5% or 9% and a $100 million revolving credit facility with interest at the borrower’s election of either the Index Rate plus 3% or LIBOR plus 3.5%. Amounts totaling $21.9 million of the term loan borrowings and $38.8 million of the revolving credit facility were used to finance the Initial Acquisition on March 3, 2004 as described above. Outstanding borrowings on May 10, 2004 were repaid in connection with the refinancing described below.

Effective May 10, 2004, Immediate Predecessor entered into a term loan of $150 million and a $75 million revolving loan facility with a syndicate of banks, financial institutions, and institutional lenders. Both loans were secured by substantially all of Immediate Predecessor’s real and personal property, including receivables, contract rights, general intangibles, inventories, equipment, and financial assets. The covenants contained under the new term loan contained restrictions which limited the ability to pay dividends at the complete discretion of the Board of Directors. The Immediate

Predecessor had no other restrictions on its ability to make dividend payments. Once any debt requirements were met, any dividends were at the discretion of the Board of Directors. There were outstanding borrowings of $148.9 million under the term loan and less than $0.1 million under the revolving loan facility at December 31, 2004. Outstanding borrowings on June 23, 2005 were repaid in connection with the Subsequent Acquisition as described above.

Effective June 24, 2005, Coffeyville Resources, LLC entered into the First Lien Credit Facility and the Second Lien Credit Facility. The First Lien Credit Facility is in an aggregate amount not to exceed $525 million, consisting of $225 million tranche C term loans; $50 million of delayed draw term loans available for the first 18 months of the agreement and subject to accelerated payment terms; a $100 million revolving loan facility; and a funded letter of credit facility (funded facility) of $150 million for the benefit of the Cash Flow Swap provider. The First Lien Credit Facility is secured by substantially all of Coffeyville Resources, LLC’s assets. At September 30, 2006, $222.8 million of tranche C term loans was outstanding, $30 million of delayed draw term loans was outstanding and there was $93.6 million available under the revolving loan facility. At September 30, 2006, Coffeyville Resources, LLC had $150 million in a funded letter of credit outstanding to secure payment obligations under derivative financial instruments. The Second Lien Credit Facility is a $275 million term loan facility secured by substantially all of Coffeyville Resources, LLC’s assets on a second priority basis.

Public Company Expenses

We expect that our general and administrative expenses will increase due to the costs of operating as a public company, such as increases in legal, accounting and compliance, insurance premiums, and investor relations. We estimate that the increase in these costs will total approximately $2.5 million to $3.0 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 and will affect the comparability with our financial statements of periods prior to the completion of this offering.

Changes in Legal Structure

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, the accompanying Original Predecessor financial statements do not reflect any provision for income taxes.

Industry Factors

Earnings for our petroleum business depend largely on refining industry margins, which have been and continue to be volatile. Crude oil and refined product prices depend on factors beyond our control. While it is impossible to predict refining margins due to the uncertainties associated with global crude oil supply and global and domestic demand for refined products, we believe that refining margins for U.S. refineries will generally remain above those experienced in the period from and including 1998 through 2003 as growth in demand for refining products in the United States, particularly transportation fuels, continues to exceed the ability of domestic refiners to increase capacity. In addition, changes in global supply and demand and other factors have constricted the extent to which product importation to the United States can relieve domestic supply deficits. This phenomenon is more pronounced in our marketing region, where demand for refined products exceeded refining production by approximately 24% in 2005.

During 2004, the market price of distillates (primarily No. 1 diesel fuel and kerosene) relative to crude oil was above average due to low industry inventories and strong consumer demand brought about by the relatively cold winter weather in the Midwest and high natural gas prices. In addition, gasoline margins were above average, and substantially so during the spring and summer driving seasons, primarily because of very low pre-driving season inventories exacerbated by high demand growth. The increased demand for refined products due to the relatively cold winter and the decreased supply due to high turnaround activity led to increasing refining margins during the early part of 2004. The key event of 2005 to our industry was the hurricane season which produced a record number of named storms. The location and intensity of these storms caused extreme amounts of damage to both crude and natural gas production as well as extensive disruption to many U.S. Gulf Coast refinery operations. These events caused both price spikes in the commodity markets as well as substantial increases in crack spreads. The U.S. Gulf Coast refining market was most affected, which then led to very strong margins in the Group 3 market as the U.S. Gulf Coast refined products were not being shipped north. In addition, several environmental mandates took effect in 2005 and 2006, such as the banning of Methyl Tertiary Butyl Ether, or MTBE (an ether produced from the reaction of isobutylene and methanol specifically for use as a gasoline blendstock), in the gasoline pool and initial implementation of the reduced sulfur requirements on diesel fuels, which caused price fluctuations due to logistical and supply/demand implications.

Average discounts for sour and heavy sour crude oil compared to sweet crude increased in 2005 and 2006 from already favorable 2004 levels due to increasing worldwide production of sour and heavy sour crude oil relative to the worldwide production of light sweet crude oil coupled with the continuing demand for light sweet crude oil. In 2004, the average discount for West Texas Sour, or WTS, compared to WTI widened to $3.96 per barrel and again in 2005 to $4.73. With the newly discovered deepwater Gulf of Mexico production combined with the introduction of Canadian sours to the mid-continent this sweet/sour spread continues to exceed average historic levels, as evidenced by the average discount of $5.41 per barrel for the first nine months of 2006. WTI also continues to trade at a premium to WTS due to continued high demand for sweet crude oil resulting from the more stringent fuel specifications implemented both in the United States and globally. We expect to continue to recognize significant benefits from our ability to meet current fuel specifications using predominantly heavy and medium sour crude oil feedstocks to the extent the discount for heavy and medium sour crude oil compared to WTI continues at its current level.

Earnings for our nitrogen fertilizer business 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.

Factors Affecting Results

Petroleum Business

In our petroleum business, earnings and cash flow from operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of, and demand for, crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. While our net sales fluctuate significantly with movements in crude oil prices, these prices do not generally have a direct long-term relationship to net income. Because we apply first-in, first-out, or FIFO, accounting to value our inventory, crude oil price movements may impact net income in the short term because of instantaneous changes in the value of the minimally required, unhedged on hand inventory. The effect of changes in crude oil prices on our results of

operations is influenced by the rate at which the prices of refined products adjust to reflect these changes.

Feedstock and refined product prices are also affected by other factors, such as product pipeline capacity, local market conditions and the operating levels of competing refineries. Crude oil costs and the prices of refined products have historically been subject to wide fluctuations. An expansion or upgrade of our competitors’ facilities, price volatility, international political and economic developments and other factors beyond our control are likely to continue to play an important role in refining industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast. For further details on the economics of refining, see “Industry Overview — Oil Refining Industry.”

In order to assess our operating performance, we compare our net sales, less cost of product sold (refining margin), against an industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil is converted, or cracked, into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of NYMEX gasoline and heating oil against the market value of NYMEX WTI (WTI) crude oil (West Texas Intermediate crude oil, which is used as a benchmark for other crude oils), we refer to the benchmark as the NYMEX 2-1-1 crack spread, or simply, the 2-1-1 crack spread. The 2-1-1 crack spread is expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark production of conventional gasoline and distillate.

Although the 2:1:1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and/or logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI crude oil. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil to the price of WTI crude oil, a light sweet crude oil. The spread is referred to as our consumed crude differential. Our refinery margin can be impacted significantly by the consumed crude differential. Our consumed crude differential will move directionally with changes in the WTS differential to WTI and the Maya differential to WTI as both these differentials indicate the relative price of heavier, more sour slate to WTI. The correlation between our consumed crude differential and published differentials will vary depending on the volume of light medium sour crude and heavy sour crude we purchase as a percent of our total crude volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate. For the nine months ending September 30, 2006 the WTI less Maya crude oil differential was $15.53/barrel per compared to $15.34/barrel for the first nine months of 2005 and the WTI less WTS crude oil differential increased to $5.41 from $4.44 for the same periods, respectively. For the same time period, the Company’s consumed crude differential increased to $4.29/barrel from $2.80/barrel.

The value of our products is also an important consideration in understanding our results. We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices of our products have to be high enough to cover the logistics cost for U.S. Gulf Coast refineries to ship into our region. The result of this logistical advantage and the fact the actual product specification used to determine the NYMEX is different from the actual production in the refinery, is that prices we realize are different than those used in determining the 2:1:1 crack spread. The difference between our price and the price used to calculate the 2:1:1 crack spread is referred to as gasoline PAD II, Group 3 vs. NYMEX basis, or gasoline basis, and heating oil PAD II, Group 3 vs.

NYMEX basis, or heating oil basis. Both gasoline and heating oil basis are greater than zero, which represents that prices in our marketing area exceeds those used in the 2:1:1 crack spread. Since 2003, the heating oil basis has been positive in all periods presented including an increase to $7.90 per barrel for the nine months ending September 30, 2006 from $1.87 per barrel for the nine month period ending September 30, 2005. The increase for the nine months ending September 30, 2006 was significantly impacted by the introduction of Ultra Low Sulfur Diesel. Gasoline basis for the nine months ending September 30, 2006 was $1.88 per barrel compared to ($0.27) per barrel for the nine months ended September 30, 2005. Beginning January 1, 2007, the benchmark used for gasoline will change from Reformulated Gasoline (RFG) to Reformulated Blend for Oxygenate Blend (RBOB). Given that RBOB has limited historical information the change to RBOB from RFG may have an unfavorable impact on our gasoline basis compared to the historical numbers presented.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy and the most important benchmark for energy costs is the value of natural gas. Our predominant variable of direct operating expense is largely energy related and therefore sensitive to the movements of natural gas prices.

Consistent, safe, and reliable operations at our refineries are key to our financial performance and results of operations. Unplanned downtime of our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform the needed maintenance, feedstock logistics and other factors. For example, we have spent significant time planning for our 2007 turnaround. This turnaround is expected to occur in the first quarter of 2007 and is expected to last 40-45 days, including incremental time to complete the expansion projects explained throughout this prospectus. This turnaround will have a significant adverse impact on our first quarter results.

We purchase most of our crude oil using a credit intermediation agreement. Our credit intermediation agreement is structured such that we take title, and the price of the crude oil is set, when it is metered and delivered at Broome Station, which is connected to, and located approximately 22 miles from, our refinery. Once delivered at Broome Station, the crude oil is delivered to our refinery through two of our wholly owned pipelines which begin at Broome Station and end at our refinery. The crude oil is delivered at Broome Station because Broome Station is located near our facility and is connected via pipeline to our facility. The terms of the credit intermediation agreement provide that we will obtain all of the crude oil for our refinery, other than the crude we obtain through our own gathering system, through J. Aron. Once we identify cargos of crude oil and pricing terms that meet our requirements, we notify J. Aron and J. Aron then provides credit, transportation and other logistical services to us for a fee. This agreement significantly reduces the investment that we are required to maintain in petroleum inventories relative to our competitors and reduces the time we are exposed to market fluctuations before the inventory is priced to a customer.

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

Nitrogen Fertilizer Business

In our nitrogen fertilizer business, 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 heavily impacted in terms of cost, by high or volatile swings in natural gas prices. Instead, our adjacent oil refinery primarily supplies our coke feedstock. 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 sell at the floor price, high natural gas prices do not force us to shut down our operations because we employ pet coke as a feedstock to produce ammonia and UAN.

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 our 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 — Nitrogen Fertilizer Industry.”

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 our operating performance, we calculate netbacks, also referred to as plant gate price, to determine our operating margin. Netbacks refer to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, excluding shipment costs. Given our use of low cost pet coke, we are 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, we utilize less than 1% of the natural gas relative to other natural gas-based fertilizer producers and we estimate that we 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 million Btu. The spot price for natural gas at Henry Hub on September 30, 2006 was $5.620 per million Btu.

Because our fertilizer plant has certain logistical advantages relative to end users of ammonia and UAN and so long as demand relative to production remains high, we can afford to target end users in the U.S. farm belt where we incur lower freight costs as compared to 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 transfer, storage, barge freight or pipeline freight charges, giving us a distribution cost advantage over U.S. Gulf Coast importers, assuming freight rates and handling charges for U.S. Gulf Coast importers as in effect in September 2006. The distribution cost advantage represents a significant portion of the market price of these commodities. For example, since the end of 2004, Southern Plains ammonia

prices have fluctuated between $290 and $424 per ton, and Cornbelt UAN prices have fluctuated between $175 and $230 per ton. Selling products to customers in close proximity to our fertilizer plant and keeping transportation costs low are keys to maintaining our profitability.

The value of our nitrogen fertilizer products is also an important consideration in understanding our results. We currently upgrade approximately two-thirds of our ammonia production into UAN, a product that presently generates a greater value for the upgraded ammonia. UAN production is a major contributor to our profitability.

Our direct operating expense structure 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 direct operating expenses include electrical energy, employee labor, maintenance, including contract labor, and outside services. These costs comprise the fixed costs associated with the fertilizer plant. Variable costs associated with the fertilizer plant have averaged approximately 1.9% of direct operating expenses over the last 24 months ending September 30, 2006. The average fixed costs over the last 24 months ending September 30, 2006 have approximated $58 million.

Consistent, safe, and reliable operations at our nitrogen fertilizer plant are critical to our financial performance and results of operations. Unplanned downtime of our 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.

Results of Operations

As discussed in Note 1 to our consolidated financial statements, effective March 3, 2004, Immediate Predecessor acquired the net assets of Original Predecessor in a business combination accounted for as a purchase, and 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 these acquisitions, the consolidated financial statements for the periods after the acquisitions are presented on a different cost basis than that for the periods before the acquisitions and, therefore, are not comparable. However, we believe the most meaningful way to comment on the results of operations 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 nine months ended September 30, 2005 with the nine months ended September 30, 2006.

The following tables provide supplementary income statement and operating data and do not represent income statements presented in accordance with GAAP. Selected items in each of the periods are discussed separately below. Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore are not a sum of only the operating results of our petroleum and nitrogen fertilizer businesses.

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

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

In order to effectively review and assess our historical financial information below, we have included combined columns 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 12 months. The combined columns provide more meaningful information by effectively showing the actual operations of our business.


				Original
				Predecessor		Immediate			Immediate
				and Immediate		Predecessor			Predecessor
	Original			Predecessor		and Successor			and Successor
	Predecessor			Combined		Combined			Combined			Successor
	Year Ended December 31,								Nine Months Ended September 30,
Consolidated Financial Results	2003			2004		2005			2005			2006
	(in millions)

Net sales	$	1,262.2		$	1,741.0	$	2,435.0		$	1,757.3		$	2,329.2
Cost of product sold (exclusive of depreciation and amortization)		1,061.9			1,465.6		1,936.1			1,392.9			1,848.1
Depreciation and amortization		3.3			2.8		25.1			13.0			36.8
Direct operating expenses (exclusive of depreciation and amortization)		133.1			140.4		166.2			117.6			144.5
Selling, general and administrative expense (exclusive of depreciation and amortization)		23.6			21.0		36.8			25.7			32.8
Impairment, (losses) in joint ventures, and other charges(1)		(10.9	)		—		—			—			—

Operating income	$	29.4		$	111.2	$	270.8		$	208.1		$	267.0
Net income (loss)(2)		27.9			60.9		(66.8	)		(200.2	)		170.8
Net income adjusted for unrealized gain or loss from Cash Flow Swap(3)		27.9			60.9		76.0			57.3			122.4


(1)		During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code.


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


			Original
			Predecessor		Immediate		Immediate
			and Immediate		Predecessor		Predecessor
			Predecessor		and Successor		and Successor
	Original		Combined		Combined		Combined
	Predecessor		(non-GAAP)		(non-GAAP)		(non-GAAP)		Successor
	Year Ended December 31,						Nine Months Ended September 30,
	2003		2004		2005		2005		2006
	(in millions)

Impairment of property, plant and equipment(a)	$	9.6	$	—	$	—	$	—	$	—
Loss of extinguishment of debt(b)		—		7.2		8.1		8.1		—
Inventory fair market value adjustment(c)		—		3.0		16.6		16.9		—
Funded letter of credit expense & interest rate swap not included in interest expense(d)		—		—		2.3		1.4		0.2
Major scheduled turnaround expense(e)		—		1.8		—		—
Loss on termination of swap(f)		—		—		25.0		25.0		4.4
Unrealized (gain) loss from Cash Flow Swap		—		—		235.9		427.1		(80.3	)


(a)		During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition.

(b)		Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004 and the write-off of $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005.


(c)		Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory.


(d)		Consists of fees which are expensed to selling, general and administrative expense in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the First Lien Credit Facility and the Second Lien Credit Facility.

(e)		Represents expenses associated with a major scheduled turnaround at our nitrogen fertilizer plant.

(f)		Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005.


(3)		Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. Under these agreements, sales representing approximately 70% and 17% of then forecasted refinery output for the periods from July 2005 through June 2009, and July 2009 through June 2010, respectively, have been economically hedged. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. See “Description of Our Indebtedness and the Cash Flow Swap.”


		We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline, we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for gain or loss from Cash Flow Swap as a key indicator of our business performance and believes that this non-GAAP measure is a useful


		measure for investors in analyzing our business. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.


		Net income adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of performance in evaluating our business. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.


		The following is a reconciliation of Net income adjusted for unrealized gain or loss from Cash Flow Swap to Net income:


			Original
			Predecessor		Immediate			Immediate
			and Immediate		Predecessor			Predecessor
			Predecessor		and Successor			and Successor
	Original		Combined		Combined			Combined
	Predecessor		(non-GAAP)		(non-GAAP)			(non-GAAP)			Successor
	Year Ended December 31,							Nine Months Ended September 30,
	2003		2004		2005			2005			2006
	(in millions)

Net Income adjusted for unrealized gain or loss from Cash Flow Swap	$	27.9	$	60.9	$	76.0		$	57.3		$	122.4
Plus:
Unrealized gain or (loss) from Cash Flow Swap, net of tax benefit		—		—		(142.8	)		(257.5	)		48.4

Net income (loss)	$	27.9	$	60.9	$	(66.8	)	$	(200.2	)	$	170.8

Petroleum Business Results of Operations

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


			Original
			Predecessor		Immediate		Immediate
			and Immediate		Predecessor		Predecessor
			Predecessor		and Successor		and Successor
	Original		Combined		Combined		Combined
	Predecessor		(non-GAAP)		(non-GAAP)		(non-GAAP)		Successor
	Year Ended December 31,						Nine Months Ended September 30,
Petroleum Business Financial Results	2003		2004		2005		2005		2006
	(in millions)

Net sales	$	1,161.3	$	1,632.4	$	2,267.2	$	1,635.4	$	2,205.0
Cost of product sold (exclusive of depreciation and amortization)		1,040.0		1,445.5		1,918.0		1,378.9		1,828.1

Refining margin	$	121.3	$	186.9	$	349.2	$	256.5	$	376.9
Depreciation and amortization		2.1		1.8		16.4		8.5		23.6
Direct operating expenses (exclusive of depreciation and amortization)		80.1		88.2		108.8		75.1		97.3
Operating income		21.5		84.8		199.7		155.8		233.5


			Original
			Predecessor			Immediate			Immediate
			and Immediate			Predecessor			Predecessor
	Original		Predecessor			and Successor			and Successor
	Predecessor		Combined			Combined			Combined			Successor
	Year Ended December 31,								Nine Months Ended September 30,
Market Indicators	2003		2004			2005			2005			2006
	(dollars per barrel)

West Texas Intermediate (WTI) crude oil	$	30.99	$	41.47		$	56.70		$	55.61		$	68.24
NYMEX 2-1-1 Crack Spread		5.53		7.43			11.62			11.57			11.60
Crude Oil Differentials:
WTI less WTS (sour)		2.67		3.96			4.73			4.44			5.41
WTI less Maya (heavy sour)		6.78		11.40			15.67			15.34			15.53
WTI less Dated Brent (foreign)		2.16		3.20			2.18			1.87			1.31
PADD II Group 3 versus NYMEX Basis:
Gasoline		0.62		(0.52	)		(0.53	)		(0.27	)		1.88
Heating Oil		1.11		1.24			3.20			1.87			7.90


			Original
			Predecessor		Immediate		Immediate
			and Immediate		Predecessor		Predecessor
	Original		Predecessor		and Successor		and Successor
	Predecessor		Combined		Combined		Combined		Successor
	Year Ended December 31,						Nine Months Ended September 30,
Company Operating Statistics	2003		2004		2005		2005		2006
	(in millions)

Per barrel profit, margin and expense of crude oil throughput:
Refining margin	$	3.89	$	5.62	$	10.50	$	10.45	$	14.68
Direct operating expenses (exclusive of depreciation and amortization)		2.57		2.65		3.27		3.06		3.79
Per gallon sales price:
Gasoline		0.91		1.19		1.61		1.62		1.99
Distillate		0.84		1.15		1.71		1.62		2.04


					Original
					Predecessor				Immediate				Immediate
					and Immediate				Predecessor and				Predecessor and
	Original				Predecessor				Successor				Successor
	Predecessor				Combined				Combined				Combined				Successor
	Year Ended December 31,												Nine Months Ended September 30,
	2003				2004				2005				2005				2006
	Barrels				Barrels				Barrels				Barrels				Barrels
Selected Company Volumetric Data	Per Day		%		Per Day		%		Per Day		%		Per Day		%		Per Day		%

Production:
Total gasoline		48,230		50.4		48,420		47.1		45,275		43.8		44,241		43.7		46,137		43.1
Total distillate		34,363		35.9		38,104		37.1		39,997		38.7		39,106		38.6		41,401		38.7
Total other		13,108		13.7		16,301		15.9		18,090		17.5		17,997		17.7		19,437		18.2

Total all production		95,701		100.0		102,825		100.0		103,362		100.0		101,344		100.0		106,975		100.0
Crude oil throughput		85,501		93.4		90,787		92.8		91,097		92.6		89,918		93.4		94,061		92.6
All other inputs		6,085		6.6		7,023		7.2		7,246		7.4		6,375		6.6		7,463		7.4

Total feedstocks		91,586		100.0		97,810		100.0		98,343		100.0		96,293		100.0		101,524		100.0


					Original
					Predecessor				Immediate				Immediate
					and Immediate				Predecessor and				Predecessor and
	Original				Predecessor				Successor				Successor
	Predecessor				Combined				Combined				Combined				Successor
	Year Ended December 31,												Nine Months Ended September 30,
	2003				2004				2005				2005				2006
	Total				Total				Total				Total				Total
	Barrels		%		Barrels		%		Barrels		%		Barrels		%		Barrels		%

Crude oil throughput by crude type:
Sweet		18,187,215		58.3		15,232,022		45.8		13,958,567		42.0		11,169,134		45.5		12,916,402		50.3
Light/medium sour		12,311,203		39.4		17,995,949		54.2		19,291,951		58.0		13,378,413		54.5		12,685,293		49.4
Heavy sour		709,300		2.3		—		—		—		—		—		—		77,036		0.3

Total crude oil throughput		31,207,718		100.0		33,227,971		100.0		33,250,518		100.0		24,547,547		100.0		25,678,731		100.0

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).

Net Sales. Petroleum net sales increased $569.6 million, or 35%, to $2,205.0 million in the nine months ended September 30, 2006 from $1,635.4 million in the nine months ended September 30, 2005. This increase resulted from significantly higher product prices ($401.2 million) and increased sales volumes ($168.4 million) over the comparable periods. Our average sales price per gallon for the nine months ending September 30, 2006 for gasoline of $1.99 and distillate of $2.04 increased by 23% and 26%, respectively, as compared to the nine months ended September 30, 2005. Overall sales volumes of refined fuels for the nine months ended September 30, 2006 increased 9% as compared to the nine months ended September 30, 2005. The increased sales volume primarily resulted from higher production levels of refined fuels during the nine months ended September 30, 2006 as compared to the same period in 2005 because of our increased focus on process unit maximization and lower production levels in 2005 due to a scheduled reformer regeneration and minor maintenance in the coker unit and one of our crude units.

2006 was $63.87, compared to $52.32 for the comparable period of 2005, an increase of 22%. Crude oil prices increased on average by 23% during the first nine months of 2006 as compared to the comparable period of 2005 due to the residual impact of Hurricanes Katrina and Rita on the refining sector, geopolitical concerns and strong demand for refined products. Sales volume of refined fuels increased 9% for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. In addition, under our FIFO accounting method, changes in crude oil prices can cause significant fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease. For the nine months ended September 30, 2006, we reported FIFO inventory gains of $13.0 million compared to FIFO inventory gains of $29.2 million for the comparable period of 2005.

Refining margin per barrel of crude throughput increased from $10.45 for the nine months ended September 30, 2005 to $14.68 for the nine months ended September 30, 2006, due to increased discount for sour crude oils demonstrated by the $0.97, or 22%, increase in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the WTS price, which is an indicator for the price of sour crude, in the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. In addition, positive regional differences between refined fuel prices in our primary marketing region (the Coffeyville supply area) and those of the NYMEX, known as basis, significantly contributed to the dramatic increase in our consumed crack spread in the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. The average distillate basis for the nine months ended September 30, 2006 increased by $6.03 per barrel to $7.90 per barrel compared to $1.87 per barrel in the comparable period of 2005. The average gasoline basis in the nine months ended September 30, 2006 increased by $2.15 per barrel to $1.88 per barrel in comparison to a negative basis of $0.27 per barrel in the comparable period of 2005.

Depreciation and Amortization. Petroleum depreciation and amortization increased by $15.1 million to $23.6 million in the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. The increase was primarily the result of the step-up in our property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses exclusive of depreciation and amortization were $97.3 million for the nine months ended September 30, 2006, an increase of $22.2 million, or 30%, as compared to direct operating expenses of $75.1 million for the comparable period of 2005. This increase was the result of increases in expenses associated with direct labor ($1.8 million), environmental compliance ($2.4 million), operating materials ($1.8 million), repairs and maintenance ($7.3 million), chemicals ($1.6 million), energy and utilities ($3.7 million) and outside services ($1.0 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude throughput for the nine months ending September 30, 2006 increased to $3.79 per barrel as compared to $3.06 per barrel for the nine months ending September 30, 2005.

Operating Income. Petroleum operating income increased $77.7 million, or 50%, to $233.5 million in the nine months ended September 30, 2006 from $155.8 million in the comparable period of 2005. This increase primarily resulted from higher refining margin due to improved NYMEX crack spreads, improved crude differentials and strong gasoline and distillate basis during the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. The increase in operating income was somewhat offset by expenses associated with direct labor ($1.8 million), environmental compliance ($2.4 million), operating materials ($1.8 million), repairs and maintenance ($7.3 million), chemicals ($1.6 million), energy and utilities ($3.7 million), outside services ($1.0 million) and depreciation and amortization ($15.1 million).

Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).

Net Sales. Petroleum net sales increased $634.8 million, or 39%, to $2,267.2 million in the year ended December 31, 2005 from $1,632.4 million in the year ended December 31, 2004. This revenue increase was primarily attributable to increases in product prices ($688.3 million) offset by reduced sales volumes ($53.5 million) as compared to 2004. As compared to 2004, sales prices of gasoline and distillates increased 35% and 49%, respectively. Sales prices increased primarily as a result of increased crude oil prices and improvements in the gasoline and distillate crack spreads. The increase in average refined product prices was partially offset by a 3% decrease in refined fuels sales volume due to a 1% reduction in refined fuels production volumes in 2005 as compared to 2004. Refined fuels production was negatively impacted in 2005 due to a scheduled reformer regeneration and an outage in the fluidized catalytic cracking unit at our Coffeyville refinery.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold exclusive of depreciation and amortization increased by $472.5 million, or 33%, to $1,918 million in the year ended December 31, 2005 from $1,445.5 million in the year ended December 31, 2004. This increase was primarily the result of higher crude oil prices partially offset by lower sales volumes and the impact of FIFO accounting. Our average cost per barrel of crude oil for the year ended December 31, 2005 was $53.42, compared to $40.23 for the same period in 2004, an increase of 33%. Crude oil prices increased significantly in 2005 as compared to 2004 due to the impact of Hurricanes Katrina and Rita, geopolitical concerns and strong demand for refined products in 2005. Sales volume decreased 3.0% for the year ended December 31, 2005 as compared to 2004. In addition, under our FIFO accounting method, changes in crude oil prices can cause significant fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease. For the year ended December 31, 2005, we reported FIFO inventory gains of $18.6 million compared to FIFO inventory gains of $9.2 million for the comparable period of 2004.

Refining margin per barrel of crude throughput increased from $5.62 for the year ended December 31, 2004 to $10.50 for the year ended December 31, 2005, due to historically high differentials between refined fuel prices and crude oil prices as exemplified in the average NYMEX crack spread of $11.62 per barrel for the year ended December 31, 2005 as compared to $7.43 per barrel for 2004. Increased discount for heavy crude oils demonstrated by the $4.27, or 37%, increase in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the Maya price, which is an indicator for the price of heavy crude, in the year ended December 31, 2005 compared to the same period in 2004 also contributed to the increased refining margin over the comparable period. In addition to the widening of the NYMEX crack spread and the increase in crude differentials, positive regional differences between refined fuel prices in our primary marketing region (PADD II, Group 3) and those of the NYMEX, known as basis, also contributed to the dramatic increase in our consumed crack spread in the year ended December 31, 2005 as compared to 2004. The average distillate basis for the year ended December 31, 2005 increased $1.96 per barrel to $3.20 per barrel as compared to $1.24 per barrel for the comparable period of 2004. The average gasoline basis for the year ended December 31, 2005 as compared to the year ended December 31, 2004 was essentially flat at a negative basis of $0.53 per barrel as compared to a negative basis of $0.52 per barrel in 2004.

Depreciation and Amortization. Petroleum depreciation and amortization increased by $14.6 million to $16.4 million in the year ended December 31, 2005 as compared to the year ended December 31, 2004. The increase was primarily the result of the step-up in our property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses increased by $20.6 million to $108.8 million, or 23%, for the year ended December 31, 2005 as compared to direct operating expenses of $88.2 million in 2004. This increase was the result of increases in expenses associated with labor and incentive bonuses ($2.2 million), environmental compliance ($2.5 million), repairs and maintenance ($9.1 million), chemicals ($1.9 million), energy and utilities (1.9 million) and outside services ($1.9 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude throughput for 2005 increased to $3.27 per barrel as compared to $2.65 per barrel for 2004.

Operating Income. Petroleum operating income increased $114.9 million, or 136%, to $199.7 million in the year ended December 31, 2005 from $84.8 million in the year ended December 31, 2004. This increase primarily resulted from higher refining margin due to favorable market conditions in the domestic refining industry somewhat offset by a 3% decrease in sales volumes and increases in expenses associated with labor and incentive bonuses ($2.2 million), environmental compliance ($2.5 million), repairs and maintenance ($9.1 million), chemicals ($1.9 million), energy and utilities ($1.9 million), outside services ($1.9 million) and depreciation and amortization ($14.6 million).

Year Ended December 31, 2004 (Non-GAAP combined) Compared to Year Ended December 31, 2003.

Net Sales. Petroleum net sales increased $471.1 million, or 41%, to $1,632.4 million in the year ended December 31, 2004 from $1,161.3 million in the year ended December 31, 2003. This revenue increase was attributable to increased production volumes ($83.2 million) and higher product prices ($387.9 million), which reacted favorably to the increase in global crude oil prices over the period. In 2004, crude oil throughput increased by an average of 5,286 bpd, or 6%, as compared to 2003. The higher crude throughput experienced in 2004 as compared to 2003 was directly attributable to Farmland’s inability, because of its impending reorganization, to purchase optimum crude oil blends necessary to operate the refinery at 2004 levels in 2003. During 2004, our petroleum business experienced increases in gasoline and distillate prices of 31% and 37%, respectively, as compared to the same period in 2003.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold includes cost of crude oil, other feedstocks and blendstocks, purchased products for resale, transportation and distribution costs. Petroleum cost of product sold exclusive of depreciation and amortization increased by $405.5 million, or 39%, to $1,445.5 million in the year ended December 31, 2004 from $1,040.0 million in the year ended December 31, 2003. This increase was attributable to strong differentials between refined products prices and crude oil prices as exemplified in the average NYMEX crack spread of $7.43 per barrel for the year ended December 31, 2004 as compared to $5.53 per barrel in the comparable period of 2003. Increased discount for heavy crude oils demonstrated by the $4.62, or 68%, increase in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the Maya price, which is a market indicator for the price of heavy crude, in the year ended December 31, 2004 as compared to the same period in 2003 also contributed to the increase in refining margin over the comparable periods. Diluting the positive impact of the widening of the NYMEX crack spread and the increased crude differentials was the negative impact of gasoline prices in our primary marketing area (PADD II, Group 3) in comparison to gasoline prices on the NYMEX, known as basis. The average gasoline basis for the year ended December 31, 2004 decreased $1.14 per barrel to a negative basis of $0.52 per barrel as compared to $0.62 per barrel for 2003. The average distillate basis for the year ended December 31, 2004 was $1.24 per barrel compared to $1.11 per barrel in 2003. Additionally, our refining margin for the year ended December 31, 2004 improved as a result of the termination of a single customer product marketing agreement in November 2003. During 2003 Farmland was party to a marketing agreement

that required it to sell all refined products to a single customer at a fixed differential to an index price. Subsequent to the conclusion of the contract, we have expanded our customer base and increased the realized differential to that index.

Depreciation and Amortization. Petroleum depreciation and amortization decreased by $0.3 million to $1.8 million in the year ended December 31, 2004 as compared to the year ended December 31, 2003. The decrease was primarily the result of the petroleum assets’ useful lives being reset to longer periods in the Initial Acquisition as compared to the prior period based on management’s assessment of the condition of the petroleum assets acquired, offset by the impact of the step-up in value of the acquired assets in the Initial Acquisition.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Petroleum operations include costs associated with the actual operations of our refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance, labor and environmental compliance costs. Petroleum direct operating expenses exclusive of depreciation and amortization increased by $8.1 million, or 10%, to $88.2 million in 2004 from $80.1 million in the corresponding period of 2003, primarily due to expenses associated with environmental compliance ($1.1 million), repairs and maintenance ($2.8 million), chemicals ($2.3 million) and energy and utilities ($3.3 million). These increases were offset by a $2.4 million reduction in rent expense. Direct operating expenses per barrel of crude throughput for the year ended December 31, 2004 increased by $0.08 per barrel compared to direct operating expenses per barrel of crude throughput of $2.57 in 2003.

Operating Income. Petroleum operating income increased $63.3 million, or 294%, to $84.8 million in the year ended December 31, 2004 from $21.5 million in the year ended December 31, 2003. This increase primarily resulted from higher refining margin due to improved conditions in the domestic refining industry and a 6% increase in sales volumes. The increase in operating income was somewhat offset by increases in expenses related to environmental compliance ($1.1 million), repairs and maintenance ($2.8 million), chemicals ($2.3 million) and energy and utilities ($3.3 million).

Nitrogen Fertilizer Business Results of Operations


			Original
			Predecessor		Immediate		Immediate
			and Immediate		Predecessor		Predecessor
	Original		Predecessor		and Successor		and Successor
	Predecessor		Combined		Combined		Combined		Successor
Nitrogen Fertilizer	Year Ended December 31,						Nine Months Ended September 30,
Business Financial Results	2003		2004		2005		2005		2006
	(in millions)

Net sales	$	100.9	$	112.9	$	173.0	$	125.9	$	128.2
Cost of product sold (exclusive of depreciation and amortization)		21.9		24.5		23.6		18.3		23.8
Depreciation and amortization		1.2		1.0		8.7		4.5		12.7
Direct operating expenses (exclusive of depreciation and amortization)		53.0		52.2		57.5		42.5		47.2
Operating income		7.8		26.4		71.0		52.0		34.1


	Year Ended						Nine Months
	December 31,						Ended September 30,
Market Indicators	2003		2004		2005		2005		2006

Natural gas (dollars per million Btu)	$	5.49	$	6.18	$	9.01	$	7.75	$	6.89
Ammonia — southern plains (dollars per ton)		274		297		356		328		360
UAN — corn belt (dollars per ton)		143		171		212		205		198


				Original
				Predecessor			Immediate			Immediate
				and Immediate			Predecessor			Predecessor
	Original			Predecessor			and Successor			and Successor
	Predecessor			Combined			Combined			Combined			Successor
	Year Ended December 31,									Nine Months Ended September 30,
Company Operating Statistics	2003			2004			2005			2005			2006

Production (thousand tons):
Ammonia		335.7			309.2			413.2			311.3			283.9
UAN		510.6			532.6			663.3			495.7			465.0

Total		846.3			841.8			1,076.5			807.0			748.9
Sales (thousand tons)(1):
Ammonia		134.8			103.9			141.8			102.4			96.8
UAN		528.9			541.6			646.5			487.4			477.7

Total		663.7			645.5			788.3			589.8			574.5
Product pricing (plant gate) (dollars per ton)(1):
Ammonia	$	235		$	266		$	324		$	305		$	346
UAN		107			136			173			172			169
On-stream factor(2):
Gasification		90.1	%		92.4	%		98.1	%		98.3	%		91.7	%
Ammonia		89.6	%		79.9	%		96.7	%		96.7	%		87.8	%
UAN		81.6	%		83.3	%		94.3	%		94.8	%		87.9	%
Capacity utilization:
Ammonia(3)		83.6	%		76.8	%		102.9	%		103.7	%		94.5	%
UAN(4)		93.3	%		97.0	%		121.2	%		121.0	%		113.6	%
Reconciliation to net sales (dollars in thousands):
Freight in revenue	$	12,535		$	11,429		$	15,010		$	11,140		$	13,860
Sales net plant gate		88,373			101,439			157,989			114,798			114,295

Total net sales		100,908			112,868			172,999			125,938			128,155


(1)		Plant gate sales per ton represents net sales less freight revenue divided by sales tons. Plant gate pricing per ton is shown in order to provide industry comparability.

(2)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.

(3)		Based on nameplate capacity of 1,100 tons per day.

(4)		Based on nameplate capacity of 1,500 tons per day.

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).

Net Sales. Nitrogen fertilizer net sales increased $2.3 million, or 2%, to $128.2 million for the nine months ended September 30, 2006 as compared to net sales of $125.9 million for the nine months ended September 30, 2005. This increase was the result of increases in selling prices ($6.1 million) offset by a reduction in overall sales volumes ($3.9 million) of our fertilizer products as compared to the nine months ended September 30, 2005.

In regard to product sales volumes for the nine months ended September 30, 2006, our nitrogen operations experienced a decrease of 6% in ammonia sales unit volumes (5,590 tons) and a decrease of 2% in UAN sales unit volumes (9,727 tons). The decrease in ammonia and UAN sales volumes was the result of decreased production volumes over the nine months ended September 30, 2006 relative to the comparable period due to the scheduled turnaround at our fertilizer plant during July 2006. 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 plant and UAN plant) were less than the comparable period primarily due to the scheduled turnaround in July 2006 and downtime in the ammonia plant 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 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. Plant gate prices for the nine months ended September 30, 2006 for ammonia were greater than plant gate prices for the comparable period of 2005 by 13%. In contrast to ammonia, UAN prices decreased for the nine month period ended September 30, 2006 as compared to the nine months ended September 30, 2005 by 2%. These strong 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.

The demand for fertilizer 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.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased by $8.2 million to $12.7 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. This increase was primarily the result of the step-up in property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Nitrogen fertilizer operations include costs associated with the actual operations of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct operating expenses exclusive of depreciation and amortization for the nine months ended September 30, 2006 increased to $47.2 million, or 11%, as compared to $42.5 million for the nine months ended September 30, 2005. This increase was primarily the result of increases in repairs and maintenance ($0.6 million), turnaround expenses ($2.6 million), outside services ($0.7 million), and utilities ($0.9 million), partially offset by a reduction in catalyst expenses ($0.6 million).

Operating Income. Nitrogen fertilizer operating income decreased $17.9 million, or 34%, to $34.1 million in the nine months ended September 30, 2006 from $52.0 million for the nine months ended September 30, 2005. This decrease was the result of reduced sales volumes, increased direct

operating expenses related to repairs and maintenance ($0.6 million), turnaround expenses ($2.6 million), outside services ($0.7 million), and utilities ($0.9 million), partially offset by a reduction in catalyst expenses ($0.6 million) and higher ammonia prices.

Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).

Net Sales. Nitrogen fertilizer net sales increased $60.1 million, or 53%, to $173.0 million for the year ended December 31, 2005 as compared to net sales of $112.9 million for the year ended December 31, 2004. This increase was the result of increases in both sales volumes ($33.2 million) and selling prices of ammonia and UAN ($26.9 million) as compared to 2004.

In regard to product sales volumes for the year, nitrogen fertilizer experienced an increase of 36% in ammonia sales unit volumes (37,949 tons) and an increase of 19% in UAN sales unit volumes (104,982 tons) as compared to 2004. The increases in both ammonia and UAN sales were due to improved on-stream factors for all units of the nitrogen operations (gasifier, ammonia plant and UAN plant) in 2005 as compared to 2004. On-stream factors in 2004 were negatively impacted during September 2004 by additional downtime from a scheduled turnaround, which resulted from delay in start-up associated with projects completed during the turnaround and outages in the ammonia plant to repair a damaged heat exchanger.

The demand for fertilizer 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 their current liquidity, soil conditions, weather patterns and the types of crops planted.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased by $7.7 million to $8.7 million in the year ended December 31, 2005 as compared to the year ended December 31, 2004. This increase was primarily the result of the step-up in property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our Nitrogen fertilizer operations include costs associated with the actual operations of our nitrogen plant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen fertilizer direct operating expenses exclusive of depreciation and amortization in 2005 increased to $57.5 million, or 10%, as compared to $52.2 million in 2004. This increase was primarily the result of increases in labor ($1.9 million), outside services ($1.4 million), and energy and utilities costs ($3.8 million), partially offset by reductions in turnaround expenses ($1.8 million) and catalyst expense ($1.6 million).

Operating Income. Nitrogen fertilizer operating income increased $44.6 million, or 169%, to $71.0 million in the year ended December 31, 2005 from $26.4 million in the year ended December 31,

2004. This increase was due to improved sales volume and nitrogen fertilizer pricing that resulted from improved on-stream factors for the nitrogen plant and strong market conditions in the nitrogen fertilizer business. These positive factors were partially offset by increased direct operating expenses due to increases in labor ($1.9 million), outside services ($1.4 million), and energy and utilities costs ($3.8 million).

Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.

Net Sales. Nitrogen fertilizer net sales increased $12.0 million, or 12%, to $112.9 million in 2004 from $100.9 million in 2003. This revenue increase was entirely attributable to increased nitrogen fertilizer prices ($18.8 million), which more than offset a slight decline in total sales volume ($6.8 million) due to a planned turnaround in August 2004. For 2004, southern plains ammonia and corn belt UAN prices increased 8% and 20%, respectively, as compared to the comparable period in 2003. In addition, due to our direct marketing efforts, our actual plant gate prices, relative to the market indices presented above improved substantially. Plant gate prices for the year ended December 31, 2004 for ammonia and UAN were greater than the comparable period in 2003 by 13% and 27%, respectively. Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver the product. We believe the 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. The improvement in plant gate price relative to the market index was the result of eliminating the reseller discount offered under the terms of our prior marketing agreement and maximizing shipments to customers that were more freight logical to our facility.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold exclusive of depreciation and amortization is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2004 increased to $24.5 million, or 12%, as compared to $21.9 million in 2003. The increase was primarily the result of the recognition of the cost of pet coke after the Initial Acquisition as compared to a zero value transfer during the Original Predecessor period. Subsequent to the Initial Acquisition in 2004 the nitrogen fertilizer business was charged $4.3 million for pet coke transferred from our petroleum business. During the Original Predecessor period, pet coke was transferred at zero value.

Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization decreased by $0.2 million, or 17%, to $1.0 million in 2004 from $1.2 million in 2003. This decrease was principally due to the nitrogen fertilizer assets’ useful lives being reset to longer periods in the Initial Acquisition period compared to the prior period based on management’s assessment of the condition of the nitrogen fertilizer assets acquired offset by the impact of the step-up in value of the acquired nitrogen fertilizer assets in the Initial Acquisition.

Operating Income. Nitrogen fertilizer operating income increased $18.6 million, or 239%, to $26.4 million in 2004 from $7.8 million in 2003. This increase was due to improved market conditions and pricing in the domestic nitrogen fertilizer industry and a decrease in direct operating expenses. The improvement in operating income was negatively impacted subsequent to the Initial Acquisition in

2004 as the nitrogen fertilizer business was charged $4.3 million for pet coke transferred from our petroleum business. During the Original Predecessor period, pet coke was transferred at zero value.

Consolidated Results of Operations

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).

Net Sales. Consolidated net sales increased $571.9 million, or 33%, to $2,329.2 million in the nine months ended September 30, 2006 from $1,757.3 million for the nine months ended September 30, 2005. This increase was primarily due to an increase in petroleum net sales of $569.6 million that resulted from significantly higher product prices ($401.2 million) and increased sales volumes ($168.4 million) over the comparable periods. Nitrogen fertilizer net sales increased $2.3 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005 due to increased selling prices ($6.1 million) partially offset by a reduction in overall sales volumes ($3.9 million).

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold exclusive of depreciation and amortization increased by $455.2 million, or 33%, to $1,848.1 million for the nine months ended September 30, 2006 from $1,392.9 million for the nine months ended September 30, 2005. This increase was primarily due to an increase in crude oil prices, sales volumes and the impact of FIFO accounting in our petroleum business. Our fertilizer business accounted for approximately $5.5 million of the increase in cost of products sold over the comparable periods primarily related to increases in freight and distribution expense.

Depreciation and Amortization. Consolidated depreciation and amortization increased by $23.8 million to $36.8 million for the nine months ended September 30, 2006 from $13.0 million for the nine months ended September 30, 2005. This increase was due to an increase in petroleum depreciation and amortization of $15.1 million and an increase in nitrogen fertilizer depreciation and amortization of $8.2 million.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses exclusive of depreciation and amortization increased by $26.9 million, or 23%, to $144.5 million for the nine months ended September 30, 2006 from $117.6 million for the nine months ended September 30, 2005. This increase was due to an increase in petroleum direct operating expenses of $22.2 million and an increase in nitrogen fertilizer direct operating expenses of $4.7 million.

Operating Income. Consolidated operating income increased by $58.9 million, or 28%, to $267.0 million for the nine months ended September 30, 2006 from $208.1 million for the nine months ended September 30, 2005. Petroleum operating income increased $77.7 million and nitrogen fertilizer operating income decreased by $17.9 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses increased $7.1 million, or 28%, to $32.8 million for the nine months ended September 30, 2006 from $25.7 million for the nine months ended September 30, 2005. Consolidated selling, general and administrative expenses for the nine months ended September 30, 2005 were negatively impacted by certain expenses associated with $3.3 million of unearned compensation related to the management equity of Immediate Predecessor in relation to the Subsequent Acquisition. Adjusting for this expense, consolidated selling, general and administrative expenses increased $10.4 million for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005. This variance was primarily the result of increases in administrative labor ($1.4 million), office costs ($0.9 million), insurance costs associated with Successor’s $1.25 billion property insurance limit requirement ($1.3 million), letter of credit fees due under our $150.0 million funded letter of credit facility utilized as

collateral for the Cash Flow Swap which was not in place for approximately six months in the comparable period ($2.4 million), public relations expense ($0.5 million) and outside services expense ($2.6 million).

Interest Expense. We reported consolidated interest expense for the nine months ended September 30, 2006 of $33.0 million as compared to interest expense of $20.0 million for the nine months ended September 30, 2005. This 65% increase for the nine months ended September 30, 2006 as compared to the nine months ended September 30, 2005 was the direct result of increased borrowings associated with our current borrowing facility completed in association with the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) and an increase in the actual rate of our borrowings due to increases both in index rates (LIBOR and prime rate) and applicable margins. The comparability of interest expense during the comparable periods has been impacted by the differing capital structures of Successor and Immediate Predecessor periods. See “— Factors Affecting Comparability.”

Interest Income. Interest income increased $2.1 million, or 300%, from $0.7 million in the nine months ended September 30, 2005 to $2.8 million in the nine months ended September 30, 2006 due to larger cash balances and higher yields on invested cash.

Gain (loss) on Derivatives. For the nine months ended September 30, 2006, we reported $44.7 million in gains on derivatives. This compares to a $494.7 million loss on derivatives during the comparable period of 2005. This significant change in gain (loss) on derivatives was primarily attributable to our Cash Flow Swap and the accounting treatment for all of our derivative transactions. We determined that the Cash Flow Swap and our other derivative instruments do not qualify as hedges for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Since the Cash Flow Swap had a significant term remaining as of September 30, 2006 (approximately three years and nine months) and the NYMEX crack spread that is the basis for the underlying swap contracts that comprised the Cash Flow Swap had declined substantially during this period, the unrealized gains on the Cash Flow Swap increased significantly. The $494.7 million loss on derivatives during the nine months ended September 30, 2005 is inclusive of the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins. At closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless, which resulted in the expensing of the associated premium in the nine months ended September 30, 2005. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

Other Income (Expense). For the nine months ended September 30, 2006, other income (expense) increased $1.1 million to $0.3 million from a loss of $0.8 million for the comparable period of 2005. This change was primarily the result of asbestos related accruals, which resulted in other expense during the nine months ending September 30, 2005.

Provision for Income Taxes. Income tax expense for the nine months ended September 30, 2006 was $111.0 million, or 39.4% of earnings before income taxes, as compared to a tax benefit of $114.7 million for the nine months ended September 30, 2005. The effective tax rate for 2005 was impacted by a realized loss on option agreements that expired unexercised. Coffeyville Acquisition LLC was party to these agreements and the loss was incurred at that level which we effectively treated as a permanent non-deductible loss.

Net Income. For the nine months ended September 30, 2006, net income increased $371.0 million to $170.8 million as compared to a net loss of $200.2 million in the nine months ended September 30, 2005, primarily due to improved operating income in our Petroleum operations and a significant change in the value of the Cash Flow Swap over the comparable periods.

Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).

Net Sales. Consolidated net sales increased $694.0 million, or 40%, to $2,435.0 million in the year ended December 31, 2005 from $1,741.0 million for the year ended December 31, 2004. This increase was primarily due to an increase in petroleum net sales of $634.8 million that resulted from increased refined product prices ($688.3 million) offset by reduced sales volumes ($53.5 million) as compared to 2004. Also contributing to the increase in net sales during the comparable periods was a $60.1 million increase in nitrogen fertilizer net sales primarily driven by increase in both sales volumes ($33.2 million) and selling prices of ammonia and UAN ($26.9 million).

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold exclusive of depreciation and amortization increased by $470.5 million, or 32%, to $1,936.1 million for the year ended December 31, 2005 from $1,465.6 million for the year ended December 31, 2004. This increase was primarily due to increased crude oil prices partially offset by lower sales volumes and the impact of FIFO inventory valuation.

Depreciation and Amortization. Consolidated depreciation and amortization increased by $22.3 million to $25.1 million for the year ended December 31, 2005 from $2.8 million for the year ended December 31, 2004. This increase was due to an increase in petroleum depreciation and amortization of $14.6 million and in nitrogen fertilizer depreciation and amortization of $7.7 million primarily the result of a step-up in property, plant and equipment for the Subsequent Acquisition. See “Factors Affecting Comparability.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses exclusive of depreciation and amortization increased by $25.8 million, or 18%, to $166.2 million for the year ended December 31, 2005 from $140.4 million for the year ended December 31, 2004. This increase was due to an increase in petroleum direct operating expenses of $20.6 million and an increase in nitrogen fertilizer direct operating expenses of $5.3 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses increased $15.8 million, or 75.2%, to $36.8 million for the year ended December 31, 2005 from $21.0 million for the year ended December 31, 2004. This increase was primarily the result of increases in insurance costs associated with Successor’s $1.25 billion property insurance limit requirement, letter of credit fees due under our $150.0 million funded letter of credit facility utilized as collateral for the Cash Flow Swap which was not in place in the prior period, management fees, discretionary bonuses and the write-off of unearned compensation associated with the Subsequent Acquisition.

Operating Income. Consolidated operating income increased by $159.6 million, or 144%, to $270.8 million for the year ended December 31, 2005 from $111.2 million for the year ended December 31, 2004. Petroleum operating income increased $114.9 million and nitrogen fertilizer operating income increased by $44.6 million.

Interest Expense. Consolidated interest expense for the year ended December 31, 2005 was $32.8 million as compared to interest expense of $10.1 million for the year ended December 31, 2004. This 225% increase for 2005 was the direct result of increased borrowings in 2005 associated with our current borrowing facility completed in association with the Subsequent Acquisition (See “— Liquidity and Capital Resources — Debt”) and an increase in the actual rate of our borrowings due to both increases in index rates (LIBOR and prime rate) and applicable margins. The comparability of

2005 and 2004 interest expense has been impacted by the differing capital structures of Successor, Immediate Predecessor and Original Predecessor. See “— Factors Affecting Comparability.”

Interest Income. Interest income increased $1.3 million, or 650%, from $0.2 million in the year ended December 31, 2004 to $1.5 million in the year ended December 31, 2005, due to larger cash balances and higher yields on invested cash.

Gain (loss) on Derivatives. For the year ended December 31, 2005, we reported $323.7 million in losses on derivatives. This compared to a $0.5 million gain on derivatives during 2004. This dramatic increase in losses on derivatives was primarily attributable to our Cash Flow Swap and the accounting treatment for all of our derivative transactions. We determined that the Cash Flow Swap and our other derivative instruments do not qualify as hedges for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the year ended December 31, 2005 included both the realized and the unrealized losses on all derivatives. Since the Cash Flow Swap had a significant term remaining as of December 31, 2005 (approximately four years) and the NYMEX crack spread that is the basis for the underlying swap contracts that comprised the Cash Flow Swap had improved substantially, the unrealized losses on the Cash Flow Swap increased significantly as of December 31, 2005. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, resulted in unrealized losses of $229.8 million for 2005. Realized losses on derivative transaction comprised the balance of the losses for 2005 or $93.9 million. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

Extinguishment of Debt. On June 24, 2005 and in connection with the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC (see “— Factors Affecting Comparability”), we raised $800.0 million in long-term debt commitments under the First Lien Credit Facility and the Second Lien Credit Facility. As a result of the retirement of Immediate Predecessor’s outstanding indebtedness consisting of $150.0 million term loan and revolving credit facilities, we recognized $8.1 million as a loss on extinguishment of debt in 2005. This compares to a loss on extinguishment of debt of $7.2 million for the year ended December 31, 2004. On May 10, 2004, we used proceeds from a $150.0 million term loan to pay off our then existing debt which was originally incurred on March 3, 2004. In connection with the extinguishment of debt, we recognized $7.2 million as a loss on extinguishment of debt in the 304 day period ended December 31, 2004.

Other Income (Expense). For the year ended December 31, 2005, other income (expense) decreased $1.4 million to an expense of $1.3 million from income of $0.1 million in 2004. This decrease was primarily the result of asbestos related accruals in 2005.

Provision for Income Taxes. Our income tax benefit in the year ended December 31, 2005 was ($26.9 million), or 28.7% of loss before income tax, as compared to $33.8 million in 2004. The effective tax rate for 2005 was impacted by a realized loss on option agreements that expired unexercised. Coffeyville Acquisition LLC was the party to these agreements and the loss was incurred at that level which we effectively treated as a permanent non-deductible loss, therefore generating a lower effective tax rate on the net loss for the year.

Net Income. For the year ended December 31, 2005, net income decreased $127.7 million to a loss of $66.8 million as compared to net income of $60.9 million in 2004, primarily due to losses on derivatives offset by improved margins in the year ending December 31, 2005 as compared to 2004.

Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.

Net Sales. Consolidated net sales increased $478.8 million, or 38%, to $1,741.0 million in the year ended December 31, 2004 from $1,262.2 million for the year ended December 31, 2003. The increase was primarily due to an increase in petroleum net sales of $471.1 million due to both increased sales volumes ($83.2 million) and increased refined product prices ($387.9 million).

Nitrogen fertilizer net sales increased $12.0 million in the year ended December 31, 2004 as compared to the year ended December 31, 2003 as a result of improved nitrogen fertilizer prices ($18.8 million), offset by a decline in overall fertilizer sales volume ($6.8 million).

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold exclusive of depreciation and amortization increased by $403.7 million, or 38%, to $1,465.6 million for the year ended December 31, 2004 from $1,061.9 million for the year ended December 31, 2003. This increase was primarily due to an increase in crude oil costs and increased crude throughput in our Petroleum business for the year ended December 31, 2004 as compared to the year ended December 31, 2003. Nitrogen fertilizer cost of product sold also increased in the comparable periods primarily due to the recognition of the cost of pet coke after the Initial Acquisition as compared to zero value transfer during the Original Predecessor period.

Depreciation and Amortization. Consolidated depreciation and amortization decreased by $0.5 million, or 15%, to $2.8 million for the year ended December 31, 2004 from $3.3 million for the year ended December 31, 2003. This decrease was due to a decrease in petroleum depreciation and amortization of $0.3 million and a decrease in nitrogen fertilizer depreciation and amortization of $0.2 million.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses exclusive of depreciation and amortization increased by $7.3 million, or 6%, to $140.4 million for the year ended December 31, 2004 from $133.1 million for the year ended December 31, 2003. The increase was primarily due to an increase in petroleum direct operating expenses of $8.1 million. This increase in the petroleum business was partially offset by a decrease in nitrogen fertilizer direct operating expenses of $0.8 million.

Operating Income. Consolidated operating income increased by $81.8 million, or 278%, to $111.2 million for the year ended December 31, 2004 from $29.4 million for the year ended December 31, 2003. Petroleum operating income increased $63.3 million and nitrogen fertilizer operating income increased by $18.6 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization, Reorganization Expenses and Interest Expense. Consolidated selling, general and administrative expenses for the period from March 2, 2004 through December 31, 2004 were $16.3 million. These expenses represented the cost associated with corporate governance, legal expenses, treasury, accounting, marketing, human resources and maintaining corporate offices in New York and Kansas City. During the predecessor periods, Farmland allocated corporate overhead based on internal needs, which may not have been representative of the actual cost to operate the businesses. In addition, during the year ended December 31, 2003, Farmland incurred a number of charges related to its bankruptcy. As a result of the charges and issues related to allocations, a comparison of selling, general and administrative expenses for the year ended December 31, 2004 to the year ended December 31, 2003 is not meaningful.

Extinguishment of Debt. On May 10, 2004, we used proceeds from a $150.0 million dollar term loan to pay off our then existing debt which was originally incurred on March 3, 2004. In connection with the extinguishment of debt, we recognized $7.2 million as a loss on extinguishment of debt in the 304 day period ended December 31, 2004.

Provision for Income Taxes. Original Predecessor was not a separate legal entity, and its operating results were included with the operating results of Farmland and its subsidiaries in filing consolidated federal and state income tax returns. Farmland did not allocate income taxes to its divisions. As a result, Original Predecessor periods do not reflect any provision for income taxes.

Net Income. Net income increased $33.0 million in 2004 to $60.9 million from $27.9 million for the comparable period in 2003. This increase was due to both the change in ownership and improved results in both the petroleum business and the nitrogen fertilizer business.

Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the Notes to our audited Financial Statements included elsewhere in this prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.

Impairment of Long-Lived Assets

During 2001, Farmland accounted for long-lived assets in accordance with SFAS No. 121, Accounting for Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of. SFAS No. 121 was superseded by SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, which was adopted by Farmland effective January 1, 2002.

In accordance with both SFAS No. 144 and SFAS No. 121, Farmland reviewed its long-lived assets for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeded its estimated future undiscounted net cash flows, an impairment charge was recognized by the amount by which the carrying amount of the assets exceeded the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying value or fair value less cost to sell, and are no longer depreciated.

In its Plan of Reorganization, Farmland stated, among other things, its intent to dispose of its petroleum and nitrogen fertilizer assets. Despite this stated intent, these assets were not classified as held for sale under SFAS 144 until October 7, 2003 because, ultimately, any disposition must be approved by the bankruptcy court and the bankruptcy court did not approve such disposition until that date. Since Farmland determined that it was more likely than not that its assets would be disposed of, those assets were tested for impairment in 2002 pursuant to SFAS 144, using projected undiscounted net cash flows. Based on Farmland’s best assumptions regarding the use and eventual disposition of those assets, primarily from indications of value received from potential bidders in the bankruptcy sales process, the assets were determined to exceed the fair value expected to be received on disposition by approximately $375.1 million. Accordingly, an impairment charge was recognized for that amount in 2002. The ultimate proceeds from disposition of these assets were decided in a bidding and auction process conducted in the bankruptcy proceedings. In 2003, as a result of receiving a bid from Coffeyville Resources, LLC, Farmland revised its estimate of the amount to be generated from the disposition of these assets and an additional impairment charge of $9.6 million was taken in the year ended December 31, 2003.

As of September 30, 2006, net property, plant and equipment totaled $928.2 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.

Derivative Instruments and Fair Value of Financial Instruments

We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long term-debt. Although management considers these derivatives economic hedges, the Cash Flow Swap and our other derivative instruments do not qualify as hedges for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair

values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The Company recorded net gains (losses) from derivative instruments of ($323.7 million) and $44.7 million in gain (loss) on derivatives for the fiscal year ended December 31, 2005 and the nine months ended September 30, 2006.

As of September 30, 2006, a $1.00 change in quoted prices for the crack spreads utilized in the Cash Flow Swap would result in a $71.2 million change to the fair value of derivative commodity position and the same change to net income.

Environmental Expenditures

Liabilities related to future remediation of contaminated properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted as new facts or changes in law or technology occur. Environmental expenditures are capitalized when such costs provide future economic benefits. Changes in laws, regulations or assumptions used in estimating these costs could have a material impact to our financial statements. The amount recorded for environmental obligations at September 30, 2006 totaled $7.4 million, including $1.8 million included in current liabilities.

Share-Based Compensation

We estimated fair value of units for all applicable periods as described below.

At March 3, 2004, we determined the per unit value of the Original Predecessor common units by assessing the fair value of the preference components associated with the preferred units based on expected future cash flows of the business and subtracting that value from the total fair value of our equity to arrive at a fair value of the residual interests of the preferred and common units.

In addition to voting rights, the holders of the preferred units, who contributed all the cash into the Original Predecessor on the acquisition date, were entitled to a return of their contributed capital plus a 15% per annum preferred yield on any outstanding unreturned contributed capital. In determining the value that the preferred unit holders transferred to the common unit holders, rather than applying a waterfall method which would have resulted in no value, we applied a discounted cash flow analysis based on a range of potential earnings outcomes and assumptions. The percent of equity value transferred from the preferred unit holders to the common unit holders was based on the discounted cash flow analysis after giving effect to the preference obligations, including the 15% per annum preferred yield. Changes in assumptions such as discount rates, prices or operating plant operating conditions used to determine the forecasted cash flows used in the valuation could have a material impact on the percent of equity value allocated to the common units. In preparing the discounted cash flow analysis, the product sales price assumptions used for the fertilizer and refinery products assumed sustained prices for a five-year period at historically high levels.

In connection with its refinancing on May 10, 2004, we had obtained independent third party appraisals for the refinery and the nitrogen fertilizer plant property, plant and equipment. Taking into account the third party appraisals, we calculated an equity value for the business. The appraisals included market approach valuations and income approach valuations in the form of a discounted cash flow. The discounted cash flow analysis included assumptions for product sales prices consistent with readily available forward market indicators and reflected existing plant performance measures. Changes in assumptions such as discount rates, prices or operating plant operating conditions used to determine the forecasted cash flows used in the valuation could have a material impact on the equity value. Given the refinancing allowed us to settle the preference obligations, the equity value resulting from the appraisal was allocated pro rata to all unit holders for the 74,852,941

shares outstanding subject to a discount of 8% attributed to the common units for the non-voting status.

For the 141–day period ended September 30, 2005, the 233–day period ended December 31, 2005 and the nine month period ended September 30, 2006, we account for share-based compensation in accordance with Statement of Financial Accounting Standards (SFAS) No. 123(R), Share-Based Payments. SFAS 123(R) requires that compensation costs relating to share-based payment transactions be recognized in a company’s financial statements. SFAS 123(R) applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments.

In accordance with SFAS 123(R), we apply a fair-value-based measurement method in accounting for share-based override units and phantom points. See “Management–Employment Agreements, Separation and Consulting Agreement and Other Arrangements.” Override units are equity classified awards measured using the grant date fair value with compensation expense recognized over the respective vesting period. Phantom points are liability classified awards marked to market based on their fair value at the end of each reporting period with compensation expense recognized over the respective vesting period.

At June 24, 2005 an independent third party appraisal for the refinery and the nitrogen fertilizer plant were obtained. Additionally, an independent appraisal process occurred at that time, to value the management common units that were subject to redemption and our override value units, override operating units and phantom points. The Monte Carlo method of valuation was utilized to value the override operating units, override value units and phantom points that were issued on June 24, 2005.

In addition, an independent appraisal process occurs each reporting period in order to revalue the management common units and phantom points. The significant assumptions that are used each reporting period to value the phantom and performance service points are: (1) estimated forfeiture rate; (2) explicit service period or derived service period as applicable, (3) grant-date fair value–controlling basis; (4) marketability and minority interest discounts and (5) volatility.

For the independent valuations that occurred as of December 31, 2005, June 30, 2006 and September 30, 2006, a Binomial Option Pricing Model was utilized to value the phantom points. Probability-weighted values that were determined in this independent valuation process were discounted to determine the present value of the units. Prospective financial information is utilized in the valuation process. A discounted cash flow method, a variation of the income approach, and a guideline company method, which is a variation of a market approach is utilized to value the management common units.

There is considerable judgment in the determination of the significant assumptions used in determining the fair value for our share based compensation. Changes in these assumptions could result in material changes in the amounts recognized as compensation expense in our consolidated financial statements. For example, if we increased volatility or projected undiscounted future cash flows, or decreased the discount rate or marketability and minority discounts, the measurement date fair value of the override units and the phantom points could materially increase, which could materially increase the amount of compensation expense recognized in our consolidated financial statements.

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.

Income Taxes

Income tax expense is estimated based on the projected effective tax rate based upon future tax return filings. The amounts anticipated to be reported in those filings may change between the time the financial statements are prepared and the time the tax returns are filed. Further, because tax filings are subject to review by taxing authorities, there is also the risk that a position on a tax return may be challenged by a taxing authority. If the taxing authority is successful in asserting a position different than that taken by us, differences in a tax expense or between current and deferred tax items may arise in future periods. Any of these differences which could have a material impact on our financial statements would be reflected in the financial statements when management considers them probable of occurring and the amount reasonably estimatable.

Valuation allowances reduce deferred tax assets to an amount that will more likely than not be realized. Management’s estimates of the realization of deferred tax assets is based on the information available at the time the financial statements are prepared and may include estimates of future income and other assumptions that are inherently uncertain. No valuation allowance is currently recorded, as we expect to realize our deferred tax assets.

Liquidity and Capital Resources

Our principal sources of liquidity are from cash and cash equivalents, cash from operations and borrowings under Coffeyville Resources, LLC’s senior secured credit facilities.

Cash Balance and Other Liquidity

As of September 30, 2006, we had cash, cash equivalents and short-term investments of $38.1 million. We believe our September 30, 2006 cash levels, together with the availability of borrowings under our revolving loan facilities and the proceeds we receive from this offering, will be adequate to fund our cash requirements based on our current level of operations for at least the next twelve months. As of September 30, 2006, we had available up to $93.6 million under our revolving loan facilities, which are discussed in more detail below.

Debt

On June 24, 2005 and in conjunction with the Subsequent Acquisition, we completed a recapitalization of Successor with a new First Lien Credit Facility and a new Second Lien Credit Facility. The First Lien Credit Facility was for an aggregate commitment not to exceed $525.0 million and the Second Lien Credit Facility consisted of a $275.0 million term loan. The First Lien Credit Facility consisted of $225.0 million of tranche B term loans; $50.0 million of delayed draw term loans; a $100.0 million revolving loan facility; and a $150.0 million funded letter of credit facility issued in support of the Cash Flow Swap. The primary borrower under the First Lien Credit Facility is our subsidiary, Coffeyville Resources, LLC. The First Lien Credit Facility matures on June 23, 2012, is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including equity of our subsidiaries on a first lien priority basis.

The tranche B term loan, initially $225 million, is subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on October 1, 2005 and increasing to 23.5% of the outstanding principal balance on October 1, 2011, with a final payment of the aggregate

outstanding balance on June 23, 2012. To date, we have made all of the quarterly principal amortization payments under this term loan.

The delayed draw term loans of $50.0 million are available for drawing through December 2006. We obtained the delayed draw term loan commitment to fund a portion of the capital requirements for two specific petroleum business capital projects: the continuous catalytic reformer and the fluidized catalytic cracking unit. As of June 24, 2005, the estimated cost to complete these projects was approximately $140.0 million with the difference between the delayed draw term commitment and the estimated project costs being funded by incremental equity contributions to Successor or other cash from operations under certain conditions. The delayed draw term loan is subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on the last date of the first quarter following the delayed draw term loan termination date or the date on which the delayed draw term loans have been fully funded through June 24, 2011. Thereafter, the delayed draw term loans are amortized in equal quarterly installments until June 24, 2012. To date, we have made all of the quarterly principal amortization payments under the delayed draw term loans. As of September 30, 2006, we have used $30.0 million of the delayed draw term loan.

The revolving loan facility of $100.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving loan facility are subject to a $50.0 million sub-limit. The revolving loan commitment matures on June 24, 2011. The borrower has an option to extend this maturity upon written notice to the lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is June 24, 2012. As of September 30, 2006, we had available $93.6 million under the revolving credit facility.

The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into a credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time upon written notice to the lenders.

In addition to the First Lien Credit Facility, our subsidiary Coffeyville Resources, LLC also entered into the Second Lien Credit Facility on June 24, 2005 for $275.0 million. The Second Lien Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including equity of our subsidiaries on a second lien priority basis. The Second Lien Credit Facility is not subject to scheduled principal amortization; however, the principal outstanding is due and payable upon final maturity on June 24, 2013.

The net proceeds from the tranche B term loan of $225.0 million, second lien term loans of $275.0 million, $12.6 million of revolving loan facilities and a $227.7 million equity contribution from Coffeyville Acquisition LLC were utilized to fund the following upon the closing of the Subsequent Acquisition:


	•	$685.8 million for cash proceeds to Immediate Predecessor ($1,038.9 million of assets acquired less $353.1 million of liabilities assumed), including $12.6 million of legal, accounting, advisory, transaction and other expenses associated with the Subsequent Acquisition;

	•	$49.6 million of other fees and expenses related to the Subsequent Acquisition; and

	•	$4.9 million of cash to fund our operating accounts.

The First Lien Credit Facility was subsequently amended and restated on June 29, 2006 under substantially the same terms as the June 24, 2005 agreement. The tranche B term loans were refinanced into tranche C term loans. The primary reason for the amendment and restatement was to reduce the applicable margin spreads for borrowings on the first lien term loans and the funded letter of credit facility.

The amended and restated First Lien Credit Facility incorporated the following pricing by facility type:


	•	Tranche C term loans and delayed draw term loans bear interest at either LIBOR plus 2.25%, or at the borrower’s election, the prime rate plus 1.25% (with step-downs to LIBOR plus 2.00% or the prime rate plus 1%, respectively, upon achievement of certain rating conditions).


	•	Revolving loan facility borrowings bear interest at either LIBOR plus 2.50% or, at the borrower’s election, the prime rate plus 1.50% (with step-downs to LIBOR plus 2.25% or the prime rate plus 1.25%, respectively, and then to LIBOR plus 2.00% or the prime rate plus 1%, respectively, upon certain prepayments of the term loans and substantial completion of certain capital expenditure projects).

	•	Letters of credit issued under the $50.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% owing to the issuing lender.

	•	Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit.

Prior to the June 2006 amendment, the Tranche B term loans (as replaced by the Tranche C term loans), had an interest rate at LIBOR plus 2.50%. All other applicable rates remained the same.

In addition to the fees stated above, the amended and restated First Lien Credit Facility requires the borrower to pay 0.50% in commitment fees on the unused portion of the revolving loan facility and 1.00% in commitment fees on the unused portion of the delayed draw term loan commitment.

The Second Lien Credit Facility borrowings bear interest at LIBOR plus 6.75% or, at the borrower’s option, the prime rate plus 5.75%.

The First Lien Credit Facility and the Second Lien Credit Facility require the borrower to prepay outstanding loans, subject to certain exceptions, with:


	•	100% of the net asset sale proceeds received from specified asset sales and net insurance/condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations;


	•	100% of the cash proceeds from the incurrence of specified debt obligations; and


	•	75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that this percentage will be reduced to 50% when the term loan repayment amount is at least $150.0 million.

Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, fifth to cash collateralize revolving letters of credit and funded letters of credit and sixth to the second lien term loan under the Second Lien Credit Facility. Voluntary prepayments of loans under the First Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty. This offering will not trigger a mandatory prepayment of the First Lien Credit Facility.

Voluntary prepayments of loans under the Second Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, so long as no amounts are outstanding under the First Lien Credit Facility or unless the lenders under the First Lien Credit Facility provide the requisite consent. Similarly, mandatory prepayments of loans under the Second Lien Credit Facility apply only after no amounts are outstanding under the First Lien Credit Facility. Any voluntary prepayments, as well as mandatory prepayments with the cash proceeds from the incurrence of specified debt obligations, made with respect to the Second Lien Credit Facility after July 8, 2006 but before July 8, 2007 are subject to a 2.0% prepayment premium and any voluntary prepayments made after July 8, 2007 but before July 8, 2008 are subject to a 1.0% prepayment premium.

Both the First Lien Credit Facility and the Second Lien Credit Facility contain customary covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and shareholders, change the business conducted by the credit parties, and enter into hedging agreements. The agreements provide that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from June 24, 2005. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap, the management agreements with the Goldman Sachs Funds and the Kelso Funds, or the May 2005 stock purchase agreement, without the prior written approval of the lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.

In particular, the agreements require the borrower to maintain certain financial ratios as follows:

Second Lien

First Lien Credit Facility

Credit Facility

Minimum

Maximum

interest

leverage

Fiscal quarter ending

coverage ratio

ratio

September 30, 2006

2.25:1.00

5.00:1.00

5.25:1.00

December 31, 2006

2.25:1.00

5.00:1.00

5.25:1.00

March 31, 2007

2.25:1.00

4.75:1.00

5.00:1.00

June 30, 2007

2.50:1.00

4.50:1.00

4.75:1.00

September 30, 2007

2.75:1.00

4.25:1.00

4.75:1.00

December 31, 2007

3.00:1.00

3.50:1.00

4.00:1.00

March 31, 2008

3.25:1.00

3.50:1.00

4.00:1.00

June 30, 2008

3.25:1.00

3.75:1.00

September 30, 2008

3.25:1.00

3.00:1.00

3.50:1.00

December 31, 2008

3.25:1.00

2.75:1.00

3.25:1.00

March 31, 2009 and thereafter

3.50:1.00

2.50:1.00

3.00:1.00

The computation of these ratios is governed by the specific terms of the credit agreements and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general, under the terms of our credit agreements, consolidated adjusted EBITDA is calculated by adding consolidated net income, consolidated interest expense, income taxes, depreciation and amortization,

other non-cash expenses, any fees and expenses related to acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests and major scheduled turnaround expenses.

We present consolidated adjusted EBITDA because it is a material component of material covenants within our current credit agreements. However, consolidated adjusted EBITDA is not a defined term under GAAP and should not be considered as an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the First Lien Credit Facility and Second Lien Credit Facility as follows:


			Original
			Predecessor		Immediate
			and Immediate		Predecessor
			Predecessor		and Successor			Immediate
	Original		Combined		Combined			Predecessor
	Predecessor		(non-GAAP)		(non-GAAP)			and Successor
								Combined						Successor
								(non-GAAP)			Successor			(non-GAAP)

														Twelve Months
								Nine Months Ended						Ended
	Year Ended December 31,							September 30,						September 30,
Consolidated Financial Results	2003		2004		2005			2005			2006			2006
			(unaudited)		(unaudited)			(unaudited)						(unaudited)
					(in millions)
Net income (loss)	$	27.9	$	60.9	$	(66.8	)	$	(200.2	)	$	170.8		$	304.2
Plus:
Depreciation and amortization		3.3		2.8		25.1			13.0			36.8			48.9
Interest expense		1.3		10.1		32.8			20.0			33.0			45.8
Income tax expense (benefit)		—		33.8		(26.9	)		(114.7	)		111.0			198.8
Impairment of property, plant and equipment		9.6		—		—			—			—			—
Loss on extinguishment of debt		—		7.2		8.1			8.1			—			—
Inventory fair market value adjustment		—		3.0		16.6			16.9			—			(0.3	)
Funded letters of credit expenses and interest rate swap not included in interest expense		—		—		2.3			1.4			0.2			1.1
Major scheduled turnaround expense		—		1.8		—			—			4.4			4.4
Loss on termination of Swap		—		—		25.0			25.0			—			—
Unrealized (gain) or loss on hedge derivatives		—		—		229.8			421.7			(81.6	)		(273.5	)

Non-cash compensation expense for equity awards		—		1.1		1.8			1.3			2.3			2.8
(Gain) or loss on disposition of fixed assets		—		—		—			—			1.2			1.2
Expenses related to acquisition		—		—		3.5			3.5			—			—
Management fees		—		0.5		2.3			1.7			1.6			2.2

Consolidated Adjusted EBITDA	$	42.1	$	121.2	$	253.6		$	197.7		$	279.7		$	335.6

In addition to the financial covenants summarized in the table above, the First Lien Credit Facility restricts the borrower’s capital expenditures to $230.0 million in 2006, $70.0 million in 2007 and $40.0 million in 2008 and each year thereafter. The capital expenditures are measured based on actual capital expenditures excluding the continuous catalytic reformer and fluidized catalytic crack unit projects and include a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The continuous catalytic reformer and fluidized catalytic cracking unit projects are subject to their own specific capital expenditure limitation of $165.0 million. The limitations on our capital expenditures imposed by the First Lien Credit Facility allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our First Lien Credit Facility.

The First Lien Credit Facility and the Second Lien Credit Facility also contain customary events of default. The events of default include the failure to pay interest and premium when due, including

fees and any other amounts owed under the credit agreements, a breach of certain covenants under the credit agreements, a breach of any representation or warranty contained in the credit agreements, any default under any of the documents entered into in connection with the credit agreements, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, events relating to employee benefit plans resulting in liability in excess of $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, a change in control, the guarantees, collateral documents or the credit agreements failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the credit agreements to have a lien on any material portion of the collateral, and any party under the credit agreements (other than the agent or lenders under the credit agreements) contesting the validity or enforceability of the credit agreements.

The credit agreements are subject to an intercreditor agreement between the lenders of both credit agreements and the Cash Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.

At September 30, 2006, funded long-term debt, including current maturities, totaled $222.8 million of tranche C term loans, $30.0 million of delayed draw term loans and $275.0 million of second lien term loans. Other commitments included a $150.0 million funded letter of credit facility and a $100.0 million revolving credit facility. As of September 30, 2006, the commitments outstanding on the revolving loan facilities were $3.2 million in letters of credit issued in support of certain environmental obligations and $3.2 million in letters of credit to secure transportation services for a crude oil pipeline.

We are required to measure our compliance with the financial ratios and other required metrics under the first and second lien credit agreements on a quarterly basis and we were in compliance with those ratios as of September 30, 2006. As of September 30, 2006, our minimum interest coverage ratio was 6.49:1 and our maximum leverage ratio was 1.51:1, in each case as such ratios are defined and calculated in the first and second lien credit agreements.

Capital Spending

We divide our capital spending needs into two categories: non-discretionary, which is either capitalized or expensed, and discretionary, which is capitalized. Non-discretionary 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 regulations. We estimate that our total non-discretionary capital spending needs, including turnaround expenses, will be approximately $152 million in 2006, approximately $99 million in 2007 and approximately $159 million in the aggregate over the three-year period beginning 2008. These estimates include, among other items, the capital costs necessary to comply with environmental regulations, including Tier II gasoline standards and on-road diesel regulations. As described above, our credit facilities limit the amount we can spend on capital expenditures.

We estimate that compliance with the Tier II gasoline and on-road diesel standards will require us to spend approximately $98 million during 2006 (most of which has already been spent), approximately $18 million during 2007 and approximately $25 million between 2008 and 2010. See “Business — Environmental Matters — Fuel Regulations — Tier II, Low Sulfur Fuels.”

The following table sets forth our estimate of our non-discretionary spending for the years presented as of September 30, 2006:


											Cumulative
											Through
	2006		2007		2008		2009		2010		2010
	(in millions)

Environmental capital needs	$	113.1	$	39.4	$	9.1	$	12.7	$	42.7	$	217.0
Sustaining capital needs		28.7		21.9		16.6		16.1		20.0		103.3

Subtotal	$	141.8	$	61.3	$	25.7	$	28.8	$	62.7	$	320.3
Turnaround expenses		10.5		38.0		5.5		3.0		32.9		89.9

Total estimated non-discretionary spending	$	152.3	$	99.3	$	31.2	$	31.8	$	95.6	$	410.2

We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields, and/or a reduction in direct operating expenses. As of September 30, 2006, we had committed approximately $170 million towards discretionary capital spending in 2006.

Cash Flows

Comparability of cash flows from operating activities for the nine months ended September 30, 2006 and 2005 and the years ended December 31, 2005, 2004 and 2003 has been impacted by the Initial Acquisition and the Subsequent Acquisition. See “Factors Affecting Comparability.” Therefore, we have presented our discussion of cash flows from operations by comparing (1) the nine months ending September 30, 2006 with the 174 days ended September 23, 2005 and the 141 days ended September 30, 2005, (2) the 233 days ended December 31, 2005, the 174 days ended September 23, 2005, the 304 days ended December 31, 2004 and the 62 days ended March 2, 2004 and (3) the year ended December 31, 2003, the 62 days ended March 2, 2004, and the 304 days ended December 31, 2004.

We believe that the most meaningful way to comment on cash flows from investing and financing activities is to compare the sum of the combined cash flows for the nine months ended September 30, 2006 and 2005 and the twelve months ended December 31, 2005 and 2004.

Operating Activities

Comparison of Nine Months Ended September 30, 2006, the 174 Days Ended June 23, 2005 and the 141 Days Ended September 30, 2005.

Comparability of cash flows from operating activities for the nine months ended September 30, 2006 and the nine months ended September 30, 2005 has been impacted by the Initial Acquisition and the Subsequent Acquisition. See “— Factors Affecting Comparability.” For instance, completion of the Subsequent Acquisition by Successor 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. Therefore, the discussion of cash flows from operations has been broken down into three separate periods: the nine months ending September 30, 2006, the 174 days ended June 23, 2005 and the 141 days ended September 30, 2005.

Net cash flows from operating activities for the nine months ended September 30, 2006 was $97.9 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other assets and liabilities, partially offset by unfavorable changes in trade working capital and other working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts

receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. See “— Consolidated Results of Operations — Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).” We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the nine months ended September 30, 2006 included both the realized losses and the unrealized gains on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of September 30, 2006 (approximately three years and nine months) and the NYMEX crack spread that is the basis for the underlying swaps had declined substantially, the unrealized gains on the Cash Flow Swap significantly increased our Net Income over this period. The impact of these unrealized gains on the Cash Flow Swap is apparent in the $88.5 million decrease in the payable to swap counterparty. Reducing our operating earnings for the nine months ended September 30, 2006 was a $37.0 million use of cash related to an increase in trade working capital. For the nine months ending September 30, 2006, accounts receivable decreased approximately $23.1 million while inventory increased $59.8 million. The primary reason for the increase in inventory relates to the increased unit volumes in inventory and also overall price increases in the related crude oil and refined product inventory. Other primary uses of cash during the period include a $16.5 million increase in prepaid expenses and other current assets and a $16.6 million reduction in accrued income taxes. Offsetting these uses of cash was a $57.5 million increase in deferred income taxes primarily the result of the unrealized gain on the Cash Flow Swap.

Net cash flows from operating activities for the 174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by strong income of $52.4 million, offset by a $54.3 million increase in trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.

Net cash flows provided by operating activities for the 141 days ended September 30, 2005 was $63.3 million. The positive cash flow from operating activities during this period was primarily the result of strong operating earnings during the period partially offset by the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins and the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. At the closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless and thus resulted in the expensing of the associated premium. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and “— Consolidated Results of Operations — Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).” We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the nine months ended September 30, 2005 included the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap became effective July 1, 2005 and had an original term of approximately five years and the NYMEX crack spread that is the basis for the underlying swaps had improved since the trade date of the Cash Flow Swap on June 16, 2005, the unrealized losses on the Cash Flow Swap significantly reduced our net income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $466.7 million increase in the payable to swap counterparty. Additionally and as a result of the closing of the Subsequent Acquisition, Successor marked up the value 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. The total impact of this for the 141 days ended September 30, 2005 was $14.3 million. Trade working capital provided

$4.5 million in cash during the 141 days ended September 30, 2005 as an increase in accounts receivable was more than offset by decreases in inventory and an increase in accounts payable. Offsetting the sources of cash from operating activities highlighted above was a $175.6 million use of cash related to deferred income taxes.

Comparison of the 233 Days Ended December 31, 2005, the 174 Days Ended June 23, 2005, the 304 Days Ended December 31, 2004 and the 62 Days Ended March 2, 2004.

Comparability of cash flows from operating activities for the year ended December 31, 2005 to the year ended December 31, 2004 has been impacted by the Initial Acquisition and the Subsequent Acquisition. See “— Factors Affecting Comparability.” Immediate Predecessor did not assume the accounts receivable or the accounts payable of Farmland. As a result, Farmland collected and made payments on these accounts after March 3, 2004 and these transactions are not included on our consolidated statements of cash flows. In addition, Coffeyville Acquisition LLC’s acquisition of the subsidiaries of Coffeyville Group Holdings, LLC required a mark up of purchased inventory to fair market value at the closing of the Initial Acquisition on June 24, 2005. This had the effect of reducing overall cash flow for Coffeyville Acquisition LLC as it capitalized that portion of the purchase price of the assets into cost of product sold. Therefore, the discussion of cash flows from operations has been broken down into four separate periods: the 233 days ended December 31, 2005, the 174 days ended June 23, 2005, the 304 days ended December 31, 2004 and the 62 days ended March 2, 2004.

Net cash flows for operating activities for the 233 days ended December 31, 2005 was $82.5 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other working capital over the period. 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. The net income for the period was not indicative of the excellent operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. See “— Consolidated Results of Operations — Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).” We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the 233 days ended December 31, 2005 included both the realized and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2005 (approximately four and one-half years) and the NYMEX crack spread that is the basis for the underlying swaps had improved substantially, the unrealized losses on the Cash Flow Swap significantly reduced our Net Income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $256.7 million unrealized loss in the period related to the increase in the payable to swap counterparty. Contributing to the sources of cash for operating activities during the period was a decrease of trade working capital of $8.0 million and an increase in both deferred revenue and other current liabilities of $10.0 million and $10.5 million, respectively. Primary uses of cash during the period were related to increases in prepaid expenses of $6.5 million due to increases in insurance and other prepaids and an increase in deferred income taxes associated with purchase price accounting for the transaction of $98.4 million.

Net cash flows for operating activities for the 174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by income of $52.4 million, offset by a $54.3 million increase in trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.

Net cash flow from operating activities for the 304 days ended December 31, 2004 was $89.8 million. The primary driver for the positive cash flow from operations over this period was cash earnings and favorable changes in trade working capital. During this period, we experienced favorable market conditions in our petroleum and nitrogen fertilizer businesses. Changes in trade working capital produced cash flow of approximately $27.6 million during this period. For the 304 days ended December 31, 2004, we experienced a $20.1 million decrease in inventory due to an effort to reduce inventory carrying levels and a $31.1 million increase in accounts payable due to the extension of credit terms by several crude oil vendors and a large electricity vendor. These positive cash flows from operations were partially offset by an increase in accounts receivable of $23.6 million as Immediate Predecessor assumed ownership of the business from Farmland. In addition, changes in other working capital generated approximately $8.7 million in cash during the period. This was primarily the result of increases in other current liabilities by $13.0 million as a result of accruals for personnel, taxes other than income taxes, leases, freight and professional services, offset by reductions in certain prepaid expenses.

Net cash from operating activities for the 62 days ended March 2, 2004 was $53.2 million. The positive cash flow generated over this period was primarily driven by cash earnings and favorable changes in other working capital of $34.4 million. With respect to other working capital, $25.7 million in cash resulted from reductions in prepaid expenses and other current assets due to the reduction in prepaid crude oil required by Farmland due to the Initial Acquisition by Coffeyville Group Holdings, LLC and $8.3 million of deferred revenue resulting primarily from prepaid fertilizer contract activity of our nitrogen fertilizer operations. The $6.5 million of cash flows generated from trade working capital was mainly the result of a $19.6 million decrease in accounts receivable due to the collection of a large petroleum account, which had been past due.

Comparison of the Year Ended December 31, 2003, the 62 Days Ended March 2, 2004 and the 304 Days Ended December 31, 2004.

Comparability of cash flows from operating activities for the year ended December 31, 2004 to 2003 has been impacted by the closing of the Initial Acquisition on March 3, 2004. We did not assume the accounts receivable or the accounts payable of Farmland. As a result, Farmland collected and made payments on these accounts after March 3, 2004 and these transactions are not included on our consolidated statements of cash flows. Therefore, this discussion of the cash flow from operations has been separated into three periods: the year ended December 31, 2003, the 62 days ended March 2, 2004 and the 304 days ended December 31, 2004.

Net cash flow from operating activities for the 304 days ended December 31, 2004 was $89.8 million. The primary driver for the positive cash flow from operations over this period was cash earnings and favorable changes in trade working capital. 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. During this period, we experienced favorable market conditions in our petroleum and nitrogen fertilizer businesses. Changes in trade working capital produced cash flow of approximately $27.6 million during this period. For the 304 days ended December 31, 2004, we experienced a $20.1 million decrease in inventory due to an effort to reduce inventory carrying levels and a $31.1 million increase in accounts payable due to the extension of credit terms by several crude oil vendors and a large electricity vendor. These positive cash flows from operations were partially offset by an increase in accounts receivable of $23.6 million as Immediate Predecessor assumed ownership of the business from Farmland. In addition, changes in other working capital generated approximately $8.7 million in cash during the period. This was primarily the result of increases in other current liabilities by $13.0 million as a result of accruals for personnel, taxes other than income taxes, leases, freight and professional services, offset by reductions in certain prepaid expenses.

Net cash flow from operating activities for the 62 days ended March 2, 2004 was $53.2 million. The positive cash flow generated over this period was primarily driven by cash earnings and favorable

changes in other working capital of $34.4 million. With respect to other working capital, $25.7 million in cash resulted from reductions in prepaid expenses and other current assets due to the reduction in prepaid crude oil required by Farmland due to the Initial Acquisition by Coffeyville Group Holdings, LLC and $8.3 million of deferred revenue resulting primarily from prepaid fertilizer contract activity of our nitrogen fertilizer operations. The $6.5 million of cash flows generated from trade working capital was mainly the result of a $19.6 million decrease in accounts receivable due to the collection of a large petroleum account, which had been past due.

Net cash flow from operating activities for the year ended December 31, 2003 was $20.3 million. The positive cash flow from operations over this period was directly attributable to cash earnings offset by unfavorable changes in trade and other working capital. The positive cash earnings were the result of an improvement in the environment for both our petroleum and nitrogen fertilizer businesses versus the prior period. The $6.6 million cash outflow resulting from changes in trade working capital was primarily attributable to a $25.3 million increase in accounts receivable due to the delinquency of a large petroleum customer. This increase in accounts receivable was partially offset by a reduction in inventory by $10.4 million and an $8.3 million increase in accounts payable. The increase in other working capital of $21.8 million was primarily driven by a $23.8 million increase in prepaid expenses and other current assets directly attributable to the necessity for Farmland to prepay its crude oil supply during its bankruptcy.

Investing Activities

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).

Net cash used in investing activities for the nine months ended September 30, 2006 was $173.0 million compared to $709.5 million for the nine months ended September 30, 2005. Investing activities for the nine months ended September 30, 2006 was the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures. Investing activities for the nine months ended September 30, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the nine months ended September 30, 2005 was approximately $24.4 million in capital expenditures.

Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).

Net cash used in investing activities for the year ended December 31, 2005 was $742.6 million as compared to $130.8 million in 2004. Both periods included acquisition costs associated with successive owners of the assets. Investing activities for the year ended December 31, 2005 included the $685.1 million related to the Subsequent Acquisition. Investing activities for the year ended December 31, 2004 included the $116.6 million acquisition of our assets by Immediate Predecessor from Original Predecessor on March 3, 2004. The other primary use of cash for investing activities was $57.4 million for capital expenditures in 2005 as compared to $14.2 million for 2004. This increase in capital expenditures was primarily the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures.

Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.

Net cash used in investing activities for 2004 was $130.8 million compared to $0.8 million in 2003. This difference is directly attributable to an increase in capital expenditures and the acquisition of the Farmland assets during the comparable periods. Throughout its bankruptcy, Farmland maintained capital expenditures for its petroleum and nitrogen assets at a minimum.

Financing Activities

Nine Months Ended September 30, 2006 Compared to Nine Months Ended September 30, 2005 (Non-GAAP Combined).

Net cash provided by financing activities in the nine months ended September 30, 2006 was $48.5 million as compared to $660.8 million for the nine months ended September 30, 2005. The primary sources of cash for the nine months ended September 30, 2006 were $20.0 million of additional equity contributions into Coffeyville Acquisition LLC, which was subsequently contributed to our operating subsidiaries, and $30.0 million of additional delayed draw term loans. These sources of cash were specifically generated to fund a portion of two discretionary capital expenditures at our petroleum operations. During this period, we also paid $1.7 million of scheduled principal payments on the first lien term loans. The primary sources of cash for the nine months ended September 30, 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $237.7 million of equity. Additional sources of funds during the nine months ending September 30, 2005 were obtained through the borrowing of $0.2 million in revolving loan proceeds, net of $69.6 million of repayments. Offsetting these sources of cash from financing activities during the nine months ending September 30, 2005 were $24.4 million in deferred financing costs associated with the first and second lien debt commitments raised by Successor in connection with the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) and a $52.2 million cash distribution to Immediate Predecessor prior to the Subsequent Acquisition.

Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).

Net cash provided by financing activities in the year ended December 31, 2005 was $660.0 million as compared to $40.4 million in 2004. The primary sources of cash for 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $227.7 million of equity. Additional equity of $10.0 million was contributed into Coffeyville Acquisition LLC subsequent to the aforementioned acquisition, which was subsequently contributed to our operating subsidiaries, in order to fund a portion of two discretionary capital expenditures at our refining operations. Offsetting these sources of cash from financing activities during the year ended December 31, 2005 were $24.7 million in deferred financing costs associated with the first and second lien debt commitments raised by Coffeyville Acquisition LLC in connection with the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) and a $52.2 million cash distribution to the owners of Coffeyville Group Holdings, LLC prior to the Subsequent Acquisition.

The uses of cash for financing activities in the year ended December 31, 2004 related primarily to the prepayment of the $23.0 million term loan, a $100.0 million cash distribution to the holders of the preferred and common units issued by Coffeyville Group Holdings, LLC, $1.2 million repayment of a capital lease obligation, $16.3 million in financing costs and $53.2 million in net divisional equity distribution to Farmland. We used cash from operations, a $63.3 million equity contribution related to the Initial Acquisition and a new term loan for $150.0 million completed on May 10, 2004 to finance the aforementioned cash outflows in 2004.

Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.

Net cash provided by financing activities in 2004 was $40.4 million. The uses of cash for financing activities over this period related primarily to the prepayment of the $23.0 million term loan, a $100.0 million cash distribution to the holders of the preferred and common units issued by Coffeyville Group Holdings, LLC, $1.2 million repayment of a capital lease obligation, $16.3 million in financing costs and $53.2 million in net divisional equity distribution to Farmland. We used cash from operations, a $63.3 million equity contribution related to the Initial Acquisition and a new term loan for

$150.0 million completed on May 10, 2004 to finance the aforementioned cash outflows in 2004. In 2003, we used $19.5 million in cash to fund a net divisional equity distribution.

Prior to the Initial Acquisition, our petroleum and nitrogen fertilizer businesses were organized as divisions within Farmland. As such, these divisions did not have a discreet legal structure from Farmland and the cash flows from these operations were collected and disbursed under Farmland’s centralized approach to cash management and the financing of its operations. The net divisional equity distribution characterized on the accompanying financial statements represents the net cash generated by these divisions and funded to Farmland to finance its overall operations.

Capital and Commercial Commitments

In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of September 30, 2006 relating to long-term debt, operating leases, unconditional purchase obligations and other specified capital and commercial commitments for the three months ending December 31, 2006, the four-year period following December 31, 2006 and thereafter.

Our ability to make payments on and to refinance our indebtedness, 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 refining spreads, fertilizer margins and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our revolving loan facility and the proceeds we receive from this offering will be adequate to meet our future liquidity needs for at least the next twelve months.


	Payments Due by Period
			Three Months
			Ending
			December 31,
	Total		2006		2007		2008		2009		2010		Thereafter
	(in millions)

Contractual Obligations
Long-term debt(1)	$	527.8	$	0.6	$	2.4	$	2.5	$	2.5	$	2.4	$	517.4
Operating leases(2)		13.7		0.9		3.8		3.6		2.9		1.6		0.9
Unconditional purchase obligations(3)		252.2		6.6		24.8		20.6		20.5		18.1		161.6
Environmental liabilities(4)		10.2		0.3		1.7		0.9		0.5		0.4		6.4
Funded letter of credit fees(5)		14.1		0.9		3.8		3.8		3.8		1.8		—
Interest payments(6)		331.1		13.4		53.2		53.1		52.8		52.6		106.0

Total	$	1,149.1	$	22.7	$	89.7	$	84.5	$	83.0	$	76.9	$	792.3
Other Commercial Commitments
Standby letters of credit(7)	$	6.4	$	—	$	6.4	$	—	$	—	$	—	$	—


(1)		Long-term debt amortization is based on the contractual terms of our existing credit facilities. See “Description of Our Indebtedness and the Cash Flow Swap.”

(2)		We lease various facilities and equipment, primarily railcars for our nitrogen fertilizer business under non-cancelable operating leases for various periods.


(3)		The amount includes (1) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation and (2) commitments under an electric supply agreement with the City of Coffeyville.


(4)		Environmental liabilities represents our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters.”


(5)		This amount represents the total of all fees related to the funded letter of credit issued under our First Lien Credit Facility. The funded letter of credit is utilized as credit support for the Cash Flow Swap. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”


(6)		Interest payments are based on interest rates in effect at September 30, 2006 and assume contractual amortization payments.


(7)		Standby letters of credit include our obligations under $3.2 million of letters of credit issued in connection with environmental liabilities, and $3.2 million to secure transportation expenses related to the Transportation Services Agreement with CCPS Transportation, LLC.

Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our revolving credit facility in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

Recently Issued Accounting Standards

In December 2004, the Financial Accounting Standards Board, or FASB, issued FASB No. 123 (revised 2004), Share-Based Payment, which addresses the accounting for transactions in which an entity exchanges its equity instruments for goods or services, with a primary focus on transactions in which an entity obtains employee services in share-based payment transactions. This Statement requires us to measure the cost of employee services received in exchange for an award of equity based on the grant-date fair value of the award (with limited exceptions). Incremental compensation costs arising from subsequent modifications of awards after the grant date must be recognized. Successor elected early adoption of SFAS 123(R) for the 233-day period ended December 31, 2005. The effect of the adoption of this standard is described in the footnotes to the Audited Financial Statements.

In December 2004, the FASB issued FASB No. 151, Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and spoilage. Under FASB 151, such items will be recognized as current-period charges. In addition, Statement No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. We adopted SFAS 151 effective January 1, 2006. There was not a significant impact on our financial position or results of operation.

In March 2005, the FASB issued FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations, which requires companies to recognize a liability for the fair value of a legal obligation to perform asset-retirement activities that are conditional on a future event when the amount can be reasonably estimated. FIN No. 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation under SFAS 143. We adopted FIN 47, as required, for the year ending December 31, 2005. A net asset retirement obligation of $636,000 was included in other liabilities on the consolidated balance sheet.

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. There was not a significant impact on our financial position or results of operations as a result of adoption.

In June 2006, the FASB issued Interpretation No. 48, Accounting for Uncertainty in Income Taxes — 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. We are currently evaluating FIN No. 48 and the effect it will have on our financial statements.

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.

The SEC issued Staff Accounting Bulletin (“SAB”) No. 108 on September 13, 2006. SAB No. 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 No. 108 are to be reflected in annual financial statements covering the first fiscal year ending after November 15, 2006. We are currently evaluating SAB No. 108 and the effect that it will have on our financial statements.

In September 2006, the FASB issued FAS No. 157, “Fair Value Measurements” which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. FAS 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.

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

The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments are held for trading.

Commodity Price Risk

We, as a manufacturer of refined petroleum products and nitrogen fertilizer products, all of which are commodities, have exposure to market pricing for products sold in the future. In order to realize value from our processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.

We use a crude oil purchasing intermediary which allows us to take title and price of our crude oil at the refinery, as opposed to the crude origination point, reducing our risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods. In addition, we seek to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in the annual operating plan. Accordingly, we use financial derivatives to economically hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard to our hedging activities, we may enter into, or have entered into, derivative instruments which serve to:


	•	lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows; and

	•	hedge the value of inventories in excess of minimum required inventories.

Further, we intend to engage only in risk mitigating activities directly related to our business.

Basis Risk. The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure.

Examples of our basis risk exposure are as follows:


	•	Time Basis — In entering over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underling physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods then weighted average physical prices will be weighted differently than the swap price as the result of timing.


	•	Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area.

Price and Basis Risk Management Activities. Our most prevalent risk management activity is to sell forward the crack spread when opportunities exist to lock in a margin sufficient to meet our cash obligations or our operating plan. Selling forward derivative contracts for which the underlying commodity is the crack spread enables us to lock in a margin on the spread between the price of crude oil and price of refined products. The commodity derivative contracts are either exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the form of commodity price swaps.

In the event our inventories exceed our target base level of inventories, we may enter into commodity derivative contracts to manage our price exposure to our inventory positions that are in excess of our base level. Excess inventories are typically the result of plant operations such as a turnaround or other plant maintenance. The commodity derivative contracts are either exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the form of commodity price swaps.

To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, we may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as we may deem appropriate) is different than the value contracted in the swap, then we will receive from or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of our margin. An example of our use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then we would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the Group 3 pricing.

On September 30, 2006, we had the following open commodity derivative contracts whose unrealized gains and losses are included in gain (loss) on derivatives in the consolidated statements of operations:


	•	Successor’s Petroleum Segment holds commodity derivative contracts in the form of three swap agreements for the period from July 1, 2005 to June 30, 2010 with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of Immediate Predecessor and required under the terms of our long-term debt agreements. These agreements were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The total notional quantities on the date of execution were 100,911,000 barrels of crude oil; 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil; pursuant to these swaps, we receive a fixed price with respect to the heating oil and the unleaded gasoline while we pay a fixed price with respect to crude oil. In June 2006, a subsequent swap was entered into with J. Aron to effectively reduce our unleaded notional quantity and increase our heating oil notional quantity by 229,671,750 gallons over the period July 2, 2007 to June 30, 2010. The swap agreements were executed at the prevailing market rate at the time of execution and management believed the swap agreements would provide an economic hedge on future transactions. At September 30, 2006 the net notional open amounts under these swap agreements were 71,206,000 barrels of crude oil, 1,495,326,000 gallons of heating oil and 1,495,326,000 gallons of unleaded gasoline. The purpose of these contracts is to economically hedge 35,603,000 barrels of heating oil crack spreads, the price spread between crude oil and heating oil and 35,603,000 barrels of unleaded gas crack spreads, the price spread between crude oil and unleaded gasoline. These open contracts had total unrealized net loss at September 30, 2006 of approximately $155.6 million.


	•	Successor’s Petroleum Segment holds two other commodity derivative contracts for the period from February 1, 2007 to February 28, 2007 with J. Aron. The combined notional quantity of the contracts is 100,000 barrels of unleaded gasoline crack spreads. The swap agreements were executed to effectively reduce the unleaded gasoline crack position of the swap agreements discussed in the previous bullet point. These open contracts had an unrealized gain of $0.1 million at September 30, 2006.


	•	Successor’s Petroleum Segment also holds various NYMEX positions through ABN Amro LLC. At September 30, 2006, we were short 390 crude contracts, 73 heating oil contracts and 100 unleaded contracts, reflecting an unrealized loss of $0.2 million on that date.

As of September 30, 2006, a $1.00 change in quoted futures price for the crack spreads described in the first bullet point would result in a $71.2 million change to the fair value of the derivative commodity position and the same change in net income.

Interest Rate Risk

As of September 30, 2006, all of our $527.8 million of outstanding debt was at floating rates. An increase of 1.0% in the LIBOR rate would result in an increase in our interest expense of approximately $5.4 million per year.

In an effort to mitigate the interest rate risk highlighted above and as required under the current first and second lien credit agreements, we entered into several interest rate swap agreements in 2005. These swap agreements were entered into with counterparties that we believe to be creditworthy. Under the swap agreements, we pay fixed rates and receive floating rates based on the three-month LIBOR rates, with payments calculated on the notional amounts set for in the table below. The interest rate swaps are settled quarterly and marked to market at each reporting date.

Effective

Termination

Fixed

Notional Amount

Date

Rate

$375.0 million

6/30/06

3/30/07

4.038%

$325.0 million

3/31/07

6/30/07

4.038%

$325.0 million

6/29/07

3/31/08

4.195%

$250.0 million

3/31/08

3/31/09

4.195%

$180.0 million

3/31/09

3/31/10

4.195%

$110.0 million

3/31/10

6/30/10

4.195%

We have determined that these interest rate swaps do not qualify as hedges for hedge accounting purposes. Therefore, changes in the fair value of these interest rate swaps are included in income in the period of change. Net realized and unrealized gains or losses are reflected in the gain (loss) for derivative activities at the end of each period. For the nine month period ending September 30, 2006, we had $2.9 million of realized and unrealized gains on these interest rate swaps.

INDUSTRY OVERVIEW

Oil Refining Industry

Oil refining is the process of separating the wide spectrum of hydrocarbons present in crude oil, and in certain processes, modifying the constituent molecular structures, for the purpose of converting them into marketable finished, or refined, petroleum products optimized for specific end uses. Refining is primarily a margin-based business where both the feedstocks (the petroleum products such as crude oil or natural gas liquids that are processed and blended into refined products) and the refined finished products are commodities. It is important for a refinery to maintain high throughput rates (the volume per day processed through the refinery) and capacity utilization given the substantial fixed component in the total operating costs. There are also material variable costs associated with the fuel and by-product components that become increasingly expensive as crude prices increase. The refiner’s goal is to achieve highest profitability by maximizing the yields of high value finished products and by minimizing feedstock and operating costs.

According to the Energy Information Administration, or the EIA, as of January 1, 2006, there were 142 oil refineries operating in the United States, with the 15 smallest each having a capacity of 11,000 bpd or less, and the 10 largest having capacities ranging from 306,000 to 562,500 bpd. Refiners typically are structured as part of a fully or partially integrated oil company, or as an independent entity, such as our Company.

Refining Margins

A variety of so called “crack spread” indicators are used to track the profitability of the refining industry. Among those of most relevance to our refinery are (1) the gas crack spread, (2) the heat crack spread, and (3) the 2-1-1 crack spread. The gas crack spread is the simple difference in per barrel value between reformulated gasoline (gasoline the compounds or properties of which meet the requirements of the reformulated gasoline regulations) in New York Harbor as traded on the New York Mercantile Exchange, or NYMEX, and the NYMEX prompt price of West Texas Intermediate, or WTI, crude oil on any given day. This provides a measure of the profitability when producing gasoline. The heat crack spread is the similar measure of the price of Number 2 heating oil in New York Harbor as traded on the NYMEX, relative to the value of WTI crude which provides a measure of the profitability of producing diesel and heating oil. The 2-1-1 crack spread is a composite spread that assumes for simplification and comparability purposes that for every two barrels of WTI consumed, a refinery produces one barrel of gasoline and one barrel of heating oil; the spread is based on the NYMEX price and delivery of gasoline and heating oil in New York Harbor. The 2-1-1 crack spread provides a measure of the general profitability of a medium high complexity refinery on the day that the spread is computed. The ability of a crack spread to measure profitability is affected by the absolute crude price.

Our refinery uses a consumed 2-1-1 crack spread to measure its specific daily performance in the market. The consumed 2-1-1 crack spread assumes the same relative production of gasoline and heating oil from crude, so like the NYMEX based 2-1-1 crack spread, it has an inherent inaccuracy because the refinery does not produce exactly two barrels of high valued products for each two barrels of crude oil, and the relative proportions of gasoline to heating oil will vary somewhat from the 1:1 relationship. However, the consumed 2-1-1 crack spread is an economically more accurate measure of performance than the NYMEX based 2-1-1 crack spread since the crude price used represents the price of our actual charged crude slate and is based on the actual sale values in our marketing region, rather than on New York Harbor NYMEX numbers. Average 2-1-1 crack spreads vary from region to region depending on the supply and demand balances of crude oils and refined products and can vary seasonally and from year to year reflecting more macroeconomic factors.

Although refining margins, the difference between the per barrel prices for refined products and the cost of crude oil, can be volatile during short term periods of time due to seasonality of demand,

refinery outages, extreme weather conditions and fluctuations in levels of refined product held in storage, longer-term averages have steadily increased over the last 10 years as a result of the improving fundamentals for the refining industry. For example, the NYMEX based 2-1-1 crack spread averaged $3.88 per barrel from 1994 through 1998 compared to $5.83 per barrel from 2000 to 2004. The following chart shows a rolling average of the NYMEX based 2-1-1 crack spread from 1994 through September 2006:

Source: Platts

Refining Market Trends

The supply and demand fundamentals of the domestic refining industry have improved since the 1990s and are expected to remain favorable as the growth in demand for refined products continues to exceed increases in refining capacity. Over the next two decades, the EIA projects that U.S. demand for refined products will grow at an average of 1.5% per year compared to total domestic refining capacity growth of only 1.3% per year. Approximately 83.3% of the projected demand growth is expected to come from the increased consumption of light refined products (including gasoline, diesel, jet fuel and liquefied petroleum gas), which are more difficult and costly to produce than heavy refined products (including asphalt and carbon black oil).

High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. According to the EIA, domestic refining capacity decreased approximately 8% between January 1981 and January 2006 from 18.6 million bpd to 17.1 million bpd, as more than 175 generally small and unsophisticated refineries that were unable to process heavy crude into a marketable product mix have been shut down, and no new major refinery has been built in the United States. The implementation of the federal Tier II low sulfur fuel regulations is expected to further reduce existing refining capacity.

In order to meet the increasing demands of the market, U.S. refineries have pursued efficiency measures to improve existing production levels. These efficiency measures and other initiatives, generally known as capacity creep, have raised productive capacity of existing refineries by approximately 1% per year since 1993. According to the EIA, between 1981 and 2004, refinery utilization increased from 69% to 93%. Over the next 20 years, the EIA projects that utilization will remain high relative to historic levels, ranging from 92% to 95% of design capacity.

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Source: EIA

The price discounts available to refiners of heavy sour crude oil have widened as many refiners have turned to sweeter and lighter crude oils to meet lower sulfur fuel specifications, which has resulted in increasing the surplus of sour and heavy crude oils. As the global economy has improved, worldwide crude oil demand has increased, and OPEC and other producers have tended to incrementally produce more of the sour or heavier crude oil varieties. We believe that the combination of increasing worldwide supplies of lower cost sour and heavy crude oils and increasing demand for sweet and light crude oils will provide a cost advantage to refineries with configurations that are able to process sour crude oils.

We expect refined products that meet new and evolving fuel specifications will account for an increasing share of total fuel demand, which will benefit refiners who are able to efficiently produce these fuels. As part of the Clean Air Act, major metropolitan areas in the United States with air pollution problems must require the sale and use of reformulated gasoline meeting certain environmental standards in their jurisdictions. Boutique fuels, such as low vapor pressure Kansas City gasoline, enable refineries capable of producing such refined products to achieve higher margins.

Due to the ongoing supply and demand imbalance, the United States continues to be a net refined products importer. Imports, largely from northwest Europe and Asia, accounted for over 13% of total U.S. consumption in 2004. The level of imports generally increases during periods when refined product prices in the United States are materially higher than in Europe and Asia.

Based on the strong fundamentals for the global refining industry, capital investments for refinery expansions and new refineries in international markets have increased during the recent year. However, the competitive threat faced by domestic refiners is limited by U.S. fuel specifications and increasing foreign demand for refined products, particularly for light transportation fuels.

Certain regional markets in the United States, such as the Coffeyville supply area, do not have the necessary refining capacity to produce a sufficient amount of refined products to meet area demand and therefore rely on pipelines and other modes of transportation for incremental supply from other regions of the United States and globally. The shortage of refining capacity is a factor that results in local refiners serving these markets earning generally higher margins on their product sales than those who have to transport their products to this region over long distances.

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Notwithstanding the trends described above, the refining industry is cyclical and volatile and has undergone downturns in the past. See “Risk Factors.”

Refinery Locations

A refinery’s location can have an important impact on its refining margins because location can influence access to feedstocks and efficient distribution. There are five regions in the United States, the Petroleum Administration for Defense Districts (PADDs), that have historically experienced varying levels of refining profitability due to regional market conditions. Refiners located in the U.S. Gulf Coast region operate in a highly competitive market due to the fact that this region (PADD III) accounts for approximately 37% of the total number of U.S. refineries and approximately 48% of the country’s refining capacity. PADD I represents the East Coast, PADD IV the Rocky Mountains and PADD V is the West Coast.

Coffeyville operates in the Midwest (PADD II) region of the US. In 2005, demand for gasoline and distillates (primarily diesel fuels, kerosene and jet fuel) exceeded refining production in the Coffeyville supply area by approximately 24%, which created a need to import a significant portion of the region’s requirement for petroleum products from the U.S. Gulf Coast and other regions. The deficit of local refining capacity benefits local refined product pricing and could generally lead to higher margins for local refiners such as our company.

Nitrogen Fertilizer Industry

Plant Nutrition and Nitrogen Fertilizers

Commercially produced fertilizers give plants the primary nutrients needed in a form they can readily absorb and use. Nitrogen is an essential element for plant growth. Absorbed by plants in larger amounts than other nutrients, nitrogen makes plants green and healthy and is the nutrient most responsible for increasing yields in crop plants. Although plants will absorb nitrogen from organic matter and soil materials, this is usually not sufficient to satisfy the demands of crop plants. The

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supply of nutrients must, accordingly, be supplemented with fertilizers to meet the requirements of crops during periods of plant growth, to replenish nutrients removed from the soil through crop harvesting and to provide those nutrients that are not already available in appropriate amounts in the soil. The two most important sources of nutrients are manufactured or mineral fertilizers and organic manures. Farmers determine the types, quantities and proportions of fertilizer to apply to their fields depending on, among other factors, the crop, soil and weather conditions, regional farming practices, and fertilizer and crop prices.

Nitrogen, which typically accounts for approximately 60% of worldwide fertilizer consumption in any planting season, is an essential element for most organic compounds in plants as it promotes protein formation and is a major component of chlorophyll, which helps to promote green healthy growth and high yields. There are no substitutes for nitrogen fertilizers in the cultivation of high-yield crops. The four principal nitrogen based fertilizer products are:

Ammonia. Ammonia is used in limited quantities as a direct application fertilizer, and is primarily used as a building block for other nitrogen products, including intermediate products for industrial applications and finished fertilizer products. Ammonia, consisting of 82% nitrogen, is stored either as a refrigerated liquid at minus 27 degrees, or under pressure if not refrigerated. It is gaseous at ambient temperatures and is injected into the soil as a gas. The direct application of ammonia requires farmers to make a considerable investment in pressurized storage tanks and injection machinery, and can take place only under a narrow range of ambient conditions.

Urea. Urea is formed by reacting ammonia with carbon dioxide, or CO₂, at high pressure. From the warm urea liquid produced in the first, wet stage of the process, the finished product is mostly produced as a coated, granular solid containing 46% nitrogen and suitable for use in bulk fertilizer blends containing the other two principal fertilizer nutrients, phosphate and potash. We do not produce merchant urea.

Ammonium Nitrate. Ammonium nitrate is another dry, granular form of nitrogen based fertilizer. It is produced by converting ammonia to nitric acid in the presence of a platinum catalyst reaction, then further reacting the nitric acid with additional volumes of ammonia to form ammonium nitrate. We do not produce this product.

Urea Ammonium Nitrate Solution (UAN). Urea can be combined with ammonium nitrate solution to make liquid nitrogen fertilizer (urea ammonium nitrate or UAN). These solutions contain 32% nitrogen and are easy to store and transport and provide the farmer with the most flexibility in tailoring fertilizer, pesticide and fungicide applications.

In 2005, we produced approximately 413,200 tons of ammonia, of which approximately two-thirds was upgraded into approximately 663,300 tons of UAN.

Ammonia Production Technology — Advantages of Coke Gasification

Ammonia is produced by reacting gaseous nitrogen with hydrogen at high pressure and temperature in the presence of a catalyst. Traditionally, nearly all hydrogen produced for the manufacture of nitrogen based fertilizers is produced by reforming natural gas at a high temperature and pressure in the presence of water and a catalyst. This process consumes a significant amount of natural gas and is believed to become unprofitable as the natural gas input costs increase.

Alternatively, hydrogen for ammonia can also be produced by gasifying pet coke. Pet coke is a coal-like substance that is produced during the refining process. The coke gasification process, which is commercially employed at our nitrogen fertilizer plant, the only such plant in North America, takes advantage of the large cost differential between pet coke and natural gas in current markets. Our coke gasification process allows us to use less than 1% of the natural gas relative to other nitrogen based fertilizer facilities that are heavily dependent upon natural gas and are thus heavily impacted by natural gas price swings. We also benefit from the ready availability of pet coke supply from our

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refinery plant. Pet coke is a refinery by-product which if not used in the fertilizer plant would otherwise be sold as fuel, generating less value to the company.

Fertilizer Consumption Trends

Global demand for fertilizers typically grows at predictable rates and tends to correspond to growth in grain production. Global fertilizer demand is driven in the long-term primarily by population growth, increases in disposable income and associated improvements in diet. Short-term demand depends on world economic growth rates and factors creating temporary imbalances in supply and demand. These factors include weather patterns, the level of world grain stocks relative to consumption, agricultural commodity prices, energy prices, crop mix, fertilizer application rates, farm income and temporary disruptions in fertilizer trade from government intervention, such as changes in the buying patterns of large countries like China or India. According to the International Fertilizer Industry Association, or IFA, from 1960 to 2005, global fertilizer demand has grown 3.7% annually and global nitrogen demand has grown at a faster rate of 4.8% annually. According to the IFA, during that 45-year period, North American fertilizer demand has grown 2.4% annually with North American nitrogen demand growing at a faster rate of 3.3% annually.

In 2000, the FAO projected an increase in major world crop production from 1995/97 to 2030 of approximately 76%. The annual growth rate for fertilizer consumption through 2030 is projected by the FAO to be between 0.7% and 1.3% per year. This forecast assumes a slowdown in the growth of the world’s population and crop production, and an improvement in fertilizer use efficiency.

The Farm Belt Nitrogen Market

All of our product shipments target freight advantaged destinations located in the U.S. farm belt. The farm belt refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. Because shipping ammonia requires refrigerated or pressured containers and UAN is more than 65% water, transportation cost is substantial for ammonia and UAN producers. As a result, locally based fertilizer producers, such as our company, enjoy a distribution cost advantage over U.S. Gulf Coast ammonia and UAN importers. Southern Plains ammonia and Corn Belt UAN prices averaged $272/ton and $157/ton, respectively, for the 2002 through 2005 period. The distribution cost for a U.S. Gulf Coast importer represents a significant portion of both ammonia’s and UAN’s price. The volumes of ammonia and UAN sold into certain farm belt markets are set forth in the table below:

Current United States Ammonia and UAN Demand in Selected Mid-continent Areas


	Ammonia		UAN
State	Quantity		Quantity
	(thousand tons per year)

Texas		2,300		850
Oklahoma		80		225
Kansas		370		670
Missouri		325		250
Iowa		690		865
Nebraska		335		1,100
Minnesota		335		195

Source: Blue Johnson & Associates Inc.

Fertilizer Pricing Trends

The nitrogen fertilizer industry is cyclical and relatively volatile, reflecting the commodity nature of ammonia and the major finished fertilizer products (e.g., urea). Although domestic industry-wide

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sales volumes of nitrogen based fertilizers vary little from one fertilizer season to the next due to the need to apply nitrogen every year to maintain crop yields, in the normal course of business industry participants are exposed to fluctuations in supply and demand, which can have significant effects on prices across all participants’ commodity business areas and products and, in turn, their operating results and profitability. Changes in supply can result from capacity additions or reductions and from changes in inventory levels. Demand for fertilizer products is dependent on demand for crop nutrients by the global agricultural industry, which, in turn, depends on, among other things, weather conditions in particular geographical regions. Periods of high demand, high capacity utilization and increasing operating margins tend to result in new plant investment, higher crop pricing and increased production until supply exceeds demand, followed by periods of declining prices and declining capacity utilization, until the cycle is repeated. Due to dependence of the prevalent nitrogen fertilizer technology on natural gas, the marginal cost and pricing of fertilizer products also tend to exhibit positive correlation with the price of natural gas.

The historical average annual U.S. ammonia prices as well as natural gas and crude oil prices are detailed in the table below.


	Natural Gas		WTI		Ammonia
Year	($/million btu)		($/bbl)		($/ton)

1990		1.78		24.53		125
1991		1.53		21.55		130
1992		1.73		20.57		134
1993		2.11		18.43		139
1994		1.94		17.16		197
1995		1.69		18.38		238
1996		2.50		22.01		217
1997		2.48		20.59		220
1998		2.16		14.43		162
1999		2.32		19.26		145
2000		4.32		30.28		208
2001		4.06		25.92		262
2002		3.39		26.19		191
2003		5.49		31.03		292
2004		5.90		41.47		326
2005		8.92		56.58		394
2006 (through September 30)		7.24		67.13		387

Source: Bloomberg and Blue Johnson & Associates, Inc.

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BUSINESS

Our petroleum business includes a 108,000 bpd, complex full coking sour crude refinery in Coffeyville, Kansas. In addition, our supporting businesses include (1) a crude oil gathering system serving central Kansas and northern Oklahoma, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, and (3) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg, and to customers at throughput terminals on Magellan refined products distribution systems. In addition to rack sales (sales which are made at terminals using tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and Valero. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, the largest crude oil trading and storage hub in the United States, served by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude variety in the world capable of being transported by pipeline.

Our nitrogen fertilizer business is the only operation in North America that utilizes a coke gasification process to produce ammonia. A majority of the ammonia produced by our fertilizer plant is further upgraded to UAN fertilizer (a solution of urea and ammonium nitrate in water used as a fertilizer). By using pet coke (a coal-like substance that is produced during the refining process) instead of natural gas as raw material, we are the lowest cost producer of ammonia and UAN in North America. Furthermore, on average, over 80% of the pet coke utilized by us is produced and supplied to the fertilizer plant as a by-product of our refinery. As such, we benefit from high natural gas prices, as fertilizer prices increase with natural gas prices, while our input costs remain substantially the same.

We have two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2004 and 2005 and the twelve months ended September 30, 2006, we generated combined net sales of $1.7 billion, $2.4 billion and $3.0 billion, respectively, and operating income of $111.2 million, $270.8 million and $329.7 million, respectively. Our petroleum business generated $1.6 billion, $2.3 billion and $2.8 billion of our combined net sales, respectively, over these periods, with our nitrogen fertilizer business generating substantially all of the remainder. In addition, during these three periods, our petroleum business contributed 76%, 74% and 84% of our combined operating income, respectively, with our nitrogen fertilizer business contributing substantially all of the remainder.

Significant Milestones Since the Change of Control in June 2005

Following the acquisition by certain affiliates of The Goldman Sachs Group, Inc. (whom we collectively refer to in this prospectus as the Goldman Sachs Funds) and certain affiliates of Kelso & Company (whom we collectively refer to in this prospectus as the Kelso Funds) in June 2005, a new senior management team led by Jack Lipinski, our Chief Executive Officer, was formed that blended the best of existing management with highly experienced new members. Our new senior management team has executed several key strategic initiatives that we believe have significantly enhanced our competitive position and improved our financial and operational performance.

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than 102,000 bpd in the second quarter of 2006, with peak daily rates in excess of 108,000 bpd of crude. Crude throughputs averaged 94,000 bpd for the first nine months of 2006, an improvement of over 4,000 bpd over the first nine months in 2005. Recent operational improvements at the refinery have also allowed us to produce higher volumes of favorably priced distillates (primarily No. 1 diesel fuel and kerosene), premium gasoline and boutique gasoline grades and to improve our liquid volume yield.

Diversified Crude Feedstock Variety. We have expanded the variety of crude grades processed in any given month from a limited few to over a dozen, including onshore and offshore domestic grades, various Canadian sours, heavy sours and sweet synthetics, and a variety of South American and West African imported grades. This has improved our crude purchase cost discount to WTI from $2.80 per barrel in the first nine months of 2005 to $4.29 per barrel in the first nine months of 2005.

Expanded Direct Rack Sales. We have significantly expanded and intend to continue to expand rack marketing of refined products (petroleum products such as gasoline and diesel fuel) directly to customers rather than origin bulk sales. Today, we sell over 23% of our produced transportation fuels throughout the Coffeyville supply area within the mid-continent, at enhanced margins, through our proprietary terminals and at Magellan’s throughput terminals. With the expanded rack sales program, we improved our net income for the first nine months of 2006 compared to the first nine months of 2005.

The following major projects under this program were completed in 2006:


	•	Construction of a new 23,000 bpd high pressure diesel hydrotreater and associated new sulfur recovery unit, which will allow the facility to meet the EPA Tier II Ultra Low Sulfur Diesel federal regulations; and


	•	Expansion of one of the two gasification units within the fertilizer complex, which is expected to increase ammonia production by over 6,500 tons per year.

The following major projects under this program expected to be completed in 2007 are intended to increase refinery processing capacity to up to 120,000 bpd, increase gasoline production and improve our liquid volume yield:


	•	Refinery-wide capacity expansion by increasing throughput of the existing fluid catalytic cracking unit (the unit that converts gas oil from the crude unit or coker unit into liquified petroleum gas, distillates and gasoline blendstocks), the delayed coker (the unit that processes heavy feedstock and produces lighter products and pet coke), and other major process units to be completed during a plant-wide turnaround scheduled to begin in the first quarter of 2007; and


	•	Construction of a new grass roots 24,000 bpd continuous catalytic reformer to be completed in the third quarter of 2007.

Once completed, these projects are intended to significantly enhance the profitability of the refinery in environments of high crack spreads and allow the refinery to operate more profitably at lower crack spreads than is currently possible. A crack spread is a simplified calculation that measures the difference between the price for light products, like gasoline and diesel fuel, and crude oil. Our experienced engineering and construction team is managing these projects in-house with support from established specialized contractors, thus giving us maximum control and oversight of execution. We intend to finance these capital projects with cash from our operations and occasional

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borrowings from our revolving credit facility. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Debt” and “Description of Our Indebtedness and the Cash Flow Swap.”

We have also undertaken a study to review expansion of the refinery beyond the program described above. Preliminary engineering for the first stage of a potential multi-stage expansion has been approved by our board of directors. We anticipate that each stage of this extended expansion program would decrease refinery crude cost by enabling the plant to process significant additional volumes of lower cost heavy sour crude from Canada or offshore. If fully implemented, this first phase would be intended for completion in 2009.

Our Competitive Strengths

Regional Advantage and Strategic Asset Location. Our refinery is one of only seven refineries located in the Coffeyville supply area within the mid-continent region, where demand for refined products exceeded refining production by approximately 24% in 2005. We estimate that this favorable supply/demand imbalance combined with our lower pipeline transportation cost as compared to the U.S. Gulf Coast refiners has allowed us to generate refining margins, as measured by the 2-1-1 crack spread, that have exceeded U.S. Gulf Coast refining margins by approximately $1.40 per barrel on average for the last four years. The 2-1-1 crack spread is a general industry standard that approximates the gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel. In addition, our nitrogen fertilizer business is geographically advantaged to supply products to markets in Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without incurring intermediate transfer, storage, barge or pipeline freight charges. We estimate that this geographic advantage provides us with a distribution cost benefit over U.S. Gulf Coast ammonia and UAN importers, assuming in each case freight rates and handling charges for U.S. Gulf Coast importers as in effect in September 2006. These cost differentials represent a significant portion of the market price of these commodities.

Access to and Ability to Process Multiple Crude Oils. Since June 2005 we have significantly expanded the variety of crude grades processed in any given month and have reduced our acquisition cost of crude relative to WTI by approximately $1.49 per barrel in the first nine months of 2006 compared to the first nine months of 2005. While our proximity to the Cushing crude oil trading hub minimizes the likelihood of an interruption to our supply, we intend to further diversify our sources of crude oil. Among other initiatives in this regard, we have secured shipper rights on the newly built Spearhead pipeline, owned by CCPS Transportation, LLC (which is ultimately owned by Enbridge), which connects Chicago to the Cushing hub and provides us with an ability to secure incremental oil supplies from Canada. We also own and operate a crude gathering system located in northern Oklahoma and central Kansas, which allows us to acquire quality crudes at a discount to WTI.

High Quality, Modern Asset Base with Solid Track Record. We operate a complex full coking sour crude refinery. Complexity is a measure of a refinery’s ability to process lower quality crude in an economic manner; greater complexity makes a refinery more profitable. Our refinery’s complexity allows us to optimize the yields (the percentage of refined product that is produced from crude and other feedstocks) of higher value transportation fuels (gasoline and distillate), which currently account for approximately 94% of our liquid production output. From 1995 through the first nine months of 2006, we have invested approximately $375 million to modernize our oil refinery and to meet more stringent U.S. environmental, health and safety requirements. As a result, we have achieved significant increases in our refinery crude throughput rate from an average of less than 90,000 bpd prior to June 2005 to over 102,000 bpd in the second quarter of 2006 and over 94,000 bpd for the first nine months of 2006 with peak daily rates in excess of 108,000 bpd. Management’s consistent focus on reliability and safety earned us the NPRA Gold Award for safety in 2005. Our fertilizer plant, completed in 2000, is the newest facility of its kind in North America, utilizes less than 1% of the natural gas relative to natural gas-based fertilizer producers and, since 2003, has demonstrated a consistent record of operating near full capacity. The fertilizer plant underwent a

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scheduled turnaround (a periodically required procedure to refurbish and maintain the facility that involves the shutdown and inspection of major processing units) in 2006, and we have recently expanded the plant’s spare gasifier to increase its production capacity.

Near Term Internal Expansion Opportunities. Since June 2005, we have identified and developed several significant capital projects with an estimated total cost of approximately $400 million primarily aimed at (1) expanding refinery capacity, (2) enhancing operating reliability and flexibility, (3) complying with more stringent environmental, health and safety standards and (4) improving our ability to process heavy sour crude feedstock varieties. With the completion of $400 million of identified and developed significant capital projects, we expect to significantly enhance the profitability of our refinery during periods of high crack spreads while enabling the refinery to operate more profitably at lower crack spreads than is currently possible. A crack spread is a simplified calculation that measures the difference between the price for light products (gasoline, diesel fuel) and crude oil. We also estimate that our contemplated fertilizer plant expansion could increase our capacity to upgrade ammonia into premium priced UAN by 50% to approximately 1,000,000 tons per year.

Unique Coke Gasification Fertilizer Plant. Our nitrogen fertilizer plant is the only one of its kind in North America utilizing a coke gasification process to produce ammonia, resulting in significantly lower feedstock costs than all other predominantly natural gas-based fertilizer plants. We estimate that our production cost advantage over U.S. Gulf Coast ammonia producers is sustainable at natural gas prices as low as $2.50 per million Btu. This cost advantage has been more pronounced in today’s natural gas price environment, as the reported Henry Hub natural gas price has fluctuated between approximately $4.20 and $15.00 per million Btu since the end of 2003. Our fertilizer business has a secure raw material supply as on average over 80% of the pet coke required by the fertilizer plant is supplied by our refinery. The sustaining capital requirements for this business are low relative to earnings and are expected to range between $3 million and $5 million per year as compared to $71.0 million of operating income in our nitrogen fertilizer segment for the combined twelve months ended December 31, 2005.

Our Business Strategy


	•	Continuing to take advantage of favorable supply and demand dynamics in the mid-continent region (where demand from our products currently outweighs supply);


	•	Selectively investing in significant projects that enhance our operating efficiency and expanding our capacity while rigorously controlling costs;

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	•	Increasing our sales and supply capabilities of UAN, and other high value products, while finding lower cost sources of raw materials;


	•	Continuing to focus on being a reliable, low cost producer of petroleum and fertilizer products;


	•	Continuing to focus on the reliability, safety and environmental performance of our operations; and


	•	Selectively evaluating attractive growth opportunities through acquisitions and/or strategic alliances.

Our History

Our business was founded in 1906 by The National Refining Company, which at the time was the largest independent oil refiner in the United States. In 1944 the Coffeyville refinery was purchased by the Cooperative Refinery Association, a subsidiary of a parent company that in 1966 renamed itself Farmland Industries, Inc. Our assets were operated as a small component of Farmland Industries, Inc., an agricultural cooperative, until March 3, 2004. Farmland filed for bankruptcy protection on May 31, 2002.

Coffeyville Resources, LLC, a subsidiary of Coffeyville Group Holdings, LLC, won the bankruptcy court auction for Farmland’s petroleum business and a nitrogen fertilizer plant and completed the purchase of these assets on March 3, 2004. On October 8, 2004, Coffeyville Group Holdings, LLC, through two of its wholly owned subsidiaries, Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc., acquired an interest in Judith Leiber business, a designer handbag business, through an investment in CL JV Holdings, LLC, a joint venture with The Leiber Group, Inc., whose majority stockholder was also the majority stockholder of Coffeyville Group Holdings, LLC. On June 23, 2005, Coffeyville Group Holdings, LLC, through a wholly owned subsidiary of CL JV Holdings, LLC, effectively redistributed the Judith Leiber business to The Leiber Group, Inc.

On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, Coffeyville Acquisition LLC, which was formed in Delaware on May 13, 2005, acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. With the exception of crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005, Coffeyville Acquisition LLC had no operations from its inception until the acquisition on June 24, 2005. The Goldman Sachs Funds and the Kelso Funds own substantially all of the common units of Coffeyville Acquisition LLC, which currently owns all of our capital stock.

Prior to this offering, Coffeyville Acquisition LLC directly or indirectly owned all of our subsidiaries. We were formed in Delaware in September 2006 as a wholly owned subsidiary of Coffeyville Acquisition LLC. Concurrently with this offering, we will merge a newly formed direct subsidiary of ours with Coffeyville Refining & Marketing and merge a separate newly formed direct subsidiary of ours with Coffeyville Nitrogen Fertilizers which will make Coffeyville Refining & Marketing and Coffeyville Nitrogen Fertilizers direct wholly owned subsidiaries of ours. We refer to these pre-IPO reorganization transactions in the prospectus as the “Transactions.”

Petroleum Business

Asset Description

We operate one of the seven refineries located in the Coffeyville supply area (Kansas, Oklahoma, Missouri, Nebraska and Iowa). The Company’s complex cracking and coking oil refinery has the capacity to produce 108,000 bpd which accounts for approximately 14% of the region’s output. As part of our comprehensive capital expenditure program, we expect to increase the refinery capacity to up to 120,000 bpd in 2007. The facility is situated on approximately 440 acres in southeast Kansas, approximately 100 miles from the Cushing, Oklahoma crude oil trading and storage hub.

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The Coffeyville refinery is a complex facility. Complexity is a measure of a refinery’s ability to process lower quality crude in an economic manner. It is also a measure of a refinery’s ability to convert lower cost, more abundant heavier and sour crudes into greater volumes of higher valued refined products such as gasoline, thereby providing a competitive advantage over less complex refineries. At the time of the Subsequent Acquisition we had a modified Solomon complexity score of approximately 10.0. “Modified Solomon complexity” is a standard industry measure of a refinery’s ability to process less-expensive feedstock, such as heavier and higher-sulfur content crude oils, into value-added products. Modified Solomon complexity is the weighted average of the Solomon complexity factors for each operating unit multiplied by the throughput of each refinery unit, divided by the crude capacity of the refinery. Due to the refinery’s complexity, higher value products such as gasoline and diesel represent approximately an 86% product yield on a total throughput basis. Other products include slurry, light cycle oil, vacuum tower bottom, or VTB, reformer feeds, gas oil, pet coke and sulfur. All of our pet coke by-product is consumed by our adjacent nitrogen fertilizer business, which enables the fertilizer plant to be cost effective, because pet coke is utilized in lieu of higher priced natural gas. Following completion of our present capital expenditure program we expect the Solomon complexity score to rise from 10.0 to 11.2.

The refinery consists of two crude units with maximum sustainable capacities of 75,000 bpd and 45,000 bpd. It has two vacuum units with 21,000 bpd and 16,000 bpd capacities. A vacuum unit is a secondary unit which processes crude oil by separating product from the crude unit according to boiling point under high heat and low pressure to recover various hydrocarbons. The availability of more than one crude and vacuum unit creates redundancy in the refinery system and enables us to continue to run the refinery even if one of these units were to shut down for scheduled or unscheduled plant maintenance and upgrades. However, the maximum combined capacity of the crude units is limited by the overall downstream capacity of the vacuum units and other units.

Our petroleum business also includes the following auxiliary operating assets:


	•	*Crude Oil Gathering System.* We own and operate a 25,000 bpd crude oil gathering system comprised of over 300 miles of feeder and trunk pipelines, 40 trucks and associated storage facilities for gathering light, sweet Kansas and Oklahoma crude oils purchased from independent crude producers. We have also leased a section of a pipeline from Magellan Pipeline Company, L.P. that will allow us to gather additional volumes of attractively priced quality crudes.


	•	*Phillipsburg Terminal.* We own storage and terminalling facilities for asphalt and refined fuels at Phillipsburg, Kansas. Our asphalt storage and terminalling facilities are used to receive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement.

Feedstocks Supply

Our refinery has the capability to process a blend of heavy sour as well as light sweet crudes. Currently, our refinery processes crude from a broad array of sources, approximately two-thirds domestic and one-third foreign. We purchase foreign crudes from Latin America, South America, West Africa, the North Sea and Canada. We purchase domestic crudes that meet pipeline specifications from Kansas, Oklahoma, Texas, and offshore deepwater Gulf of Mexico production. Given our refinery’s ability to process a wide variety of crudes and ready access to multiple sources of crude, we have never curtailed production due to lack of crude access. Other feedstocks (petroleum products that are processed and blended into refined products) include natural gasoline, various grades of butanes, vacuum gas oil, vacuum tower bottom, or VTB, and others which are sourced from the

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Conway/Group 140 storage facility or regional refinery suppliers. Below is a summary of our historical feedstock inputs:


	Year Ended December 31,										Nine Months Ended September 30,
	2001		2002		2003		2004		2005		2005		2006
	(in barrels)

Crude oil		30,880,860		27,172,830		31,207,718		33,227,971		33,250,518		24,547,547		25,678,731
Natural gasoline		694,552		1,093,629		483,362		317,874		455,587		344,382		273,559
Normal butane		—		—		—		530,575		467,176		158,116		194,132
Isobutane		1,142,098		1,037,855		1,627,989		1,615,898		1,398,694		1,035,321		1,089,415
Alky feed		—		—		—		—		68,636		68,636		112,358
Gas oil		—		—		—		—		155,344		34,574		337,764
Vacuum tower bottom		32,951		98,371		109,974		105,981		99,362		99,362		30,208

Total Inputs		32,750,461		29,402,685		33,429,043		35,798,299		35,895,317		26,287,938		27,716,167

Crude is supplied to our refinery through our wholly owned gathering system and by pipeline.

Our crude gathering system was expanded in 2006 and now supplies in excess of 22,000 bpd of crude to the refinery (approximately 20% of total supply). We leased a pipeline in 2006 from Magellan Pipeline Company, L.P. that will serve as part of our pipeline system and will allow for further buying of attractively priced locally produced crudes. Locally produced crudes are delivered to the refinery at a discount to WTI and are of similar quality to WTI. These lighter sweet crudes allow us to blend higher percentages of low cost crudes such as heavy sour Canadian while maintaining our target medium sour blend.

Crude oils sourced outside of our proprietary gathering system are first delivered by common carrier pipelines (primarily Seaway) into various terminals in Cushing, Oklahoma, where they are blended and then delivered to Caney, Kansas via a pipeline owned by Plains All American L.P. Crudes are delivered to our refinery from Caney, Kansas via a 145,000 bpd proprietary pipeline system, which we own. We also maintain capacity on the Spearhead Pipeline owned ultimately by Enbridge from Canada. As part of our crude supply optimization efforts, we lease approximately 1,550,000 barrels of crude oil storage in Cushing, and recently purchased 65 acres of land and contracted to purchase an additional 120 acres of land in the heart of the Cushing crude storage district, which we expect will provide us a storage expansion option should the addition of crude storage be required in the future.

The following table sets forth the feedstock pipelines used by the oil refinery as of September 30, 2006:


	Nominal
Pipeline	Capacity (bpd)

Seaway Pipeline (TEPPCO) from U.S. Gulf Coast to Cushing, Oklahoma		350,000
Spearhead (CCPS/Enbridge) from Griffith (Chicago) to Cushing, Oklahoma		125,000
Coffeyville Crude Oil Pipeline System from Caney, Kansas to Oil Refinery		145,000
Coffeyville Crude Oil Gathering and Trucking System		25,000
Natural Gas Liquid (NGL) Connection from/to Conway, Kansas through MAPCO and ONEOK		15,000
Plains-Cushing to Caney, Kansas		97,000
Sun Logistics Pipeline from U.S.G.C. to Cushing, Oklahoma		120,000

We purchase most of our crude oil requirements outside of our proprietary gathering system under a credit intermediation agreement with J. Aron. The credit intermediation agreement helps us reduce our inventory position and mitigate crude pricing risk. Once we identify cargos of crude oil and pricing terms that meet our requirements, we notify J. Aron which then provides, for a fee, credit, transportation and other logistical services for delivery of the crude to the crude oil tank farm. Generally, we select crude oil approximately 30 to 45 days in advance of the time the related refined

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products are to be marketed, except for Canadian and West African crude purchases which require an additional 30 days of lead time due to transit considerations.

Transportation Fuels


	•	*Gasoline.* Gasoline typically accounts for approximately 47% of our refinery’s production. Our oil refinery produces various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded and uses a computerized component blending system to optimize gasoline blending.


	•	*Distillates.* Distillates typically account for approximately 41% of the refinery’s production. The majority of the diesel fuel we produce is low-sulfur.

The following table summarizes our historical oil refinery yields:


																Nine Months
	Year Ended															Ended
	December 31,															September 30,
	2001			2002			2003			2004			2005			2005			2006
	(in barrels)

Gasoline:
Regular unleaded		15,118,607			14,071,304			16,531,362			16,703,566			16,154,172			11,740,790			11,926,825
Premium unleaded		423,898			306,334			298,789			220,908			261,467			227,242			374,211
Sub-octane unleaded		803,590			754,264			773,831			797,416			109,774			109,774			294,356

Total gasoline		16,346,095			15,131,902			17,603,982			17,721,890			16,525,413			12,077,806			12,595,393
Distillate:
Kerosene		25,675			26,085			25,149			23,256			32,302			13,086			(5,774	)
Jet fuel		97,354			—			—			—			—			—			—
No. 1 distillate		278,325			124,741			342,363			99,832			261,048			40,447			13,628
No. 2 low sulfur distillate		6,708,536			6,526,883			7,899,132			8,896,701			9,129,518			6,533,104			8,496,463
No. 2 high sulfur distillate		3,138,236			2,268,116			3,017,785			3,500,351			3,916,658			2,955,997			2,743,127
Diesel		2,105,709			1,923,370			1,258,279			1,425,897			1,259,308			1,133,210			55,043

Total distillate		12,353,835			10,869,195			12,542,708			13,946,037			14,598,834			10,675,844			11,302,488
Liquid by-products:
NGL (propane, butane)		676,753			583,095			734,737			1,137,645			696,637			519,939			509,479
Slurry		507,407			445,784			532,236			500,692			562,657			385,503			524,078
Light cycle oil sales		214,504			84,146			42,571			—			—			—			—
VTB sales		188,684			8,212			26,438			150,700			134,899			40,927			66,126
Reformer feed sales		207,154			—			—			79,906			230,785			170,171			231,250
Gas oil sales		—			84,673			—			—			66,274			66,274			—

Total liquid by-products		1,794,502			1,205,910			1,335,982			1,868,943			1,691,252			1,182,814			1,330,933
Solid by-products:
Coke		2,751,298			2,068,031			1,956,619			2,384,414			2,439,297			1,854,020			1,848,931
Sulfur		92,918			74,226			131,137			88,744			100,035			77,877			65,292

Total solid by-products		2,844,216			2,142,257			2,087,756			2,473,158			2,539,332			1,931,897			1,914,223
NGL production		226,159			52,682			(8,539	)		—			548,883			548,883			473,639
In process change		(347,599	)		114,945			(120,122	)		(12,369	)		265,280			38,652			311,226
Produced fuel		1,369,413			1,268,388			1,489,030			1,636,665			1,557,689			1,210,977			1,276,288
Processing loss (gain)		(1,836,160	)		(1,382,594	)		(1,501,754	)		(1,836,025	)		(1,831,366	)		(1,378,935	)		(1,488,023	)

Total yields		32,750,461			29,402,685			33,429,043			35,798,299			35,895,317			26,287,938			27,716,167

Our oil refinery’s long-term capacity utilization (ratio of total refinery throughput to the refinery’s rated capacity) has steadily improved over the years. To further enhance capacity utilization, our operations management initiatives and capital expenditures program are focused on improving crude

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slate flexibility, increasing inbound NGL pipeline capacity and optimizing use of raw materials and in-process feedstock.

The following table summarizes storage capacity at the oil refinery as of September 30, 2006 which we believe is sufficient for our current needs:


Product	Capacity (barrels)

Gasoline		767,000
Distillates		1,068,000
Intermediates		1,004,000
Crude oil(1)		1,194,000


(1)		Crude oil storage consists of 674,000 barrels of refinery storage capacity and 520,000 barrels of field storage capacity.

Distribution Pipelines and Product Terminals

We focus our marketing efforts on the midwestern states of Oklahoma, Kansas, Missouri, Nebraska, and Iowa for the sale of our petroleum products because of their relative proximity to our oil refinery and their pipeline access. Since the Subsequent Acquisition, we have significantly expanded our rack sales directly to the customers as opposed to origin bulk sales. Rack sales are sales which are made using tanker trucks via either a proprietary or third party terminal facility designed for truck loading. In contrast, bulk sales are sales made through pipelines. Currently, approximately 23% of the refinery’s products are sold through the rack system directly to retail and wholesale customers while the remaining 77% is sold through pipelines via bulk spot and term contracts.

We are able to distribute gasoline, diesel fuel, and natural gas liquids produced at the refinery either into the Magellan or Enterprise pipeline and further on through Valero and other Magellan systems or via the trucking system. The Magellan #2 and #3 pipelines are connected directly to the refinery and transport products to Kansas City and other northern cities. The Valero and Magellan (Mountain) pipelines are accessible via the Enterprise outbound line or through the Magellan system at El Dorado, Kansas. Our modern three-bay, bottom-loading fuels loading rack has been in service since July 1998 with a maximum delivery capability of 225 trucks per day or 40,000 bpd of finished gasoline and diesel fuels. We own and operate refined fuels and asphalt storage and terminalling facilities in Phillipsburg, Kansas. Our asphalt storage and terminalling facilities are used to receive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement. Our refined fuels truck terminal includes two loading locations with a capacity of approximately 95 trucks per day.

Below is a detailed summary of our product distribution pipelines and their capacities:


Pipeline	Capacity (bpd)

Magellan Pipeline #3-8” Line (from Coffeyville to northern cities via Caney, Kansas)		32,000
Magellan Pipeline #2-10” Line (from Coffeyville to northern cities via Barnsdall, Oklahoma)		81,000
Enterprise Pipeline (provides accessibility to Magellan (Mountain) and Valero systems at El Dorado, Kansas)		12,000
Truck Loading Rack Delivery System		40,000

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The following map depicts part of the Magellan pipeline, which the oil refinery uses for the majority of its distribution.

Source: Magellan Midstream Partners, L.P.

Nitrogen Fertilizer Business

We operate the only nitrogen fertilizer plant in North America that utilizes a coke gasification process to generate hydrogen feedstock that is further converted to ammonia for the production of nitrogen fertilizers. We are also considering a fertilizer plant expansion, which we estimate could increase our capacity to upgrade ammonia into premium priced UAN by 50% to approximately 1,000,000 tons per year.

Our facility uses a gasification process licensed from The General Electric Company, or General Electric, to convert pet coke to high purity hydrogen for subsequent conversion to ammonia. It uses between 950 to 1,050 tons per day of pet coke from the refinery and another 250 to 300 tons per day from unaffiliated, third-party sources such as other Midwestern refineries or pet coke brokers and converts it all to approximately 1,200 tons per day of ammonia. Our fertilizer plant has demonstrated consistent levels of production at levels close to full capacity and has the following advantages compared to competing natural gas-based facilities:

Significantly Lower Cost Position. Our coke gasification process allows us to use less than 1% of the natural gas relative to other nitrogen based fertilizer facilities that are heavily dependent upon natural gas and are thus heavily impacted by natural gas price swings. Because our plant uses pet coke, we have a significant cost advantage over other North American natural gas-based fertilizer producers. The adjacent refinery supplies on average more than 80% of our raw material.

Strategic Location with Transportation Advantage. We believe that selling products to customers in close proximity to our UAN plant and reducing transportation costs are keys to maintaining our profitability. Due to our favorable location relative to end users and high product demand relative to production volume all of our product shipments are targeted to freight advantaged destinations located in the U.S. farm belt. The available ammonia production at our nitrogen fertilizer plant is small and easily sold into truck and rail delivery points. Our products leave the plant either in trucks for direct shipment to customers or in railcars for principally Union Pacific Railroad destinations.

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We do not incur any intermediate transfer, storage, barge freight, or pipeline freight charges. Consequently, we estimate that our plant enjoys a distribution cost advantage over U.S. Gulf Coast ammonia and UAN importers, assuming in each case freight rates and handling charges for U.S. Gulf Coast importers as in effect in September 2006. Such cost differentials represent a significant portion of the market price of these commodities. For example, since the end of 2004, ammonia prices have fluctuated between $290 and $424 per ton, and UAN prices have fluctuated between $175 and $230 per ton.

High and Increasing Capacity Utilization. Capacity utilization has increased steadily over the past few years of operation. The gasifier on-stream factor (a measure of how long the gasifier has been operational over a period) was 98.3% and 91.7% for 2005 and for the first nine months of 2006, respectively. We expect that efficiency of the plant will continue to improve with operator training, replacement of unreliable equipment, and reduced dependence on contract maintenance.


	Year Ended
	December 31,								Nine Months Ended September 30,
	2002		2003		2004		2005		2005		2006

Gasifier on-stream(1)		78.6%		90.1%		92.4%		98.1%		98.3%		91.7%
Ammonia capacity utilization(2)		66.0%		83.6%		76.8%		102.9%		103.7%		94.5%
UAN capacity utilization(3)		79.4%		93.3%		97.0%		121.2%		121.0%		113.6%


(1)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period.

(2)		Based on nameplate capacity of 1,100 tons per day.

(3)		Based on nameplate capacity of 1,500 tons per day.

Raw Material Supply

Our nitrogen fertilizer facility’s primary input is pet coke, of which more than 80% on average is supplied by our adjacent oil refinery at market prices. Historically we have obtained a small amount of pet coke from third parties such as other Midwestern refineries or pet coke brokers at spot prices. We believe that optimization of the use of our oil refinery’s coker should reduce the need for purchasing pet coke from third parties. If necessary, the gasifier can also operate on low grade coal, which provides an additional raw material source. There are significant supplies of low grade coal within a 60 mile radius of our plant.

The BOC Group owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to the gasifier for a monthly fee. We provide and pay for all utilities required for operation of the air separation plant. The air separation plant has not experienced any long-term operating problems. The nitrogen fertilizer plant is covered for business interruption insurance for up to $25 million in case of any interruption in the supply of oxygen from The BOC Group from a covered peril. Our agreement with The BOC Group expires in 2020.

We import start-up steam for the fertilizer plant from our adjacent oil refinery, and then export steam back to the oil refinery once all units are in service. Monthly charges and credits are booked with steam valued at the gas price for the month.

Production Process

Our nitrogen fertilizer plant was built in 2000 with a pair of gasifiers to provide reliability. Following a turnaround completed in the second quarter of 2006, the plant is capable of processing approximately 1,300 tons per day of pet coke from the oil refinery and third-party sources and converting it into approximately 1,200 tons per day of ammonia. It uses a gasification process licensed from General Electric to convert the pet coke to high purity hydrogen for subsequent conversion to

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ammonia. A majority of the ammonia is converted to approximately 2,075 tons per day of UAN. Typically 0.41 tons of ammonia are required to produce one ton of UAN.

Pet coke is first ground and blended with water and a fluxant (a mixture of fly ash and sand) to form a slurry that is then pumped into the partial oxidation gasifier. The slurry is then contacted with oxygen from an air separation unit, or ASU. Partial oxidation reactions take place and the synthesis gas, or syngas, consisting predominantly of hydrogen and carbon monoxide, is formed. The mineral residue from the slurry is a molten slag (a glasslike substance containing the metal impurities originally present in coke) and flows along with the syngas into a quench chamber. The syngas and slag are rapidly cooled and the syngas is separated from the slag.

Slag becomes a by-product of the process. The syngas is scrubbed and saturated with moisture. The syngas next flows through a shift unit where the carbon monoxide in the syngas is reacted with the moisture to form hydrogen and carbon dioxide. The heat from this reaction generates saturated steam. This steam is combined with steam produced in the ammonia unit and the excess steam not consumed by the process is sent to the adjacent oil refinery.

After additional heat recovery, the high-pressure syngas is cooled and processed in the acid gas removal, or AGR, unit. The syngas is then fed to a pressure swing absorption, or PSA, unit, where the remaining impurities are extracted. The PSA unit reduces residual carbon monoxide and carbon dioxide levels to trace levels, and the moisture-free, high-purity hydrogen is sent directly to the ammonia synthesis loop.

The hydrogen is reacted with nitrogen from the ASU in the ammonia unit to form the ammonia product. A portion of the ammonia is converted to UAN.

The following is an illustrative Nitrogen Fertilizer Plant Process Flow Chart:

Critical equipment is set up on routine maintenance schedules using our own maintenance technicians. We have a Technical Services Agreement with General Electric which licensed the gasification technology to us. Under this agreement, General Electric experts provide technical advice and technological updates from their ongoing research as well as other licensees’ operating experiences.

We license the coke gasification process from General Electric Company pursuant to a license agreement that will be fully paid up as of June 1, 2007. The license grants us perpetual rights to use the coke gasification process on specified terms and conditions. The license is important to us because it allows us to operate our nitrogen fertilizer facility at a low cost compared to facilities which rely on natural gas.

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Distribution

The primary geographic markets for our fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, and Texas. We market our ammonia products to industrial and agricultural customers and our UAN products to agricultural customers. The direct application agricultural demand from our nitrogen fertilizer plant occurs in three main use periods. The summer wheat pre-plant occurs in August and September. The fall pre-plant occurs in late October and November. The highest level of ammonia demand is traditionally observed in the spring pre-plant period, from March through May. There are also small fill volumes that move in the off-season to fill the available storage at the dealer level.

Ammonia and UAN are distributed by truck or by railcar. If delivered by truck, products are sold on a freight-on-board basis, and freight is normally arranged by the customer. We also own and lease a fleet of railcars. We also negotiate with distributors that have their own leased railcars to utilize these assets to deliver products. We own all of the truck and rail loading equipment at our facility. We operate two truck loading and eight rail loading racks for each of ammonia and UAN.

Sales and Marketing

Petroleum Business

We focus our marketing efforts on the Midwestern states of Oklahoma, Kansas, Missouri, Nebraska, and Iowa and frequently Colorado, as economics dictate, for the sale of our petroleum products because of their relative proximity to our refinery and their pipeline access. Our refinery produces approximately 88,000 bpd of gasoline and distillates, which we estimate was approximately 10% of the demand for gasoline and distillates in our target market area in the first nine months of 2006.

Nitrogen Fertilizer Business

The primary geographic markets for our fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, and Texas. We market our ammonia products to industrial and agricultural customers and our UAN products to agricultural customers. The direct application agricultural demand from our nitrogen fertilizer plant occurs in three main use periods. The summer wheat pre-plant occurs in August and September. The fall pre-plant occurs in late October and in November. The highest level of ammonia demand is traditionally in the spring pre-plant period, from March through May. There are also small fill volumes that move in the off-season to fill the available storage at the dealer level.

We market our agricultural products to destinations that produce the best margins for our business. These markets are primarily located on the Union Pacific railroad or destinations which can be supplied by truck. By securing this business directly, we reduce our dependence on distributors serving the same customer base, which enables us to capture a larger margin and allows us to better control our product distribution. Most of our agricultural sales are made on a competitive spot basis. We also offer products on a prepay basis for in-season demand. The heavy in-season demand periods are spring and fall in the corn belt and summer in the wheat belt. The corn belt is the primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. The wheat belt is the primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas. Some of our industrial sales are spot sales, but most are on annual or multiyear contracts. Industrial demand for ammonia provides consistent sales and allows us to better manage inventory control and generate consistent cash flow.

Customers

Petroleum Business

Customers for our petroleum products include other refiners, convenience store companies, railroads and farm cooperatives. We have bulk term contracts in place with most of these customers,

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which typically extend from a few months to one year in length. Our shipments to these customers are typically in the 10,000 to 60,000 barrel range (420,000 to 2,520,000 gallons) and are delivered by pipeline. We enter into these types of contracts in order to lock in a committed volume at market prices to ensure an outlet for our refinery production. For the year ended December 31, 2005, CHS Inc., SemFuel LP, QuikTrip Corporation and GROWMARK, Inc. accounted for 16.2%, 15.9%, 15.8% and 10.8%, respectively, of our petroleum business sales and for the nine months ended September 30, 2006, they accounted for 2.0%, 11.1%, 15.5% and 10.4%, respectively. We sell bulk products based on industry market related indexes such as Platt’s or NYMEX related Group Market (Midwest) prices.

In addition to bulk sales, we have implemented an aggressive rack marketing initiative. Utilizing the Magellan pipeline system we are able to reach customers such as QuikTrip, Casey’s, Murphy, Hy-Vee, Pilot Travel Centers, Flying J Truck Stops, Krause-Gentel (Kum and Go) and others. Our longer term, target customers may include industrial and commercial end users, railroads, and farm cooperatives that buy in truckload quantities. Truck terminal sales are at daily posted prices which are influenced by competitor pricing and spot market factors. Rack prices are typically higher than bulk prices.

Nitrogen Fertilizer Business

We sell ammonia to agricultural and industrial customers. We sell approximately 80% of the ammonia we produce to agricultural customers, such as farmers in the mid-continent area between North Texas and Canada, and approximately 20% to industrial customers. Our agricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., Interchem, GROWMARK, Inc., Mid West Fertilizer Inc., DeBruce Grain, Inc., and Agriliance, LLC. Our industrial customers include Tessenderlo Kerley, Inc. and Truth Chemical. We sell UAN products to retailers and distributors. For the year ended December 31, 2005 and the nine months ended September 30, 2006, our top five ammonia customers in the aggregate represented 55.2% and 49.6% of our ammonia sales, respectively, and our top five UAN customers in the aggregate represented 43.1% and 30.0% of our UAN sales, respectively. During the year ended December 31, 2005, Brandt Consolidated Inc. and MFA accounted for 23.3% and 13.6% of our ammonia sales, respectively, and Agriliance and ConAgra Fertilizer accounted for 14.7% and 12.7% of our UAN sales, respectively. During the nine months ended September 30, 2006, Brandt Consolidated Inc. and MFA accounted for 21.1% and 12.6% of our ammonia sales, respectively, and Agriliance and ConAgra Fertilizer accounted for 7.8% and 5.6% of our UAN sales, respectively.

Competition

We have experienced and expect to continue to meet significant levels of competition from current and potential competitors, many of whom have significantly greater financial and other resources. See “Risk Factors — Risks Related to Our Petroleum Business — We face significant competition, both within and outside of our industry. Competitors who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us” and “Risk Factors — Risks Related to Our Nitrogen Fertilizer Business — Our fertilizer products are global commodities, and we face intense competition from other nitrogen fertilizer producers.”

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Petroleum Business

Our oil refinery in Coffeyville, Kansas ranks third in processing capacity and fifth in refinery complexity, among the seven mid-continent fuels refineries. The following table presents certain information about us and the six other major mid-continent fuel oil refineries with which we compete:

Crude Capacity

Solomon

(barrels per

Complexity

Company

Location

calendar day)

Index

ConocoPhillips

Ponca City, OK

187,000

12.5

Frontier Oil

El Dorado, KS

110,000

13.3

CVR Energy

Coffeyville, KS

108,000

10.0

Valero

Ardmore, OK

88,000

11.3

NCRA

McPherson, KS

82,200

14.1

Gary Williams Energy

Wynnewood, OK

52,500

8.0

Sinclair

Tulsa, OK

50,000

8.3

Mid-continent Total:

677,700

Source: Oil and Gas Journal. A Sunoco refinery located in Tulsa, Oklahoma was excluded from this table because it is not a stand-alone fuels refinery.

We compete with our competitors primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are costs of crude oil and other feedstock costs, refinery complexity (a measure of a refinery’s ability to convert lower cost heavy and sour crudes into greater volumes of higher valued refined products such as gasoline), refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refinery provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors.

Our competitors include trading companies such as SemFuel, L.P., Western Petroleum, Center Oil, Tauber Oil Company, Morgan Stanley and others. In addition to competing refineries located in the mid-continent United States, our oil refinery also competes with other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the U.S. Gulf Coast and the Texas Panhandle region.

Our refinery competition also includes branded, integrated and independent oil refining companies such as BP, Shell, ConocoPhillips, Valero, Sunoco and Citgo, whose strengths include their size and access to capital. Their branded stations give them a stable outlet for refinery production although the branded strategy requires more working capital and a much more expensive marketing organization.

Nitrogen Fertilizer Business

Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. We maintain a large fleet of rail cars and we seasonally adjust inventory to enhance our manufacturing and distribution operations.

Domestic competition, mainly from regional cooperatives and integrated multinational fertilizer companies, is intense due to customers’ sophisticated buying tendencies and production strategies that focus on cost and service. Also, foreign competition exists from producers of fertilizer products manufactured in countries with lower cost natural gas supplies. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments. Our major competitors include Koch Nitrogen, Terra and CF Industries, among others.

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Our nitrogen fertilizer plant’s main competition in ammonia marketing are Koch’s plants at Beatrice, Nebraska, Dodge City, Kansas and Enid, Oklahoma, as well as Terra’s plants in Verdigris and Woodward, Oklahoma and Port Neal, Iowa.

Based on Fertecon and Blue Johnson research, our UAN production represents approximately 5.3% of the total U.S. demand. The net ammonia produced and marketed at Coffeyville represents less than 1% of the total U.S. demand.

Seasonality

Petroleum Business

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

Nitrogen Fertilizer Business

A significant portion of our nitrogen fertilizer product sales consists of sales of agricultural commodity products, exposing us to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, our nitrogen fertilizer business typically generates greater net sales and operating income in the spring. In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers who make planting decisions based largely on the prospective profitability of a harvest. The specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

Environmental Matters

Our business and operations are subject to extensive and frequently changing federal, state and local laws and regulations relating to the protection of the environment. These laws, their underlying regulatory requirements and the enforcement thereof impact our business and operations by imposing:


	•	restrictions on operations and/or the need to install enhanced or additional controls;

	•	the need to obtain and comply with permits and authorizations;

	•	liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities and off-site waste disposal locations; and

	•	specifications for the products we market, primarily gasoline, diesel fuel, UAN and ammonia.

The petroleum refining industry is subject to frequent public and governmental scrutiny of its environmental compliance. As a result, the laws and regulations to which we are subject are often evolving and many of them have become more stringent or become subject to more stringent interpretation or enforcement by federal and state agencies. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws such as the Resource Conservation and Recovery Act, or the RCRA, and the Clean Air Act have not yet been finalized, are under governmental or judicial review or are being revised. These regulations and other

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new air and water quality standards and stricter fuel regulations could result in increased capital, operating and compliance costs.

The principal environmental risks associated with our operations are air emissions, releases of hazardous substances into the environment, and the treatment and discharge of wastewater. The legislative and regulatory programs that affect these areas are outlined below.

The Clean Air Act

The Clean Air Act and its underlying regulations as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air affect our operations both directly and indirectly. Direct impacts may occur through Clean Air Act permitting requirements and/or emission control requirements relating to specific air pollutants. The Clean Air Act indirectly affects our operations by extensively regulating the air emissions of sulfur dioxide, or SO₂, volatile organic compounds, nitrogen oxides and other compounds including those emitted by mobile sources, which are direct or indirect users of our products.

The Clean Air Act imposes stringent limits on air emissions, establishes a federally mandated permit program and authorizes civil and criminal sanctions and injunctions for any failure to comply. The Clean Air Act also establishes National Ambient Air Quality Standards, or NAAQS, that states must attain. If a state cannot attain the NAAQS (i.e., is in nonattainment), the state will be required to reduce air emissions to bring the state into attainment. A geographic area’s attainment status is based on the severity of air pollution. A change in the attainment status in the area where our facilities are located could necessitate the installation of additional controls. At the current time, all areas that we operate in are classified as attainment for NAAQS.

There have been numerous other recently promulgated National Emission Standards for Hazardous Air Pollutants, NESHAP or MACT, including, but not limited to, the Organic Liquid Distribution MACT, the Miscellaneous Organic NESHAP, Gasoline Distribution Facilities MACT, Reciprocating Internal Combustion Engines MACT, Asphalt Processing MACT, Commercial and Institutional Boilers and Process Heaters standards. Some or all of these MACT standards or future promulgations of MACT standards may require the installation of controls or changes to our operations in order to comply. If we are required to install controls or change our operations, the costs could be significant. These new requirements, other requirements of the Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to comply and/or permit our refinery to produce products that meet applicable requirements.

Air Emissions. The regulation of air emissions under the Clean Air Act requires us to obtain various operating permits and to incur capital expenditures for the installation of certain air pollution control devices at our refinery. Various regulations specific to, or that directly impact, our industry have been implemented, including regulations that seek to reduce emissions from refineries’ flare systems, sulfur plants, large heaters and boilers, fugitive emission sources and wastewater treatment systems. Some of the applicable programs are the Benzene Waste Operations NESHAP, New Source Performance Standards, New Source Review, and Leak Detection and Repair. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations.

The EPA recently embarked on a Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues — New Source Review, flaring, leak detection and repair, and the Benzene Waste Operations NESHAP. The Petroleum Refining Initiative has resulted in many refiners entering into consent decrees imposing civil penalties and requiring substantial expenditures for additional or enhanced pollution control. At this time, we do not know how, if at all, the Petroleum Refining Initiative will affect us. However, in March 2004, we entered into a Consent Decree with the EPA and the KDHE to resolve air compliance concerns raised by the EPA and KDHE related to Farmland’s prior operation of our oil refinery. The Consent Decree covers some, but not all, of the Petroleum Refining Initiative’s marquee issues.

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Under the Consent Decree, we agreed to install controls on certain process equipment and make certain operational changes at our refinery. As a result of our agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Pursuant to the Consent Decree, in the short term, we have increased the use of catalyst additives to the fluid catalytic cracking unit at the facility to reduce emissions of SO₂. We will begin adding catalyst to reduce oxides of nitrogen, or NOx, in 2007. In the long term, we will install controls to minimize both SO₂ and NOx emissions, which under terms of the Consent Decree require that final controls be in place by January 1, 2011. In addition, pursuant to the Consent Decree, we assumed certain cleanup obligations at the Coffeyville refinery and the Phillipsburg terminal. We agreed to retrofit certain heaters at the refinery with Ultra Low NOx burners. All heater retrofits have been performed and we are currently verifying that the heaters meet the Ultra Low NOx standards required by the Consent Decree. The Ultra Low NOx heater technology is in widespread use throughout the industry. There are other permitting, monitoring, record-keeping and reporting requirements associated with the Consent Decree. The overall cost of complying with the Consent Decree is expected to be approximately $31 million, of which approximately $25 million is expected to be capital expenditures and which does not include the cleanup obligations. No penalties are expected to be imposed as a result of the Consent Decree.

Fertilizer Plant Audit. We conducted an air permitting compliance audit of our fertilizer plant pursuant to agreements with EPA and KDHE immediately after Immediate Predecessor acquired the fertilizer plant in 2004. The audit revealed that the fertilizer plant was not properly permitted under the Clean Air Act and its implementing regulations and corresponding Kansas environmental statutes and regulations. As a result, the fertilizer plant performed air modeling to demonstrate that the current emissions from the facility are in compliance with federal and state air quality standards, and that the air pollution controls that are in place are the controls that are required to be in place. In the event that the EPA or KDHE determines that additional controls are required, we may incur significant expenditures to comply. The completion of this process requires that we submit a new permit application, which we have done. We are now awaiting the final permit approval from KDHE at which time we will file a Title V air operating permit application that will include the relevant terms and conditions of the new air permit.

Air Permitting. The petroleum refinery is a “major source” of air emissions under the Title V permitting program of the federal Clean Air Act. A final Class I (major source) operating permit was issued for our oil refinery in August 2006. We are currently in the process of amending the Title V permit to include the recently approved expansion project permit and the continuous catalytic reformer permit.

The fertilizer plant has agreed to file a new Title V operating air permit application because the voluntary fertilizer plant audit (described in more detail above) revealed that the fertilizer plant should be permitted as a “major source” of certain air pollutants. In the meantime, the fertilizer plant is operating under the Clean Air Act’s “application shield” (which protects permittees from enforcement while an operating permit is being issued as long as the permittee complies with the permit conditions contained in the permit application), the current construction permits, other KDHE approvals and the protections of the federal and state audit policies. Once the current air permit application is approved, we will file the final Title V permit application that will contain all terms and conditions imposed under the new permit and any other permits and/or approvals in place. We do not anticipate significant cost or difficulty in obtaining these permits. However, in the event that the EPA or KDHE determines that additional controls are required, we may incur significant expenditures to comply.

We believe that we hold all material air permits required to operate the Phillipsburg Terminal and our crude oil transportation company’s facilities.

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Release Reporting

The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting of threshold quantities under federal and state environmental laws. Our operations periodically experience releases of hazardous substances and extremely hazardous substances that could cause us to become the subject of a government enforcement action or third-party claims. We report such releases promptly to federal and state environmental agencies.

Prior to the acquisition of the nitrogen fertilizer plant by Immediate Predecessor in 2004 and during the period the plant was owned by Immediate Predecessor, the facility experienced heat exchanger equipment deterioration at an unanticipated rate, resulting in upset/malfunction air releases of ammonia into the environment. We replaced the equipment in August 2004 with a new metallurgy design that also experienced an unanticipated deterioration rate. The new equipment was subsequently replaced in 2005 by a redesigned exchanger with upgraded metallurgy, which has operated without additional ammonia emissions. Other critical exchanger metallurgy was upgraded during our most recent July 2006 turnaround. We have reported the excess emissions of ammonia to EPA and KDHE as part of an air permitting audit of the facility. Additional equipment, repairs to existing equipment, changes to current operations, government enforcement or third-party claims could result in significant expenditures and liability.

Fuel Regulations

Tier II, Low Sulfur Fuels. The EPA interprets the Clean Air Act to authorize the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. For example, in February 2000, EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the sulfur content of gasoline at any refinery shall not exceed 30 ppm during any calendar year beginning January 1, 2006. These requirements began being phased in during 2004. In addition, in January 2001, EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. EPA adopted a rule for off-road diesel in May 2004. The off-road diesel regulations will generally require a 97% reduction in the sulfur content of diesel sold for off-road use by June 1, 2010.

Modifications will be required at our refinery as a result of the Tier II gasoline and low sulfur diesel standards. In February 2004 EPA granted us approval under a “hardship waiver” that would defer meeting final low sulfur Tier II gasoline standards until January 1, 2011 in exchange for our meeting low sulfur highway diesel requirements by January 1, 2007. We are currently in the startup phase of our Ultra Low Sulfur Diesel Hydrodesulfurization unit, which utilizes technology with widespread use throughout the industry. Based on our preliminary estimates, we believe that compliance with the Tier II gasoline and on-road diesel standards will require us to spend approximately $98 million during 2006 (most of which has already been spent), approximately $18 million during 2007 and approximately $25 million between 2008 and 2010.

Methyl Tertiary Butyl Ether (MTBE). The EPA previously required gasoline to contain a specified amount of oxygen in certain regions that exceed the National Ambient Air Quality Standards for either ozone or carbon monoxide. This oxygen requirement had been satisfied by adding to gasoline one of many oxygen-containing materials including, among others, methyl tertiary butyl ether, or MTBE. As a result of growing public concern regarding possible groundwater contamination resulting from the use of MTBE as a source of required oxygen in gasoline, MTBE has been banned for use as a gasoline additive. Neither we nor, to the best of our knowledge, the Successor, the Immediate Predecessor or Farmland used MTBE in our petroleum products. We cannot make any

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assurance as to whether MTBE was added to our petroleum products after those products left our facilities or whether MTBE-containing products were distributed through our pipelines.

The Clean Water Act

The federal Clean Water Act of 1972 affects our operations by regulating the treatment of wastewater and imposing restrictions on effluent discharge into, or impacting, navigable water. Regular monitoring, reporting requirements and performance standards are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water. We maintain numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the Clean Water Act and have implemented internal programs to oversee our compliance efforts.

All of our facilities are subject to Spill Prevention, Control and Countermeasures, or SPCC, requirements under the Clean Water Act. The SPCC rules were modified in 2002 with the modifications to go into effect in 2004. In 2004, certain requirements of the rule were extended. Changes to our operations may be required to comply with the modified SPCC rule.

In addition, we are regulated under the Oil Pollution Act. Among other requirements, the Oil Pollution Act requires the owner or operator of a tank vessel or facility to maintain an emergency oil response plan to respond to releases of oil or hazardous substances. We have developed and implemented such a plan for each of our facilities covered by the Oil Pollution Act. Also, in case of such releases, the Oil Pollution Act requires responsible parties to pay the resulting removal costs and damages, provides for substantial civil penalties, and authorizes the imposition of criminal and civil sanctions for violations. States where we have operations have laws similar to the Oil Pollution Act.

Wastewater Management. We have a wastewater treatment plant at our refinery permitted to handle an average flow of 2.2 million gallons per day. The facility uses a complete mix activated sludge, or CMAS, system with three CMAS basins. The plant operates pursuant to a KDHE permit. We are also implementing a comprehensive spill response plan in accordance with the EPA rules and guidance.

Ongoing fuels terminal and asphalt plant operations at Phillipsburg generate only limited wastewater flows (e.g., boiler blowdown, asphalt loading rack condensate, groundwater treatment). These flows are handled in a wastewater treatment plant that includes a primary clarifier, aerated secondary clarifier, and a final clarifier to a lagoon system. The plant operates pursuant to a KDHE Water Pollution Control Permit. To control facility runoff, management implements a comprehensive Spill Response Plan. Phillipsburg also has a timely and current application on file with the KDHE for a separate storm water control permit.

Resource Conservation and Recovery Act (RCRA)

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

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

We have set aside approximately $3.2 million in financial assurance for closure/post-closure care for hazardous waste management units at the Phillipsburg terminal and the Coffeyville refinery.

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Impacts of Past Manufacturing. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and ground water conditions, which require investigation or remediation projects. The Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. The Consent Decree that we signed with EPA and KDHE requires us to complete all activities in accordance with federal and state rules.

The anticipated remediation costs through 2010 were estimated, as of September 30, 2006, to be as follows:


							Total
	Site				Total O&M		Estimated
	Investigation		Capital		Costs		Costs
Facility	Costs		Costs		Through 2010		Through 2010

Coffeyville Oil Refinery	$	0.5	$	–	$	1.0	$	1.5
Phillipsburg Terminal		0.3		–		1.9		2.2

Total Estimated Costs	$	0.8	$	–	$	2.9	$	3.7

These estimates are based on current information and could go up or down as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years, we will spend between $5.4 and $6.8 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the Phillipsburg terminal. It is possible that additional costs will be required after this ten year period.

Environmental Insurance. We have entered into several environmental insurance policies as part of our overall risk management strategy. Our pollution legal liability policy provides us with an aggregate limit of $50.0 million subject to a $1.0 million self-insured retention. This policy covers cleanup costs resulting from pre-existing or new pollution conditions and bodily injury and property damage resulting from pollution conditions. It also includes a $25.0 million business interruption sub-limit subject to a ten day waiting period. We also have a financial assurance policy that provides a $4.0 million limit per pollution incident and an $8.0 million aggregate policy limit related specifically to closed RCRA units at the Coffeyville refinery and the Phillipsburg terminal. Each of these policies contains substantial exclusions; as such, we cannot guarantee that we will have coverage for all or any particular liabilities.

Financial Assurance. We were required in the Consent Decree to establish $15 million in financial assurance to cover the projected cleanup costs posed by the Coffeyville and Phillipsburg facilities in the event our company ceased to operate as a going concern. In accordance with the Consent Decree, this financial assurance is currently provided by a bond posted by Original Predecessor, Farmland. We will be required to replace the financial assurance currently provided by Farmland. If the financial assurance is not replaced by March 3, 2007, we must reimburse Farmland through eight equal quarterly payments beginning in April 2007. At this point, it is not clear what the amount of financial assurance will be when replaced. Although it may be significant, it is unlikely to be more than $15 million. The form of this financial assurance that will be required by EPA (cash, letter of credit, financial test, etc.) has not been determined.

Environmental Remediation

Under the Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property

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when the release occurred, and any persons who disposed of, or arranged for the disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, retroactive and joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. The liability of a party is determined by the cost of investigation and remediation, the portion of the hazardous substance(s) the party contributed, the number of solvent potentially responsible parties, and other factors.

As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters. These matters include soil and water contamination, personal injury and property damage allegedly caused by hazardous substances which we, or potentially Farmland, manufactured, handled, used, stored, transported, spilled, released or disposed of. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or that, if we were held responsible for damages in any existing or future proceedings, such costs would be covered by insurance or would not be material.

Safety and Health Matters

We operate a comprehensive safety program, involving active participation of employees at all levels of the organization. We measure our success in this area primarily through the use of injury frequency rates administered by the Occupational Safety and Health Administration, or OSHA. In 2005, our oil refinery experienced a 45% reduction in injury frequency rates and our nitrogen fertilizer plant experienced a 59% reduction in such rate as compared to the average of previous years. The recordable injury rate reflects the number of recordable incidents (injuries as defined by OSHA) per 200,000 hours worked, and for the year ended December 31, 2005, we had a recordable injury rate of 2.66 in our petroleum business and 2.98 in our nitrogen fertilizer business. Despite our efforts to achieve excellence in our safety and health performance, we cannot assure you that there will not be accidents resulting in injuries or even fatalities. We have implemented a new incident investigation program that is intended to improve the safety for our employees by identifying the root cause of accidents and potential accidents and by correcting conditions that could cause or contribute to accidents or injuries. We routinely audit our programs and consider improvements in our management systems.

Process Safety Management. We maintain a Process Safety Management program. This program is designed to address all facets associated with OSHA guidelines for developing and maintaining a Process Safety Management program. We will continue to audit our programs and consider improvements in our management systems.

We have evaluated and continue to implement improvements at our refinery’s process units, underground process piping and emergency isolation valves for control of process flows. We currently estimate the costs for implementing any recommended improvements to be between $7 and $9 million over a period of four years. These improvements, if warranted, would be intended to reduce the risk of releases, spills, discharges, leaks, accidents, fires or other events and minimize the potential effects thereof. We are currently completing the addition of a new $25 million refinery flare system that will replace atmospheric sumps in our refinery. We are also assessing the potential impacts on building occupancy caused by the location and design of our refinery and fertilizer plant control rooms and operator shelters. We expect the costs to upgrade or relocate these areas to be between $3 and $5 million over two to five years. The current plan would consolidate the refinery control boards and equipment into a central control building that would also house operations and technical personnel and would lead to improved communication and efficiency for operation of the refinery.

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

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Community Advisory Panel (CAP). We developed and continue to support ongoing discussions with the community to share information about our operations and future plans. Our CAP includes wide representation of residents, business owners and local elected representatives for the city and county.

Employees

As of September 30, 2006, we had a total of 582 employees, of which 408 were employed in our petroleum business and 109 were employed by our nitrogen fertilizer business. The remaining 65 employees were employed at our offices in Sugar Land, Texas and Kansas City, Kansas.

We entered into collective bargaining agreements which cover approximately 39% of our employees with the Metal Trades Union and the United Steelworkers of America, which expire in March 2009. We believe that our relationship with our employees is excellent.

Properties

Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas. We lease approximately 22,000 square feet at that location. Rent under the lease is currently approximately $470,000 annually, plus operating expenses, increasing to approximately $500,000 in 2009. The lease expires in 2011. The following table contains certain information regarding our other principal properties:


Location	Acres	Own/Lease	Use

Coffeyville, KS	440	Own	Oil refinery, nitrogen plant and office buildings
Phillipsburg, KS	200	Own	Terminal facility
Montgomery County, KS (Coffeyville Station)	20	Own	Crude oil storage
Montgomery County, KS (Broome Station)	20	Own	Crude oil storage
Bartlesville, OK	25	Own	Truck storage and office buildings
Winfield, KS	5	Own	Truck storage
Cushing, OK	65	Own	Crude oil storage
	additional 120 acres pending
Cowley County, Kansas (Hooser Station)	80	Own	Crude oil storage
Holdrege, NE	7	Own	Crude oil storage
Stockton, KS	6	Own	Crude oil storage
Kansas City, KS	19,000 (square feet)	Lease	Office space

Rent under our lease for the Kansas City office space is approximately $195,000 annually, plus a portion of operating expenses and taxes, increasing to approximately $215,000 in 2007 and $222,000 in 2008. The lease expires in 2009. We expect that our current owned and leased facilities will be sufficient for our needs over the next twelve months.

Legal Proceedings

We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described above under “— Environmental Matters.” We are not party to any pending legal proceedings that we believe will have a material impact on our business, and there are no existing legal proceedings where we believe that the reasonably possible loss or range of loss is material.

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MANAGEMENT

Executive Officers and Directors

Prior to this offering, our business was operated by Coffeyville Acquisition LLC and its subsidiaries. In connection with the offering, Coffeyville Acquisition LLC formed a wholly owned subsidiary, CVR Energy, Inc., which will own all of Coffeyville Acquisition LLC’s subsidiaries and which will conduct our business through its subsidiaries following this offering. The following table sets forth the names, positions and ages (as of September 30, 2006) of each person who has been an executive officer or director of Coffeyville Acquisition LLC and who will be an executive officer or director of CVR Energy, Inc. upon completion of this offering.


Name	Age		Position

John J. Lipinski		55	Chief Executive Officer, President and Director
Stanley A. Riemann		55	Chief Operating Officer
James T. Rens		40	Chief Financial Officer
Edmund S. Gross		55	Vice President, General Counsel and Secretary
Robert W. Haugen		48	Executive Vice President Refining Operations
Wyatt E. Jernigan		54	Executive Vice President Crude Oil Acquisition and Petroleum Marketing
Kevan A. Vick		52	Executive Vice President, General Manager Nitrogen Fertilizer
Christopher G. Swanberg		48	Vice President, Environmental, Health and Safety
Wesley Clark		60	Director
Scott Lebovitz		31	Director
George E. Matelich		50	Director
Stanley de J. Osborne		36	Director
Kenneth A. Pontarelli		36	Director

John J. Lipinski has served as our chief executive officer and president and a member of our board of directors since September 2006 and as chief executive officer and president and a director of Coffeyville Acquisition LLC since June 24, 2005. Mr. Lipinski has more than 34 years experience in the petroleum refining and nitrogen fertilizer industries. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation’s refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen based chemical processing, and lubricant operations, as well as the corporate engineering and construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a Managing Director and Partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski graduated from Stevens Institute of Technology with a Bachelor of Engineering (Chemical) and received a Juris Doctor degree from Rutgers University School of Law.

Stanley A. Riemann has served as chief operating officer of our company and its predecessors since March 3, 2004. Prior to joining our company in March 2004, Mr. Riemann held various positions associated with the Crop Production and Petroleum Energy Division of Farmland Industries, Inc. over 29 years, including, most recently, Executive Vice President of Farmland Industries and President of Farmland’s Energy and Crop Nutrient Division. In this capacity, he was directly responsible for managing the petroleum refining operation and all domestic fertilizer operations, which included the Trinidad and Tobago nitrogen fertilizer operations. His leadership also extended to managing Farmland’s interests in SF Phosphates in Rock Springs, Wyoming and Farmland Hydro, L.P., a phosphate production operation in Florida, and managing all company-wide transportation assets and services. On May 31, 2002, Farmland Industries, Inc. filed for Chapter 11 bankruptcy protection. Mr. Riemann served as a board member and board chairman on several industry organizations including Phosphate Potash Institute, Florida Phosphate Council, and International Fertilizer Association. He currently serves on the Board of The Fertilizer Institute. Mr. Riemann received a bachelor of science from the University of Nebraska and an MBA from Rockhurst University.

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James T. Rens has served as chief financial officer of our company and its predecessors since March 3, 2004. Before joining our company, Mr. Rens was a consultant to the Original Predecessor’s majority shareholder from November 2003 to March 2004, assistant controller at Koch Nitrogen Company from June 2003, which was when Koch acquired the majority of Farmland’s nitrogen fertilizer business, to November 2003 and Director of Finance of Farmland’s Crop Production and Petroleum Divisions from January 2002 to June 2003. From May 1999 to January 2002, Mr. Rens was Controller and chief financial officer of Farmland Hydro L.P. Mr. Rens has spent 15 years in various accounting and financial positions associated with the fertilizer and energy industry. Mr. Rens received a Bachelor of Science degree in accounting from Central Missouri State University.

Edmund S. Gross has served as general counsel of our company and its predecessors since July 2004. Prior to joining Coffeyville Resources, Mr. Gross was Of Counsel at Stinson Morrison Hecker LLP in Kansas City, Missouri from 2002 to 2004, was Senior Corporate Counsel with Farmland Industries, Inc. from 1987 to 2002 and was an associate and later a partner at Weeks,Thomas & Lysaught, a law firm in Kansas City, Kansas, from 1980 to 1987. Mr. Gross received a Bachelor of Arts degree in history from Tulane University, a Juris Doctor from the University of Kansas and an MBA from the University of Kansas.

Robert W. Haugen joined our business on June 24, 2005 and has served as executive vice president, refining, engineering and construction at our company since September 2006 and at Coffeyville Acquisition LLC since April 2006. Mr. Haugen brings 25 years of experience in the refining, petrochemical and nitrogen fertilizer business to our company. Prior to joining us, Mr. Haugen was a Managing Director and Partner of Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. On leave from Prudentia, he served as the Senior Oil Consultant to the Iraqi Reconstruction Management Office for the U.S. Department of State. Prior to joining Prudentia Energy, Mr. Haugen served in numerous engineering, operations, marketing and management positions at the Howell Corporation and at the Coastal Corporation. Upon the merger of Coastal and El Paso in 2001, Mr. Haugen was named Vice President and General Manager for the Coastal Corpus Christi Refinery, and later held the positions of Vice President of Chemicals and Vice President of Engineering and Construction. Mr. Haugen received a B.S. in Chemical Engineering from the University of Texas.

Wyatt E. Jernigan has served as executive vice president of crude oil acquisition and petroleum marketing at our company since September 2006 and at Coffeyville Acquisition LLC since June 24, 2005. Mr. Jernigan has 30 years of experience in the areas of crude oil and petroleum products related to trading, marketing, logistics and business development. Most recently, Mr. Jernigan was Managing Director with Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. Most of his career was spent with Coastal Corporation and El Paso, where he held several positions in crude oil supply, petroleum marketing and asset development, both domestic and international. Following the merger between Coastal Corporation and El Paso in 2001, Mr. Jernigan assumed the role of Managing Director for Petroleum Markets Originations. Mr. Jernigan attended Virginia Wesleyan College, majoring in Sociology, and has training in petroleum fundamentals from the University of Texas.

Kevan A. Vick has served as executive vice president and general manager of Coffeyville Resources Nitrogen Fertilizers Manufacturing at our company since September 2006 and at Coffeyville Resources LLC since March 3, 2004. He has served on the board of directors of Farmland MissChem Limited in Trinidad and SF Phosphates. He has nearly 30 years of experience in the Farmland organization and is one of the most highly respected executives in the nitrogen fertilizer industry, known for both his technical expertise and his in-depth knowledge of the commercial marketplace. Prior to joining Coffeyville Resources LLC, he was general manager of nitrogen manufacturing at Farmland from January 2001 to February 2004. Mr. Vick received a bachelor of science in chemical engineering from the University of Kansas and is a licensed professional engineer in Kansas, Oklahoma, and Iowa.

Christopher G. Swanberg has served as vice president environmental, health and safety at our company since September 2006 and at Coffeyville Resources LLC since June 24, 2005. He has

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served in numerous management positions in the petroleum refining industry such as Manager, Environmental Affairs for the refining and marketing division of Atlantic Richfield Company (ARCO), and Manager, Regulatory and Legislative Affairs for Lyondell-Citgo Refining. Mr. Swanberg’s experience includes technical and management assignments in project, facility and corporate staff positions in all environmental, safety and health areas. Prior to joining Coffeyville Resources, he was Vice President of Sage Environmental Consulting, an environmental consulting firm focused on petroleum refining and petrochemicals, from September 2002 to June 2005 and Senior HSE Advisor of Pilko & Associates, LP from September 2000 to September 2002. Mr. Swanberg received a B.S. in Environmental Engineering Technology from Western Kentucky University and an MBA from the University of Tulsa.

Wesley Clark has been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLC since September 20, 2005. Since March 2003 he has been the Chairman and Chief Executive Officer of Wesley K. Clark & Associates, a business services and development firm based in Little Rock, Arkansas. Mr. Clark also serves as senior advisor to GS Capital Partners V Fund, L.P. From March 2001 to February 2003 he was a Managing Director of the Stephens Group Inc. From July 2000 to March 2001 he was a consultant for Stephens Group Inc. Prior to that time, Mr. Clark served as the Supreme Allied Commander of NATO and Commander-in-Chief for the United States European Command and as the Director of the Pentagon’s Strategic Plans and Policy operation. Mr. Clark retired from the United States Army as a four-star general in July 2000 after 38 years in the military and received many decorations and honors during his military career. Mr. Clark is a graduate of the United States Military Academy and studied as a Rhodes Scholar at the Magdalen College at the University of Oxford. Mr. Clark is a director of Argyle Security Acquisition Corp.

Scott Lebovitz has been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLC since June 24, 2005. Mr. Lebovitz is a Vice President in the Merchant Banking Division of Goldman, Sachs & Co. Mr. Lebovitz joined Goldman Sachs in 1997. He is a director of Village Voice Media Holdings, LLC. He received his B.S. in Commerce from the University of Virginia.

George E. Matelich has been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLC since June 24, 2005. Mr. Matelich has been a Managing Director of Kelso & Company since 1990. Mr. Matelich has been affiliated with Kelso since 1985. Mr. Matelich is a Certified Public Accountant and holds a Certificate in Management Consulting. Mr. Matelich received an M.B.A. (Finance and Business Policy) from the Stanford Graduate School of Business. He is a director of Global Geophysical Services, Inc. and Waste Services, Inc. Mr. Matelich is also a Trustee of the University of Puget Sound.

Stanley de J. Osborne has been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLC since June 24, 2005. Mr. Osborne has been a Vice President of Kelso & Company since 2004. Mr. Osborne has been affiliated with Kelso since 1998. Prior to joining Kelso, Mr. Osborne was an Associate at Summit Partners. Previously, Mr. Osborne was an Associate in the Private Equity Group and an Analyst in the Financial Institutions Group at J.P. Morgan & Co. He received a B.A. in Government from Dartmouth College. Mr. Osborne is a director of Custom Building Products, Inc. and Traxys S.A.

Kenneth A. Pontarelli has been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLC since June 24, 2005. Mr. Pontarelli is a managing director in the Merchant Banking Division of Goldman, Sachs & Co. Mr. Pontarelli joined Goldman, Sachs & Co. in 1992 and became a managing director in 2004. He is a director of Cobalt International Energy, L.P., an oil and gas exploration and development company, Horizon Wind Energy LLC, a developer, owner and operator of wind power projects, and NextMedia Group, Inc., a privately owned radio broadcasting and outdoor advertising company. He received a B.A. from Syracuse University and an M.B.A. from Harvard Business School.

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Board of Directors

Our board of directors consists of six members. The current directors are included above. Our directors are elected annually to serve until the next annual meeting of stockholders or until their successors are duly elected and qualified.

Prior to the completion of this offering, our board will have an audit committee, a compensation committee and a nominating and corporate governance committee. Our board of directors has determined that we are a “controlled company” under the rules of , and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements of the .

Audit Committee. Our audit committee will be comprised of Messrs. , , and . The audit committee’s responsibilities will be to review the accounting and auditing principles and procedures of our company with a view to providing for the safeguard of our assets and the reliability of our financial records by assisting the board of directors in monitoring our financial reporting process, accounting functions and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent accountants; to review with the independent accountants the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters.

Compensation Committee. Our compensation committee will be comprised of Messrs. , , and . The principal responsibilities of the compensation committee will be to establish policies and periodically determine matters involving executive compensation, recommend changes in employee benefit programs, grant or recommend the grant of stock options and stock awards and provide counsel regarding key personnel selection.

Nominating and Corporate Governance Committee. Our nominating and corporate governance committee will be comprised of Messrs. , , and . The principal duties of the nominating and corporate governance committee will be to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings and to develop and make recommendations to the board of directors regarding corporate governance matters and practices.

Compensation Committee Interlocks and Insider Participation

Mr. Lipinski, our chief executive officer, served on the compensation committee of Coffeyville Acquisition LLC during 2005 and 2006. Otherwise, no interlocking relationship exists between our board of directors or compensation committee and the board of directors or compensation committee of any other company.

Director Compensation

Non-employee directors who do not work for entities affiliated with us are entitled to receive an annual retainer of $60,000. In addition, all directors are reimbursed for travel expenses and other out-of-pocket costs incurred in connection with their attendance at meetings.

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Executive Compensation

The following table sets forth certain information with respect to compensation for the year ended December 31, 2005 earned by our chief executive officer, former chief executive officer and our four other most highly compensated executive officers as of December 31, 2005. In this prospectus, we refer to these individuals as our named executive officers.

Summary Compensation Table


	Annual Compensation						All Other
Name and Principal Position	Year		Salary		Bonus(1)		Compensation

John J. Lipinski		2005		315,000		1,336,301		2,633,925	(2)
Chief Executive Officer
Philip L. Rinaldi		2005		180,385		—		382,599	(3)
Former Chief Executive Officer(4)
Stanley A. Riemann		2005		329,410		896,012		1,178,595	(5)
Chief Operating Officer
Kevan A. Vick		2005		183,061		307,931		609,641	(6)
Executive Vice President General Manager Nitrogen Fertilizer
James T. Rens		2005		211,346		269,971		609,641	(7)
Chief Financial Officer
Wyatt E. Jernigan		2005		116,346		340,515		609,641	(8)
Executive Vice President Crude Oil Acquisition and Petroleum Marketing


(1)		Bonuses are reported for the year in which they were earned, though they may have been paid the following year.

(2)		Includes the value of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”

(3)		Includes (1) a lump sum severance payment of $173,999.72 (which represents six months of base salary equal to $175,000 less the aggregate of Mr. Rinaldi’s share of premium payments for continuing health care coverage), (2) $3,470.40, which represents the dollar value of the company’s cost of continued health care coverage for six months, (3) $91,000, which represents a pro rata portion of Mr. Rinaldi’s 2005 bonus paid as a component of severance (4) $36,346, which represents 5.4 weeks of earned but unused vacation and paid time off, (5) $15,000 in lieu of outplacement services, (6) $23,332.99, which represents two months’ salary in lieu of receiving two months’ written notice from us less an amount paid by us to Mr. Rinaldi subsequent to his termination date of $35,000.01, (7) $30,000, which amount represents payment for consulting services provided by Mr. Rinaldi following his termination of employment and (8) $9,450, which represents a pre-separation company contribution under the company’s 401(k) plan in 2005.

(4)		Mr. Rinaldi served as Chief Executive officer from March 3, 2004 to June 24, 2005.

(5)		Includes (1) a company contribution of $9,450 under the company’s 401(k) plan in 2005 and (2) $1,169,145, which represents the value of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash

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		flows. The profit interests are more fully described below under “Executives’ Interests in Coffeyville Acquisition LLC.”

(6)		Includes (1) a company contribution of $9,450 under the company’s 401(k) plan in 2005 and (2) $600,191, which represents the value of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”

(7)		Includes (1) a company contribution of $9,450 under the company’s 401(k) plan in 2005 and (2) $600,191, which represents the value of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”

(8)		Includes (1) a company contribution of $9,450 under the company’s 401(k) plan in 2005 and (2) $600,191, which represents the value of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”

Employment Agreements, Separation and Consulting Agreement and Other Arrangements

Employment Agreements

John J. Lipinski. On July 12, 2005, Coffeyville Resources, LLC entered into an employment agreement with Mr. Lipinski, as Chief Executive Officer. The agreement has a rolling term of three years so that at the end of each month it automatically renews for one additional month, or the Rolling Contract Period, unless otherwise terminated by us or Mr. Lipinski. Mr. Lipinski receives an annual base salary of $650,000. Mr. Lipinski is eligible to receive a performance-based annual cash bonus with a target payment equal to 75% (250% effective January 1, 2007) of his annual base salary to be based upon individual and/or company performance criteria as established by the board of directors of Coffeyville Resources, LLC for each fiscal year. The agreement provides that, for the period during which he was employed in 2005, Mr. Lipinski was eligible to receive a portion of his annual bonus pro-rated for the number of days Mr. Lipinski was employed during such period and based upon the individual and/or Company performance criteria established by the board of directors of Coffeyville Resources, LLC for such period. For the years prior to 2007, in addition to his annual bonus, Mr. Lipinski is eligible to participate in any special bonus program that the board of directors of Coffeyville Resources, LLC may implement to reward senior management for extraordinary performance on terms and conditions established by such board.

If Mr. Lipinski’s employment is terminated either by Coffeyville Resources, LLC without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in Mr. Lipinski’s agreement), then Mr. Lipinski is entitled to receive as severance (a) salary continuation for 36 months and (b) the continuation of medical benefits for thirty-six months at active-employee rates or until such time as Mr. Lipinski becomes eligible for medical benefits from a subsequent employer. If Mr. Lipinski’s employment is terminated as a result of his disability, then in addition to any payments to be made to Mr. Lipinski under disability plan(s), Mr. Lipinski is entitled to supplemental disability payments equal to, in the aggregate, Mr. Lipinski’s base salary as in effect immediately before his disability. Such supplemental disability payments will be made for a period of 36 months from the date of disability. If Mr. Lipinski’s employment is terminated at any time during the Rolling Contract Period by reason of his death, then Mr. Lipinski’s beneficiary (or his estate) will be paid the

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base salary Mr. Lipinski would have received had he remained employed through such date. Notwithstanding the foregoing, Coffeyville Resources, LLC may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski’s supplemental disability payments or the payments due to Mr. Lipinski’s beneficiary or estate by reason of his death. Mr. Lipinski will be required to cooperate in obtaining such insurance. If any payments or distributions due to Mr. Lipinski would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code of 1986, as amended, then such payments or distributions will be “cutback” so that they will no longer be subject to the excise tax.

The agreement requires Mr. Lipinski to abide by restrictive covenants relating to non-disclosure, non-solicitation and non-competition during his employment and for specified periods following termination of his employment.

Stanley A. Riemann, Kevan A. Vick, James T. Rens and Wyatt E. Jernigan. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Mr. Riemann, as Chief Operating Officer; Mr. Vick, as Executive Vice President — General Manager Nitrogen Fertilizer; Mr. Rens, as Chief Financial Officer; and Mr. Jernigan, as Executive Vice President — Crude Oil Acquisition and Petroleum Marketing. The agreements have a term of three years and expire on June 24, 2008, unless otherwise terminated earlier by the parties. The agreements provide for an annual base salary of $350,000 for Mr. Riemann, $250,000 for Mr. Rens, $225,000 for Mr. Jernigan and $200,000 for Mr. Vick ($225,000 effective January 1, 2007). Each executive is eligible to receive a performance-based annual cash bonus with a target payment equal to 52% of his annual base salary (60% for Mr. Riemann) to be based upon individual and/or company performance criteria as established by the board of directors of Coffeyville Resources, LLC for each fiscal year. Effective January 1, 2007, the target annual bonus percentages are as follows: Mr. Reimann (200%), Mr. Vick (60%), Mr. Rens (120%) and Mr. Jernigan (100%). For the year 2005, each executive was also eligible to receive an annual bonus under the 2005 Coffeyville Resources, LLC and Affiliated Companies Performance Based Income Sharing Plan with appropriate adjustments to the performance criteria thereunder to reflect the impact, if any, of the transactions that were contemplated in the Stock Purchase Agreement among Coffeyville Acquisition LLC and the other parties thereto, dated May 15, 2005. For the years prior to 2007, in addition to their annual bonuses, the executives are eligible to participate in any special bonus program that the board of directors of Coffeyville Resources, LLC may implement to reward senior management for extraordinary performance on terms and conditions established by the board of directors of Coffeyville Resources, LLC. Mr. Riemann’s agreement provides that he will receive retention bonuses of approximately $245,833 in the aggregate during the years 2006 and 2007. Mr. Vick’s agreement provides that he will receive retention bonuses of approximately $105,115 in the aggregate during the years 2006 and 2007.

If an executive’s employment is terminated either by Coffeyville Resources, LLC without cause and other than for disability or by the executive for good reason (as such terms are defined in the relevant agreement), then the executive is entitled to receive as severance (a) salary continuation for 12 months (18 months for Mr. Riemann) and (b) the continuation of medical benefits for 12 months (18 months for Mr. Riemann) at active-employee rates or until such time as the executive becomes eligible for medical benefits from a subsequent employer. The agreements provide that if any payments or distributions due to an executive would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code, as amended, then such payments or distributions will be “cutback” so that they will no longer be subject to the excise tax.

The agreements require each of the executives to abide by restrictive covenants relating to non-disclosure, non-solicitation and non-competition during their employment and for specified periods following termination of their employment.

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Separation and Consulting Agreement with Philip L. Rinaldi

Mr. Rinaldi served as chief executive officer from March 3, 2004 until June 24, 2005. In connection with his separation, Coffeyville Resources, LLC entered into a separation and consulting agreement with him. This agreement provides that Mr. Rinaldi would continue to provide various consulting services for one month commencing on the termination date in exchange for a consulting fee equal to $30,000. Mr. Rinaldi was previously a party to an employment agreement, and the following payments were provided pursuant to that agreement in connection with his separation: (a) a lump sum payment equal to six months’ of his base salary less his aggregate share of premium payments for continuing health care coverage (the total payment equaling approximately $174,000), (b) the continuation of his health care benefits for a period of six months and (c) an amount equal to approximately $165,679, which amount represents a pro rata portion of Mr. Rinaldi’s 2005 bonus, earned but unused vacation and paid time off, payment in lieu of outplacement services and salary in lieu of notice of termination that was required under his employment agreement. Mr. Rinaldi was subject to six-month post-separation non-solicitation and non-competition covenants. Mr. Rinaldi remains subject to a confidentiality covenant.

Stock Incentive Plan

We intend to adopt a stock incentive plan under which certain of our executives and employees may be granted options or other equity based compensation in respect of our stock. The stock incentive plan will be designed to enable us to attract, retain and motivate our officers and employees and to further align their interests with those of our stockholders by providing for, or increasing, their ownership interests in us.

Executives’ Interests in Coffeyville Acquisition LLC

The following is a summary of the material terms of the Coffeyville Acquisition LLC Second Amended and Restated Limited Liability Company Agreement, or the LLC Agreement, as they relate to the limited liability interests granted to our named executive officers (with the exception of Mr. Rinaldi) pursuant to the LLC Agreement as of September 30, 2006.

General

The LLC Agreement provides for two classes of interests in Coffeyville Acquisition LLC: common units and override units (which consist of either operating units or value units) (Common units and override units are collectively referred to as units). The common units provide for voting rights and have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition LLC. Such voting rights cease, however, if the executive holding common units ceases to provide services to Coffeyville Acquisition LLC or one of its subsidiaries. The common units were issued to our named executive officers in the following amounts in exchange for an initial capital contribution of $10 per common unit: Mr. Lipinski (65,000 units), Mr. Riemann (40,000 units), Mr. Rens (25,000 units), Mr. Vick (25,000 units) and Mr. Jernigan (10,000 units). These named executive officers were also granted override units, which consist of operating units and value units, in the following amounts: Mr. Lipinski (315,818 operating units and 631,637 value units), Mr. Riemann (140,185 operating units and 280,371 value units), Mr. Rens (71,965 operating units and 143,931 value units), Mr. Vick (71,965 operating units and 143,931 value units) and Mr. Jernigan (71,965 operating units and 143,931 value units). Override units have no voting rights attached to them, but have the rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition LLC. Our named executive officers were not required to make any capital contribution with respect to the override units; override units were issued only to certain members of management who own common units and who agree to provide services to Coffeyville Acquisition LLC. In addition, common units were issued to the following executive officers in the following amounts in exchange for an initial capital contribution of $10 per common unit: Mr. Robert W. Haugen (10,000 units), Mr. Edmund Gross (3,000 units) and Mr. Chris Swanberg

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(2,500 units). Mr. Haugen was also granted override units in the following amounts: 71,965 operating units and 143,931 value units.

If all of our shares held by Coffeyville Acquisition LLC were sold at our initial public offering price and cash was distributed to members pursuant to the LLC Agreement, our named executive officers would receive a cash payment in respect of their override units in the following approximate amounts: Mr. Lipinski ($ ), Mr. Riemann ($ ), Mr. Rens ($ ), Mr. Vick ($ ) and Mr. Jernigan ($ ).

Forfeiture of Override Units Upon Termination of Employment

If the executive ceases to provide services to Coffeyville Acquisition LLC or a subsidiary due to a termination for “Cause” (as such term is defined in the LLC Agreement), the executive will forfeit all of his override units. If the executive ceases to provide services for any reason other than Cause before the fifth anniversary of the date of grant of his operating units, and provided that an event that is an “Exit Event” (as such term is defined in the LLC Agreement) has not yet occurred and there is no definitive agreement in effect regarding a transaction that would constitute an Exit Event, then (a) unless the termination was due to the Executive’s death or “Disability” (as that term is defined in the LLC Agreement), in which case a different vesting schedule will apply based on when the death or Disability occurs, all value units will be forfeited and (b) a percentage of the operating units will be forfeited according to the following schedule: if terminated before the second anniversary of the date of grant, 100% of operating units are forfeited; if terminated on or after the second anniversary of the date of grant, but before the third anniversary of the date of grant, 75% of operating units are forfeited; if terminated on or after the third anniversary of the date of grant, but before the fourth anniversary of the date of grant, 50% of operating units are forfeited; and if terminated on or after the fourth anniversary of the date of grant, but before the fifth anniversary of the date of grant, 25% of his operating units are forfeited.

Adjustments to Capital Accounts; Distributions

Each of the executives has a capital account under which his balance is increased or decreased, as applicable, to reflect his allocable share of net income and gross income of Coffeyville Acquisition LLC, the capital that the executive contributed, distributions paid to such executive and his allocable share of net loss and items of gross deduction.

Value units owned by the executives do not participate in distributions under the LLC Agreement until the “Current Value” is at least two times the “Initial Price” (as these terms are defined in the LLC Agreement), with full participation occurring when the Current Value is four times the Initial Price and pro rata distributions when the Current Value is between two and four times the Initial Price. The board of directors of Coffeyville Acquisition LLC will determine the “Benchmark Amount” with respect to each override unit at the time of its grant, which for all override units granted as of July 25, 2005, was $10. Coffeyville Acquisition LLC may make distributions to its members to the extent that the cash available to it is in excess of the business’s reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds. Distributions in respect of override units (both operating units and value units), however, will be reduced until the total reductions in proposed distributions in respect of the override units equals the Benchmark Amount (i.e., for override units granted on July 25, 2005, $10). (There is also a catch-up provision with respect to any value unit that was not previously entitled to participate in a distribution because the Current Value was not at least four times the Initial Price.)

Put and Call Rights

The executives have put rights with respect to their common units, so that following their termination of employment, they have the right to sell all (but not less than all) of their common units to Coffeyville Acquisition LLC at their “Fair Market Value” (as that term is defined in the LLC

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Agreement) if they were terminated without “Cause,” or as a result of death, “Disability” or resignation with “Good Reason” (each as defined in the LLC Agreement) or due to “Retirement” (as that term is defined in the LLC Agreement). Coffeyville Acquisition LLC has call rights with respect to the executives’ common units, so that following the executives’ termination of employment, Coffeyville Acquisition LLC has the right to purchase the common units at their Fair Market Value if the executive was terminated without Cause, or as a result of the executive’s death, Disability or resignation with Good Reason or due to Retirement. The call price will be the lesser of the common unit’s Fair Market Value or Carrying Value (which means the capital contribution, if any, made by the executive in respect of such interest less the amount of distributions made in respect of such interest) if the executive is terminated for Cause or he resigns without Good Reason. For any other termination of employment, the call price will be at the Fair Market Value or Carrying Value of such common units, in the sole discretion of Coffeyville Acquisition LLC’s board of directors. No put or call rights apply to override units following the executive’s termination of employment unless Coffeyville Acquisition LLC’s board of directors (or the compensation committee thereof) determines in its discretion that put and call rights will apply.

Other Provisions Relating to Units

The executives are subject to transfer restrictions on their units, although they may make certain transfers of their units for estate planning purposes. The LLC Agreement also provides for certain tag-along and drag-along rights with respect to members’ units.

Coffeyville Resources, LLC Phantom Unit Appreciation Plan

The following is a summary of the material terms of the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (the “Phantom Unit Plan”) as they relate to our named executive officers (with the exception of Mr. Rinaldi and Mr. Vick).

General

The Phantom Unit Plan provides for two classes of interests: Phantom Service Points and Phantom Performance Points (collectively, the “Phantom Points”). Holders of the Phantom Service Points and Phantom Performance Points have the opportunity to receive a cash payment when distributions are made pursuant to the LLC Agreement in respect of Operating Units and Value Units, respectively. The Phantom Points represent a contractual right to receive a payment when payment is made in respect of certain profit interests in Coffeyville Acquisition LLC. Phantom Points have been granted to our named executive officers in the following amounts: Mr. Lipinski (1,368,571 Phantom Service Points and 1,368,571 Phantom Performance Points, which represents 13.7% of the total Phantom Points awarded), Mr. Riemann 596,133 Phantom Service Points and 596,133 Phantom Performance Points, which represents 6.0% of the total Phantom Points awarded), Mr. Rens (495,238 Phantom Service Points and 495,238 Phantom Performance Points, which represents 5.0% of the total Phantom Points awarded) and Mr. Jernigan (148,571 Phantom Service Points and 148,571 Phantom Performance Points, which represents 1.5% of the total Phantom Points awarded). If all of the shares of the Company held by Coffeyville Acquisition LLC were sold at our initial public offering price and cash was distributed to members pursuant to the LLC Agreement, our named executive officers would receive a cash payment in respect of their Phantom Points in the following amounts: Mr. Lipinski ($ ), Mr. Riemann ($ ), Mr. Rens ($ ) and Mr. Jernigan ($ ).

Phantom Point Payments

Payments in respect of Phantom Service Points will be made within 30 days from the date distributions are made pursuant to the LLC Agreement in respect of Operating Units. Cash payments in respect of Phantom Performance Points will be made within 30 days from the date distributions are made pursuant to the LLC Agreement in respect of Value Units (i.e., not until the “Current Value” is at

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least two times the “Initial Price” (as such terms are defined in the LLC Agreement), with full participation occurring when the Current Value is four times the Initial Price and pro rata distributions when the Current Value is between two and four times the Initial Price). There is a catch-up provision with respect to Phantom Performance Points for which no cash payment was made because no distribution pursuant to the LLC Agreement was made with respect to Value Units.

Other Provisions Relating to the Phantom Points

If a participant’s employment is terminated prior to an “Exit Event” (as such term is defined in the LLC Agreement), all of his Phantom Units are forfeited. Phantom Units are generally non-transferable (except by will or the laws of descent and distribution). If payment to a participant in respect of his Phantom Points would result in the application of the excise tax imposed under Section 4999 of the Internal Revenue Code of 1986, as amended, then the payment will be “cutback” so that it will no longer be subject to the excise tax.

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PRINCIPAL AND SELLING STOCKHOLDERS

The following table presents information regarding beneficial ownership of our common stock as of September 30, 2006, and as adjusted to reflect the sale of common stock in this offering by:


	•	each of our directors;

	•	each of our named executive officers;

	•	each stockholder known by us to beneficially hold five percent or more of our common stock;

	•	each selling stockholder who beneficially owns less than five percent of our common stock; and

	•	all of our executive officers and directors as a group.

Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all shares beneficially owned, subject to community property laws where applicable. Shares of common stock subject to options that are currently exercisable or exercisable within 60 days of September 30, 2006 are deemed to be outstanding and to be beneficially owned by the person holding the options for the purpose of computing the percentage ownership of that person but are not treated as outstanding for the purpose of computing the percentage ownership of any other person. Except as otherwise indicated, the business address for each of our beneficial owners is c/o CVR Energy, Inc., 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479.

Prior to this offering, Coffeyville Acquisition LLC owned 100% of our outstanding common stock. Following the closing of this offering, Coffeyville Acquisition LLC will own shares of our common stock, or approximately % of our outstanding common stock, and the Goldman Sachs Funds and the Kelso Funds, along with certain members of management, will beneficially own their interests in our common stock set forth below through their ownership of Coffeyville Acquisition LLC. The information in the table below reflects the number of shares of our common stock that correspond to each named holder’s economic interest in common units in Coffeyville Acquisition LLC and does not reflect any economic interest in operating override units and value override units in Coffeyville Acquisition LLC.

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Shares Beneficially

Owned After this Offering

Owned Prior

Assuming the

to this

Underwriters’ Option Is

Offering

Not Exercised(1)

Exercised(1)

Name and Address

Number

Percent

Number

Percent

Number

Percent

Coffeyville Acquisition LLC(2)(3)(4)

The Goldman Sachs Group, Inc.(2)

85 Broad Street

New York, New York 10004

Kelso Investment
Associates VII, L.P.

KEP VI, LLC(3)

320 Park Avenue, 24th Floor

New York, New York 10022

John J. Lipinski

Stanley A. Riemann

James T. Rens

Edmund S. Gross

Robert W. Haugen

Wyatt E. Jernigan

Kevan A. Vick

Christopher G. Swanberg

Wesley Clark

Scott Lebovitz

George E. Matelich(3)

Stanley de J. Osborne

Kenneth A. Pontarelli

All directors and executive officers, as a group (13 persons)


(1)		The underwriters have an option to purchase up to an additional shares from the selling stockholder in this offering. If the underwriters exercise this option, shares would be sold to the underwriters by Coffeyville Acquisition LLC and Coffeyville Acquisition LLC would distribute the proceeds to its members.

(2)		The Goldman Sachs Group, Inc., and certain affiliates, including Goldman, Sachs & Co., may be deemed to directly or indirectly own in the aggregate shares of common stock which are owned directly or indirectly by investment partnerships, which we refer to as the Goldman Sachs Funds, of which affiliates of The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. are the general partner, managing limited partner or the managing partner. Goldman, Sachs & Co. is the investment manager for certain of the Goldman Sachs Funds. Goldman, Sachs & Co. is a direct and indirect, wholly owned subsidiary of The Goldman Sachs Group, Inc. The Goldman Sachs Group, Inc., Goldman, Sachs & Co. and the Goldman Sachs Funds share voting power and investment power with certain of their respective affiliates. Shares beneficially owned by the Goldman Sachs Funds consist of: (1) shares of common stock owned by GS Capital Partners V Fund, L.P., (2) shares of common stock owned by GS Capital Partners V

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		Offshore Fund, L.P., (3) shares of common stock owned by GS Capital Partners V Institutional, L.P., and (4) shares of common stock owned by GS Capital Partners V GmbH & Co. KG. Ken Pontarelli is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. each disclaims beneficial ownership of the shares of common stock owned directly or indirectly by the Goldman Sachs Funds, except to the extent of their pecuniary interest therein, if any. If the underwriters exercise their option to purchase additional shares in full, (1) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Fund, L.P., (2) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Offshore Fund, L.P., (3) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Institutional, L.P. and (4) shares of common stock will be sold in respect of member units owned by GS Capital Partners V GmbH & Co. KG.


(3)		With respect to the total number of shares of common stock beneficially owned prior to this offering, the share amount includes (1) shares of common stock owned by Kelso Investment Associates VII, L.P., a Delaware limited partnership, or KIA VII, and (2) shares of common stock owned by KEP VI, LLC, a Delaware limited liability company, or KEP VI. KIA VII and KEP VI, due to their common control, could be deemed to beneficially own each of the other’s shares but each disclaims such beneficial ownership. Shares and percentages indicated represent the upper limit of the expected ownership of our equity securities by these persons and entities. Messrs. Nickell, Wall, Matelich, Goldberg, Wahrhaftig, Bynum, Berney, Loverro and Connors may be deemed to share beneficial ownership of shares of common stock owned of record, by virtue of their status as managing members of KEP VI and of Kelso GP VII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of Kelso GP VII, L.P., a Delaware limited partnership, the principal business of which is serving as the general partner of KIA VII. Each of Messrs. Nickell, Wall, Matelich, Goldberg, Wahrhaftig, Bynum, Berney, Loverro and Connors share investment and voting power with respect to the ownership interests owned by KIA VII and KEP VI but disclaim beneficial ownership of such interests. If the underwriters exercise their option to purchase additional shares in full, (i) shares of common stock will be sold in respect of member units owned by KIA VII and (ii) shares of common stock will be sold in respect of member units owned by KEP VI.


(4)		The board of directors of Coffeyville Acquisition LLC, which consists of the same members as our board of directors, has the power to dispose of the securities of Coffeyville Acquisition LLC.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

Transactions with the Goldman Sachs Funds and the Kelso Funds

GS Capital Partners V Fund, L.P. and related entities, or the Goldman Sachs Funds, and Kelso Investment Associates VII, L.P. and related entity, the Kelso Funds, are the majority owners of Coffeyville Acquisition LLC.

Investments in Coffeyville Acquisition LLC

On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC, Coffeyville Acquisition LLC acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. The Goldman Sachs Funds made capital contributions of $112,817,500 to Coffeyville Acquisition LLC and the Kelso Funds made capital contributions of $110,817,500 to Coffeyville Acquisition LLC in connection with the acquisition. The total proceeds received by Pegasus Partners II, L.P. and the other unit holders of Coffeyville Group Holdings, LLC, including then current management, in connection with the Subsequent Acquisition was $526,185,017, after repayment of Immediate Predecessor’s credit facility.

Coffeyville Acquisition LLC paid companies related to the Goldman Sachs Funds and the Kelso Funds each equal amounts totaling $6.0 million for the transaction fees related to the Subsequent Acquisition, as well as an additional $0.7 million paid to the Goldman Sachs Funds for reimbursed expenses related to the Subsequent Acquisition.

On July 25, 2005, the following executive officers and directors made the following capital contributions to Coffeyville Acquisition LLC: John J. Lipinski, $650,000; Stanley A. Riemann, $400,000; James T. Rens, $250,000; Kevan A. Vick, $250,000; Robert W. Haugen, $100,000; Wyatt E. Jernigan, $100,000; Chris Swanberg, $25,000. On September 12, 2005, Edmund Gross made a $30,000 capital contribution to Coffeyville Acquisition LLC. On September 20, 2005, Wesley Clark made a $250,000 capital contribution to Coffeyville Acquisition LLC. All but two of the executive officers received common units, operating units and value units of Coffeyville Acquisition LLC and the director received common units of Coffeyville Acquisition LLC.

On September 14, 2005, the Goldman Sachs Funds and the Kelso Funds each invested an additional $5.0 million in Coffeyville Acquisition LLC. On May 23, 2006, the Goldman Sachs Funds and the Kelso Funds each invested an additional $10.0 million in Coffeyville Acquisition LLC. In each case they received additional common units of Coffeyville Acquisition LLC.

J. Aron & Company

Coffeyville Acquisition LLC entered into commodity derivative contracts in the form of three swap agreements for the period from July 1, 2005 through June 30, 2010 with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. The swap agreements were originally entered into by Coffeyville Acquisition LLC on June 16, 2005 in conjunction with the acquisition of Immediate Predecessor and were required under the terms of our long-term debt agreements. The swap agreements were executed at the prevailing market rate at the time of execution and management believes the swap agreements provide an economic hedge on future transactions. These agreements were assigned to Coffeyville Resources, LLC on June 24, 2005. The economically hedged volumes total approximately 70% of their forecasted production from July 2005 through June 2009 and approximately 17% from July 2009 through June 2010. These positions resulted in unrealized losses of approximately $235.9 million at December 31, 2005 and unrealized gains of approximately $80.3 million for the nine months ended September 30, 2006. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources — Cash Flow Swap.”

Effective December 30, 2005, Coffeyville Acquisition LLC entered into a crude oil supply agreement with J. Aron. Other than locally produced crude we gather ourselves, we purchase crude oil from third parties using a credit intermediation agreement. The terms of this agreement provide

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that we will obtain all of the crude oil for our refinery, other than the crude we obtain through our own gathering system, through J. Aron. Once we identify cargos of crude oil and pricing terms that meet our requirements, we notify J. Aron and J. Aron then provides credit, transportation and other logistical services to us for a fee. This agreement significantly reduces the investment that we are required to maintain in petroleum inventories relative to our competitors and reduces the time we are exposed to market fluctuations before the inventory is priced to a customer. The current credit intermediation agreement with J. Aron expires on December 31, 2007. At that time we may renegotiate the agreement with J. Aron, seek a similar arrangement with another party, or choose to obtain our crude supply directly without the use of an intermediary.

Coffeyville Acquisition LLC also entered into certain crude oil, heating oil, and gasoline option agreements with J. Aron as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 233 days ended December 31, 2005.

Consulting and Advisory Agreements

Under the terms of separate consulting and advisory agreements, dated June 24, 2005, between Coffeyville Acquisition LLC and each of Goldman, Sachs & Co. and Kelso & Company, L.P., Coffeyville Acquisition LLC was required to pay an advisory fee of $1,000,000 per year, payable quarterly in advance, to each of Goldman Sachs and Kelso for consulting and advisory services provided by Goldman Sachs and Kelso. The advisory agreements provide that Coffeyville Acquisition LLC will indemnify Goldman Sachs and Kelso and their respective affiliates, designees, officers, directors, partners, employees, agents and control persons (as such term is used in the Securities Act and the rules and regulations thereunder), to the extent lawful, against claims, losses and expenses as incurred in connection with the services rendered to Coffeyville Acquisition LLC under the consulting and advisory agreements or arising out of any such person being a controlling person of Coffeyville Acquisition LLC. The agreements also provide that Coffeyville Acquisition LLC will reimburse expenses incurred by Goldman Sachs and Kelso in connection with their investment in Coffeyville Acquisition and with respect to services provided to Coffeyville Acquisition LLC pursuant to the consulting and advisory agreements. The consulting and advisory agreements also provide for the payment of certain fees, as may be determined by mutual agreement, payable by Coffeyville Acquisition LLC to Goldman Sachs and Kelso in connection with transaction services and for the reimbursement of expenses incurred in connection with such services. Payments relating to the consulting and advisory agreements include $1,310,416 which was expensed in selling, general, and administrative expenses for the 233 days ended December 31, 2005. In addition, $1,046,575 was included in other current liabilities and approximately $78,671 was included in accounts payable at December 31, 2005.

On , 2007, Coffeyville Acquisition LLC entered into termination agreements with Goldman Sachs and Kelso under which Coffeyville Acquisition LLC agreed to pay each of Goldman Sachs and Kelso a one-time fee of $5 million payable upon the consummation of this offering. Pursuant to the terms of the termination letter, in return for the $5 million fee, the annual advisory fee and any obligations with respect to certain other fees will terminate. In addition, pursuant to the termination letter, the obligations of Goldman Sachs and Kelso with respect to consulting and other services will terminate after Goldman Sachs or Kelso no longer have beneficial ownership of our common stock in excess of % of our outstanding common stock. Coffeyville Acquisition LLC’s obligations with respect to the indemnification of Goldman Sachs and Kelso and reimbursement of expenses will survive the termination of the obligations of the parties described above.

Credit Facilities

Goldman Sachs Credit Partners L.P., an affiliate of Goldman, Sachs & Co., or Goldman Sachs, is one of the lenders under the First Lien Credit Facility and the Second Lien Credit Facility which were entered into in connection with the financing of the Subsequent Acquisition. Goldman Sachs

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Credit Partners is the sole lead arranger, sole bookrunner and syndication agent under the First Lien Credit Facility and the joint lead arranger, joint bookrunner and syndication agent under the Second Lien Credit Facility. Successor paid this Goldman Sachs affiliate a $22.1 million fee included in deferred financing costs. For the 233 days ended December 31, 2005, Successor made interest payments to this Goldman Sachs affiliate of $1.8 million recorded in interest expense and paid letter of credit fees of approximately $155,000 which were recorded in selling, general, and administrative expenses. See “Description of Our Indebtedness and the Cash Flow Swap.”

Transactions with John J. Lipinski

On June 30, 2005, Coffeyville Acquisition LLC loaned $500,000 to John J. Lipinski, CEO of Successor. This loan accrued interest at the rate of 7% per year. The loan was made in conjunction with Mr. Lipinski’s purchase of 50,000 common units of Coffeyville Acquisition LLC. The balance as of June 30, 2006 was $350,000. The loan, together with accrued and unpaid interest, was forgiven in full in September 2006.

Coffeyville Acquisition LLC Operating Agreement

The Goldman Sachs Funds, the Kelso Funds, and John J. Lipinski, Stanley A. Riemann, James T. Rens, Edmund Gross, Robert W. Haugen, Wyatt E. Jernigan, Kevan A. Vick, Christopher Swanberg, Wesley Clark, Magnetite Asset Investors III L.L.C. and other members of management beneficially own capital stock in our company through Coffeyville Acquisition LLC. The LLC Agreement includes (1) restrictions on the ability of members to transfer their interests in Coffeyville Acquisition LLC, (2) a right of first offer in the event of proposed sales by the Goldman Sachs Funds and/or the Kelso Funds, and (3) tag along and drag along rights in connection with transfers by the Goldman Sachs Funds and/or the Kelso Funds.

The LLC Agreement provides that the business and affairs of Coffeyville Acquisition LLC is managed by a board of directors. The number of directors of Coffeyville Acquisition LLC is established by mutual consent of the Goldman Sachs Funds and the Kelso Funds. The LLC Agreement provides that the board of Coffeyville Acquisition LLC shall consist of at least five members, including Mr. Lipinski, two directors designated by the Goldman Sachs Funds and two directors designated by the Kelso Funds. The board currently has six members. Of the current directors, Messrs. Lebovitz and Pontarelli were appointed by the Goldman Sachs Funds and Messrs. Matelich and Osborne were appointed by the Kelso Funds.

The Goldman Sachs Funds and the Kelso Funds each have the right to designate two directors to the board of Coffeyville Acquisition LLC so long as that party holds common units that represent both at least 20% of the common units then held by all members and at least 50% of the common units held by such party on June 24, 2005. The Goldman Sachs Funds and the Kelso Funds each have the right to designate one director for so long as such party continues to hold common units that represent at least 5% of the common units then held by all members. In addition, for so long as John Lipinski is President and Chief Executive Officer, he will be appointed to the board of Coffeyville Acquisition LLC. To the extent that the Goldman Funds or the Kelso Funds have no director designation rights, that party will have the right to designate a board observer to attend board meetings.

Most significant decisions involving Coffeyville Acquisition LLC and (prior to an initial public offering) its subsidiaries require the approval of the Goldman Sachs Funds or at least one Goldman Sachs Funds appointed director (for so long as the Goldman Sachs Funds have the right to appoint two directors) and the Kelso Funds or at least one Kelso Funds appointed director (for so long as the Kelso Funds have the right to appoint two directors).

The LLC Agreement provides that in the event that the Goldman Sachs Funds and the Kelso Funds elect to complete an initial public offering through a subsidiary of Coffeyville Acquisition LLC, (1) Coffeyville Acquisition LLC will not vote any shares in favor of any action without the prior written

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consent of the Goldman Sachs Funds or at least one Goldman Sachs Funds appointed director (for so long as the Goldman Sachs Funds have the right to appoint two directors) and the Kelso Funds or at least one Kelso Funds appointed director (for so long as the Kelso Funds have the right to appoint two directors), (2) the transfer restrictions, right of first offer, tag along rights and drag along rights contained in the LLC Agreement will cease to apply, and (3) Coffeyville Acquisition LLC will enter into a registration rights agreement with the initial public offering issuer.

For a summary of the material terms of the LLC Agreement as they relate to the limited liability interests granted to our executive officers, see “Management — Employment Agreements and Change-in-Control Arrangements — Executives’ Interests in Coffeyville Acquisition LLC.”

Registration Rights Agreement

We intend to enter into a registration rights agreement immediately prior to the completion of this offering with Coffeyville Acquisition LLC pursuant to which we may be required to register the sale of our shares held by Coffeyville Acquisition LLC and permitted transferees. Under the registration rights agreement, the Goldman Sachs Funds and the Kelso Funds will have the right to request that we register the sale of shares held by Coffeyville Acquisition LLC on their behalf and may require us to make available shelf registration statements permitting sales of shares into the market from time to time over an extended period. In addition, the members of Coffeyville Acquisition LLC (including members of management) will have the ability to exercise certain piggyback registration rights if we elect to register any of our equity securities. The registration rights agreement is also expected to include provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. Immediately after this offering, all of our shares held by Coffeyville Acquisition LLC will be entitled to these registration rights.

Transactions with Pegasus Partners II, L.P.

Pegasus Partners II, L.P., or Pegasus, was a majority owner of Coffeyville Group Holdings, LLC (Immediate Predecessor) during the period March 3, 2004 through June 24, 2005. On March 3, 2004, Coffeyville Group Holdings, LLC, through its wholly owned subsidiary, Coffeyville Resources, LLC, acquired the assets of the former Farmland petroleum division and one facility within Farmland’s nitrogen fertilizer manufacturing and marketing division through a bankruptcy court auction process for approximately $107 million and the assumption of approximately $23 million of liabilities.

On March 3, 2004, Coffeyville Group Holdings, LLC entered into a management services agreement with Pegasus Capital Advisors, L.P., pursuant to which Pegasus Capital Advisors, L.P. provided Coffeyville Group Holdings, LLC with managerial and advisory services. In consideration for these services, Coffeyville Group Holdings, LLC agreed to pay Pegasus Capital Advisors, L.P. an annual fee of up to $1.0 million plus reimbursement for any out-of-pocket expenses. During the year ended December 31, 2004, Immediate Predecessor paid an aggregate of approximately $545,000 to Pegasus Capital Advisors, L.P. in fees under this agreement. $1,000,000 was expensed to selling, general, and administrative expenses for the 174 days ended June 23, 2005. In addition, Immediate Predecessor paid approximately $455,000 in legal fees on behalf of Pegasus Capital Advisors, L.P. in lieu of the remaining amount owed under the management fee. This management services agreement terminated at the time of the Subsequent Acquisition in June 2005.

Coffeyville Group Holdings, LLC paid Pegasus Capital Advisors, L.P. a $4.0 million transaction fee upon closing of the acquisition on March 3, 2004. The transaction fee related to a $2.5 million merger and acquisition fee and a $1.5 million in deferred financing costs. In addition, in conjunction with the refinancing of our senior secured credit facility on May 10, 2004, Coffeyville Group Holdings, LLC paid an additional $1.25 million fee to Pegasus Capital Advisors, L.P. as a deferred financing cost.

On March 3, 2004, Coffeyville Group Holdings, LLC entered into Executive Purchase and Vesting Agreements with the then executive officers listed below providing for the sale by Immediate

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Predecessor to them of the number of our common units to the right of each executive officer’s name at a purchase price of approximately $0.0056 per unit. Pursuant to the terms of these agreements, as amended, each executive officer’s common units were to vest at a rate of 16.66% every six months with the first 16.66% vesting on November 10, 2004. In connection with their purchase of the common units pursuant to the Executive Purchase and Vesting Agreements, each of the executive officers at that time issued promissory notes in the amounts indicated below. These notes were paid in full on May 10, 2004.


	Number of		Amount of
	Common		Promissory
Executive Officer	Units		Note

Philip L. Rinaldi		3,717,647	$	21,000
Abraham H. Kaplan		2,230,589	$	12,600
George W. Dorsey		2,230,589	$	12,600
Stanley A. Riemann		1,301,176	$	7,350
James T. Rens		371,764	$	2,100
Keith D. Osborn		650,588	$	3,675
Kevan A. Vick		650,588	$	3,675

On May 10, 2004, Mr. Rinaldi entered into another Executive Purchase and Vesting Agreement under the same terms as described above providing for the purchase of an additional 500,000 common units of Coffeyville Group Holdings, LLC for an aggregate purchase price of $2,850.

On May 10, 2004, Coffeyville Group Holdings, LLC refinanced its existing long-term debt with a $150 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under Coffeyville Group Holdings, LLC’s previous credit facility. The borrowings were also used to distribute a $99,987,509 dividend, which included a preference payment of $63,200,000 plus a yield of $1,802,956 to the preferred unit holders and a $63,000 payment to the common unit holders for undistributed capital per the LLC agreement. The remaining $34,921,553 was distributed to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.

On October 8, 2004, Coffeyville Group Holdings, LLC entered into a joint venture with The Leiber Group, Inc., a company whose majority stockholder was Pegasus Partners II, L.P., the principal stockholder of Immediate Predecessor. In connection with the joint venture, Coffeyville Group Holdings, LLC contributed approximately 68.7% of its membership interests in Coffeyville Resources, LLC to CL JV Holdings, LLC, a Delaware limited liability company, or CL JV Holdings, and The Leiber Group, Inc. contributed the Judith Leiber business to CL JV Holdings. At the time of the Subsequent Acquisition, in June 2005, the joint venture was effectively terminated.

On January 13, 2005, Immediate Predecessor’s board of directors authorized the following bonus payments to the following then executive officers, at that time, in recognition of the importance of retaining their services:


Executive Officer	Bonus Amount

Philip L. Rinaldi	$	1,000,000
Abraham H. Kaplan	$	600,000
George W. Dorsey	$	300,000
Stanley A. Riemann	$	700,000
James T. Rens	$	150,000
Keith D. Osborn	$	150,000
Kevan A. Vick	$	150,000
Edmund S. Gross	$	200,000

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During 2004 and 2005, Immediate Predecessor shared office space with Pegasus in New York, New York for which we paid Pegasus $10,000 per month.

On June 23, 2005, immediately prior to the Subsequent Acquisition, Coffeyville Group Holdings, LLC used available cash balances to distribute a $52,211,493 dividend to its preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.

Future Transactions

We believe that each of the transactions described above that is to remain in effect following the completion of this offering is on terms no less favorable to us than could have been obtained from unaffiliated third parties. Concurrently with this offering, our board of directors will adopt policies and procedures for the review, approval and ratification of related party transactions.

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DESCRIPTION OF OUR INDEBTEDNESS AND THE CASH FLOW SWAP

First Lien Credit Facility and Second Lien Credit Facility

In connection with the acquisition of all of the subsidiaries of Coffeyville Group Holdings, LLC on June 24, 2005 by the Goldman Sachs Funds and the Kelso Funds, Coffeyville Resources, LLC, as the borrower, and Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Pipeline, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, which we refer to collectively as Holdings, and certain of their subsidiaries as guarantors entered into a first lien credit agreement, dated as of June 24, 2005, as amended on July 8, 2005 and December 16, 2005, and as further amended and restated as of June 29, 2006 (which we refer to as the First Lien Credit Facility) with Goldman Sachs Credit Partners, L.P., as sole lead arranger, sole bookrunner and syndication agent, Credit Suisse, Cayman Islands Branch, as Funded LC issuing bank, Wachovia Bank, National Association, as administrative agent, collateral agent, co-documentation agent and revolving issuing bank and Sumitomo Mitsui Banking Corporation, as a co-documentation agent, and a second lien credit facility, dated as of June 24, 2005 and amended as of July 8, 2005, which we refer to as the Second Lien Credit Facility, with Goldman Sachs Credit Partners, L.P., as joint lead arranger, joint bookrunner and syndication agent and Credit Suisse, Cayman Islands Branch, as joint lead arranger and joint bookrunner, administrative agent and collateral agent.

The following summary of the material terms of the First Lien Credit Facility and the Second Lien Credit Facility is only a general description and is not complete and, as such, is subject to and is qualified in its entirety by reference to the provisions of the First Lien Credit Facility and the Second Lien Credit Facility.

The First Lien Credit Facility provides financing of up to $523.3 million, consisting of $223.3 million of tranche C term loans, $50.0 million of delayed draw term loans available through December 2006 and subject to accelerated payment terms, a $100.0 million revolving loan facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. The Second Lien Credit Facility includes a $275.0 million term loan.

The revolving loan facility of $100.0 million provides for direct cash borrowings for general corporate purposes on a short-term basis. Letters of credit issued under the revolving loan facility are subject to a $50.0 million sub-limit. The revolving loan commitment matures on June 24, 2011. We have an option to extend this maturity upon written notice to our lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is June 24, 2012.

The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into the credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, we have the ability to reduce the funded letter of credit at any time upon written notice to the lenders.

The First Lien Credit Facility was subsequently amended and restated on June 29, 2006 under substantially the same terms as the original agreement, as amended. The tranche B term loans were refinanced into tranche C term loans. The primary reason for the amendment and restatement was to reduce the applicable margin spreads for borrowings on the first lien term loans and the funded letter of credit facility and to make the capital expenditure covenant less restrictive.

Interest Rate and Fees.

The First Lien Credit Facility. The tranche C term loans and delayed draw term loans bear interest at either LIBOR plus 2.25%, or at the borrower’s election, prime rate plus 1.25% (with step-downs to LIBOR plus 2.00% and prime rate plus 1%, respectively, upon achievement of certain rating conditions). The revolving loan facility borrowings bear interest at either LIBOR plus 2.50% or, at the borrower’s election, prime rate plus 1.50% (with step-downs to LIBOR plus 2.25% and prime rate plus

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1.25%, respectively, and then to LIBOR plus 2.00% and prime rate plus 1%, respectively, upon certain amounts of prepayments of the term loans and substantial completion of certain capital expenditure projects). Letters of credit issued under the $50.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% owing to the issuing lender. Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owing to all funded letter of credit lenders and a fronting fee of 0.125% owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit. In addition to the fees stated above, the First Lien Credit Facility requires the borrower to pay 0.50% in commitment fees on the unused portion of the revolving loan facility and 1.00% in commitment fees on the unused portion of the delayed draw term loan commitment. The average weighted interest rate on borrowings under the First Lien Credit Facility on September 30, 2006 was 7.631%.

The Second Lien Credit Facility. The Second Lien Credit Facility borrowings bear interest at LIBOR plus 6.75%, or at the borrower’s option, prime rate plus 5.75%.

Prepayments. The First Lien Credit Facility and the Second Lien Credit Facility require the borrower to prepay outstanding loans, subject to certain exceptions, with:


	•	100% of the net asset sale proceeds received by Holdings or any of its subsidiaries from specified asset sales and net insurance/condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or to make other certain permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or to make other certain permitted investments within 18 months of receipt, each subject to certain limitations;

	•	100% of the cash proceeds from the incurrence of specified debt obligations by Holdings or any of its subsidiaries; and

	•	75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that this percentage will be reduced to 50% when the term loan repayment amount is at least $150.0 million.

Voluntary prepayments of loans under the First Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.

Voluntary prepayments of loans under the Second Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, so long as no amounts are outstanding under the First Lien Credit Facility or unless the lenders under the First Lien Credit Facility provide the requisite consent. Similarly, mandatory prepayments of loans under the Second Lien Credit Facility apply only after no amounts are outstanding under the First Lien Credit Facility. Any voluntary prepayments as well as prepayments out of the cash proceeds from the incurrence of specified debt obligations made to the Second Lien Credit Facility after July 8, 2006 but before July 8, 2007 are subject to a 2.0% prepayment premium and any voluntary prepayments made after July 8, 2007 but before July 8, 2008 are subject to a 1.0% prepayment premium.

Amortization.

The First Lien Credit Facility. The tranche C term loans are repayable in quarterly installments in a principal amount equal to the principal amount of the tranche C term loans

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outstanding on the quarterly installment date multiplied by 0.25% for each quarterly installment made prior to October 1, 2011 and 23.5% for each quarterly installment made during the period commencing on October 1, 2011 through maturity on June 24, 2012. The delayed draw term loan is subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on the last date of the first quarter following the delayed draw term loan termination date or the date on which the delayed draw term loans have been fully funded through the sixth anniversary of the closing date or June 24, 2011. Thereafter, the delayed draw term loans are amortized in equal quarterly installments until June 24, 2012.

The Second Lien Credit Facility. The Second Lien Credit Facility is not subject to scheduled principal amortization; however, the principal outstanding is due and payable upon final maturity on June 24, 2013.

Collateral and Guarantors. All obligations under the First Lien Credit Facility and the Second Lien Credit Facility are guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries. Indebtedness under the First Lien Credit Facility is secured by a first priority security interest in substantially all of Coffeyville Resources, LLC’s assets, including a pledge of all of the capital stock of its domestic subsidiaries and 65% of all the capital stock of each of its foreign subsidiaries on a first lien priority basis. The Second Lien Credit Facility is similarly secured but on a second lien priority basis.

Certain Covenants and Events of Default. Both the First Lien Credit Facility and the Second Lien Credit Facility contain customary covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and shareholders, change the business conducted by the credit parties, and enter into hedging agreements. The agreements provide that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from June 24, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap, the management agreements with the Goldman Sachs Funds and the Kelso Funds, or the May 2005 stock purchase agreement, without the prior written approval of the lenders.

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The First Lien Credit Facility requires the borrower to maintain a minimum interest coverage ratio and a maximum total leverage ratio and the Second Lien Credit Facility requires the borrower to maintain a maximum total leverage ratio. These financial covenants are set forth in the table below:

Second Lien

First Lien Credit Facility

Credit Facility

Minimum

Maximum

interest

leverage

Fiscal quarter ending

coverage ratio

ratio

September 30, 2006

2.25:1.00

5.00:1.00

5.25:1.00

December 31, 2006

2.25:1.00

5.00:1.00

5.25:1.00

March 31, 2007

2.25:1.00

4.75:1.00

5.00:1.00

June 30, 2007

2.50:1.00

4.50:1.00

4.75:1.00

September 30, 2007

2.75:1.00

4.25:1.00

4.75:1.00

December 31, 2007

3.00:1.00

3.50:1.00

4.00:1.00

March 31, 2008

3.25:1.00

3.50:1.00

4.00:1.00

June 30, 2008

3.25:1.00

3.75:1.00

September 30, 2008

3.25:1.00

3.00:1.00

3.50:1.00

December 31, 2008

3.25:1.00

2.75:1.00

3.25:1.00

March 31, 2009 and thereafter

3.50:1.00

2.50:1.00

3.00:1.00

In addition, the First Lien Credit Facility also requires the borrower to maintain a maximum capital expenditures limitation of $230.0 million in 2006, $70.0 million in 2007, $40.0 million in 2008 and thereafter. If the actual amount of capital expenditures made in any fiscal year (excluding those made in connection with the continuous catalytic reformer and fluidized catalytic crack unit projects) is less than the amount permitted to be made in such fiscal year, the amount of such difference may be carried forward and used to make capital expenditures in succeeding fiscal years. The continuous catalytic reformer and the fluidized catalytic crack unit projects are subject to their own specific capital expenditure limitation of $165.0 million. The limitations on our capital expenditures imposed by the First Lien Credit Facility allow us to meet our current capital expenditure needs. However if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned we would need to obtain consent from the lenders under our First Lien Credit Facility.

The First Lien Credit Facility and the Second Lien Credit Facility also contain customary events of default. The events of default include the failure to pay interest and premium when due, including fees and any other amounts owed under the credit agreements, a breach of certain covenants under the credit agreements, a breach of any representation or warranty contained in the credit agreements, any default under any of the documents entered into in connection with the credit agreements, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, events relating to employee benefit plans resulting in liability in excess of $10 million under the First Lien Credit Facility and $15 million under the Second Lien Credit Facility, the guarantees, collateral documents or the credit agreements failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the credit agreements to have a lien on any material portion of the collateral,

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and any party under the credit agreements (other than the agent or lenders under the credit agreements) contesting the validity or enforceability of the credit agreements.

The First Lien Credit Facility and the Second Lien Credit Facility also contain an event of default upon the occurrence of a change of control. Under the First Lien Credit Agreement, a “change of control” means (1) the Goldman Sachs Funds and the Kelso Funds cease to beneficially own on a fully diluted basis at least 35% of the economic and voting interests in the capital stock of Parent (Coffeyville Acquisition LLC or CVR Energy or any entity that owns all of the capital stock of Holdings), (2) any person or group other than the Goldman Sachs Funds and/or the Kelso Funds (a) acquires beneficial ownership of 35% or more on a fully diluted basis of the voting and/or economic interest in the capital stock of Holdings and the percentage voting and/or economic interest acquired exceeds the percentage owned by the Goldman Sachs Funds and the Kelso Funds or (b) shall have obtained the power to elect a majority of the board of Parent, (3) Parent shall cease to own and control, directly or indirectly, 100% on a fully diluted basis of the capital stock of the borrower, (4) Holdings ceases to beneficially own and control all of the capital stock of the borrower or (5) the majority of the seats on the board of Parent cease to be occupied by continuing directors approved by the then-existing directors.

Other. The First Lien Credit Facility and the Second Lien Credit Facility are subject to an intercreditor agreement between the lenders of both credit agreements and the provider of the Cash Flow Swap, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.

Cash Flow Swap

In connection with the Subsequent Acquisition and as required under our existing credit facilities, Coffeyville Acquisition LLC entered into a crack spread hedging transaction with J. Aron. The agreements underlying the transaction were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. See “Certain Relationships and Related Party Transactions.” The derivative transaction was entered into for the purpose of managing our exposure to the price fluctuations in crude oil, heating oil and gasoline markets.

The fixed prices for each product in each calendar quarter are specified in the applicable swap confirmation. The floating price for


	•	crude oil for each quarter equals the average of the closing settlement price(s) on NYMEX for the Nearby Light Crude Futures Contract that is “first nearby” as of any determination date during that calendar quarter quoted in U.S. dollars per barrel;


	•	unleaded gasoline for each quarter equals the average of the closing settlement prices on NYMEX for the Unleaded Gasoline Futures Contract that is “first nearby” for any determination period to and including the determination period ending December 31, 2006 and the average of the closing settlement prices on NYMEX for Reformulated Gasoline Blendstock for Oxygen Blending Futures Contract that is “first nearby” for each determination period thereafter quoted in U.S. dollars per gallon; and


	•	heating oil for each quarter equals the average of the closing settlement prices on NYMEX for the Heating Oil Futures Contract that is “first nearby” as of any determination date during such calendar quarter quoted in U.S. dollars per gallon.

The hedge transaction is governed by the standard form 1992 International Swap and Derivatives Association, Inc., or ISDA Master Agreement, which includes a schedule to the ISDA Master Agreement setting forth certain specific transaction terms.

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Coffeyville Resources, LLC’s obligations under the hedge transaction are:


	•	guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries;

	•	secured by a $150 million funded letter of credit issued under the First Lien Credit Facility in favor of J. Aron; and

	•	to the extent J. Aron’s exposure under the derivative transaction exceeds $150 million, secured by the same collateral that secures our First Lien Credit Facility.

In addition, J. Aron is an additional named insured and loss payee under certain insurance policies of Coffeyville Resources, LLC.

The obligations of J. Aron under the derivative transaction are guaranteed by The Goldman Sachs Group, Inc.

The derivative transactions terminate on June 30, 2010. Prior to the termination date, neither party has a right to terminate the derivative transaction unless one of the events of default or termination events under the ISDA Master Agreement has occurred. In addition to standard events of default and termination events described in the ISDA Master Agreement, the schedule to the ISDA Master Agreement provides for the termination of the derivative transaction if:


	•	Coffeyville Resources, LLC’s obligations under the derivative transaction cease to be secured as described above equally and ratably with the security interest granted under the First Lien Credit Facility;

	•	Coffeyville Resources, LLC’s obligations under the derivative transaction cease to be guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; or

	•	Coffeyville Resources, LLC fails to maintain a $150 million funded letter of credit in favor of J. Aron.

If a termination event occurs, the derivative transaction will be cash-settled on the termination date designated by a party entitled to such designation under the ISDA Master Agreement (to the extent of the amounts owed to either party on the termination date, without netting of payments) and no further payments or deliveries under the derivative transaction will be required.

Intercreditor matters among J. Aron and the lenders under the First Lien Credit Facility and the Second Lien Credit Facility are governed by the Intercreditor Agreement. J. Aron’s security interest in the collateral is pari passu with the security interest in the collateral granted under the First Lien Credit Facility and the Second Lien Credit Facility. In addition, pursuant to the Intercreditor Agreement, J. Aron is entitled to vote together as a class with the lenders under the First Lien Credit Facility with respect to (1) any remedies proposed to be taken by the holders of the secured obligations with respect to the collateral, (2) any matters related to a breach, waiver or modification of the covenants in the First Lien Credit Facility that restrict the granting of liens, the incurrence of indebtedness, and the ability of Coffeyville Resources, LLC to enter into derivative transactions for more than 75% of Coffeyville Resources, LLC’s actual production (based on the three month period preceding the trade date of the relevant derivative) of refined products or for a term longer than six years, (3) the maintenance of insurance, and (4) any matters relating to the collateral. For any of the foregoing matters, J. Aron is entitled to vote with the lenders under the First Lien Credit Facility as a single class to the extent of the greater of (x) its exposure under the derivative transaction, less the amount secured by the letter of credit and (y) $75 million.

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DESCRIPTION OF CAPITAL STOCK

Immediately following the completion of this offering, our authorized capital stock will consist of shares of common stock, par value $0.01 per share, and shares of preferred stock, par value $0.01 per share, the rights and preferences of which may be established from time to time by our board of directors. Upon the completion of this offering, there will be outstanding shares of common stock and no outstanding shares of preferred stock. The following description of our capital stock does not purport to be complete and is subject to and qualified by our certificate of incorporation and bylaws, which are included as exhibits to the registration statement of which this prospectus forms a part, and by the provisions of applicable Delaware law.

Common Stock

Holders of our common stock are entitled to one vote for each share on all matters voted upon by our stockholders, including the election of directors, and do not have cumulative voting rights. Subject to the rights of holders of any then outstanding shares of our preferred stock, our common stockholders are entitled to any dividends that may be declared by our board of directors. Holders of our common stock are entitled to share ratably in our net assets upon our dissolution or liquidation after payment or provision for all liabilities and any preferential liquidation rights of our preferred stock then outstanding. Holders of our common stock have no preemptive rights to purchase shares of our stock. The shares of our common stock are not subject to any redemption provisions and are not convertible into any other shares of our capital stock. All outstanding shares of our common stock are, and the shares of common stock to be issued in this offering will be, upon payment therefor, fully paid and nonassessable. The rights, preferences and privileges of holders of our common stock will be subject to those of the holders of any shares of our preferred stock we may issue in the future.

Preferred Stock

Our board of directors may, from time to time, authorize the issuance of one or more classes or series of preferred stock without stockholder approval. Subject to the provisions of our certificate of incorporation and limitations prescribed by law, our board of directors is authorized to adopt resolutions to issue shares, establish the number of shares, change the number of shares constituting any series, and provide or change the voting powers, designations, preferences and relative rights, qualifications, limitations or restrictions on shares of our preferred stock, including dividend rights, terms of redemption, conversion rights and liquidation preferences, in each case without any action or vote by our stockholders. We have no current intention to issue any shares of preferred stock.

One of the effects of undesignated preferred stock may be to enable our board of directors to discourage an attempt to obtain control of our company by means of a tender offer, proxy contest, merger or otherwise. The issuance of preferred stock may adversely affect the rights of our common stockholders by, among other things:


	•	restricting dividends on the common stock;

	•	diluting the voting power of the common stock;

	•	impairing the liquidation rights of the common stock; or

	•	delaying or preventing a change in control without further action by the stockholders.

Limitation of Liability of Officers and Directors

Our certificate of incorporation limits the liability of directors to the fullest extent permitted by Delaware law. The effect of these provisions is to eliminate the rights of our company and our stockholders, through stockholders’ derivative suits on behalf of our company, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly negligent behavior. However, our directors will be personally liable to us and our stockholders

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for monetary damages if they acted in bad faith, knowingly or intentionally violated the law, authorized illegal dividends or redemptions or derived an improper benefit from their actions as directors. In addition, our restated certificate of incorporation provides that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. We may enter into indemnification agreements with our current directors and executive officers prior to the completion of this offering. We also maintain directors and officers insurance.

Delaware Anti-Takeover Law

We are subject to Section 203 of the Delaware General Corporation Law which regulates corporate acquisitions. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation may not engage in business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder. The law defines the term “business combination” to include mergers, asset sales and other transactions in which the interested stockholder receives or could receive a financial benefit on other than a pro rata basis with other stockholders. This provision has an anti-takeover effect with respect to transactions not approved in advance by our board of directors, including discouraging takeover attempts that might result in a premium over the market price for the shares of our common stock. With the approval of our stockholders, we could amend our certificate of incorporation in the future to avoid the restrictions imposed by this anti-takeover law.

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is .

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SHARES ELIGIBLE FOR FUTURE SALE

Upon the completion of this offering, we will have outstanding shares of common stock. The shares sold in this offering plus any additional shares sold by the selling stockholder upon exercise of the underwriters’ option and any shares sold in any directed share program established by us prior to this offering will be freely tradable without restriction under the Securities Act, unless purchased by our “affiliates” as that term is defined in Rule 144 under the Securities Act. In general, affiliates include executive officers, directors and our largest stockholders. Shares of common stock purchased by affiliates will remain subject to the resale limitations of Rule 144.

The remaining shares outstanding prior to this offering are restricted securities within the meaning of Rule 144. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rules 144, 144(k) or Rule 701 promulgated under the Securities Act, which are summarized below.

The executive officers, directors and selling stockholder will enter into lock-up agreements in connection with this offering, generally providing that they will not offer, sell, contract to sell, or grant any option to purchase or otherwise dispose of our common stock or any securities exercisable for or convertible into our common stock owned by it for a period of 180 days after the date of this prospectus without the prior written consent of .

Despite possible earlier eligibility for sale under the provisions of Rules 144, 144(k) and 701 under the Securities Act, any shares subject to a lock-up agreement will not be salable until the lock-up agreement expires or is waived by . Taking into account the lock-up agreement, and assuming does not release Coffeyville Acquisition LLC from its lock-up agreement, shares held by our affiliates will be eligible for future sale in accordance with the requirements of Rule 144.

In general, under Rule 144 as currently in effect, after the expiration of lock-up agreements, a person who has beneficially owned restricted securities for at least one year would be entitled to sell within any three month period a number of shares that does not exceed the greater of the following:


	•	one percent of the number of shares of common stock then outstanding, which will equal approximately shares immediately after this offering; or

	•	the average weekly trading volume of the common stock during the four calendar weeks preceding the sale.

Sales under Rule 144 are also subject to requirements with respect to manner-of-sale requirements, notice requirements and the availability of current public information about us. Under Rule 144(k), a person who is not deemed to have been our affiliate at any time during the three months preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years, is entitled to sell his or her shares without complying with the manner-of-sale, public information, volume limitation, or notice provisions of Rule 144.

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UNITED STATES TAX CONSEQUENCES TO NON-UNITED STATES HOLDERS

The following is a summary of the material United States federal income and estate tax consequences of the acquisition, ownership and disposition of our common stock by a non-U.S. holder. As used in this summary, the term “non-U.S. holder” means a beneficial owner of our common stock that is not, for United States federal income tax purposes:


	•	an individual who is a citizen or resident of the United States or a former citizen or resident of the United States subject to taxation as an expatriate;

	•	a corporation created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

	•	a partnership;

	•	an estate whose income is includible in gross income for U.S. federal income tax purposes regardless of its source; or

	•	a trust, if (1) a United States court is able to exercise primary supervision over the trust’s administration and one or more “United States persons” (within the meaning of the U.S. Internal Revenue Code of 1986, as amended, or the Code) has the authority to control all of the trust’s substantial decisions, or (2) the trust has a valid election in effect under applicable U.S. Treasury regulations to be treated as a “United States person.”

An individual may be treated as a resident of the United States in any calendar year for United States federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States on at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of this calculation, an individual would count all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year. Residents are taxed for U.S. federal income purposes as if they were U.S. citizens.

If an entity or arrangement treated as a partnership or other type of pass-through entity for U.S. federal income tax purposes owns our common stock, the tax treatment of a partner or beneficial owner of such entity may depend upon the status of the partner or beneficial owner and the activities of the partnership or entity and by certain determinations made at the partner or beneficial owner level. Partners and beneficial owners in such entities that own our common stock should consult their own tax advisors as to the particular U.S. federal income and estate tax consequences applicable to them.

This summary does not discuss all of the aspects of U.S. federal income and estate taxation that may be relevant to a non-U.S. holder in light of the non-U.S. holder’s particular investment or other circumstances. In particular, this summary only addresses a non-U.S. holder that holds our common stock as a capital asset (generally, investment property) and does not address:


	•	special U.S. federal income tax rules that may apply to particular non-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, and dealers and traders in securities or currencies;

	•	non-U.S. holders holding our common stock as part of a conversion, constructive sale, wash sale or other integrated transaction or a hedge, straddle or synthetic security;

	•	any U.S. state and local or non-U.S. or other tax consequences; and

	•	the U.S. federal income or estate tax consequences for the beneficial owners of a non-U.S. holder.

This summary is based on provisions of the Code, applicable United States Treasury regulations and administrative and judicial interpretations, all as in effect or in existence on the date of this prospectus. Subsequent developments in United States federal income or estate tax law, including

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changes in law or differing interpretations, which may be applied retroactively, could have a material effect on the U.S. federal income and estate tax consequences of purchasing, owning and disposing of our common stock as set forth in this summary. Each non-U.S. holder should consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of our common stock.

Dividends

We do not anticipate making cash distributions on our common stock in the foreseeable future. See “Dividend Policy.” In the event, however, that we make cash distributions on our common stock, such distributions will constitute dividends for United States federal income tax purposes to the extent paid out of current or accumulated earnings and profits of the Company. To the extent such distributions exceed the Company’s earnings and profits, they will be treated first as a return of the shareholder’s basis in their common stock to the extent thereof, and then as gain from the sale of a capital asset. If we make a distribution that is treated as a dividend and is not effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States, we will have to withhold a U.S. federal withholding tax at a rate of 30%, or a lower rate under an applicable income tax treaty, from the gross amount of the dividends paid to such non-U.S. holder. Non-U.S. holders should consult their own tax advisors regarding their entitlement to benefits under a relevant income tax treaty.

In order to claim the benefit of an applicable income tax treaty, a non-U.S. holder will be required to provide a properly executed U.S. Internal Revenue Service Form W-8BEN (or other applicable form) in accordance with the applicable certification and disclosure requirements. Special rules apply to partnerships and other pass-through entities and these certification and disclosure requirements also may apply to beneficial owners of partnerships and other pass-through entities that hold our common stock. A non-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the U.S. Internal Revenue Service. Non-U.S. holders should consult their own tax advisors regarding their entitlement to benefits under a relevant income tax treaty and the manner of claiming the benefits.

Dividends that are effectively connected with a non-U.S. holder’s conduct of a trade or business in the United States and, if required by an applicable income tax treaty, are attributable to a permanent establishment maintained by the non-U.S. holder in the United States, will be taxed on a net income basis at the regular graduated rates and in the manner applicable to United States persons. In that case, we will not have to withhold U.S. federal withholding tax if the non-U.S. holder provides a properly executed U.S. Internal Revenue Service Form W-8ECI (or other applicable form) in accordance with the applicable certification and disclosure requirements. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with the conduct of a trade or business in the United States.

Gain on disposition of our common stock

A non-U.S. holder generally will not be taxed on any gain recognized on a disposition of our common stock unless:


	•	the gain is effectively connected with the non-U.S. holder’s conduct of a trade or business in the United States and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by the non-U.S. holder in the United States; in these cases, the gain will be taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons (unless an applicable income tax treaty provides otherwise) and, if the non-U.S. holder is a foreign corporation, the “branch profits tax” described above may also apply;

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	•	the non-U.S. holder is an individual who holds our common stock as a capital asset, is present in the United States for more than 182 days in the taxable year of the disposition and meets other requirements (in which case, except as otherwise provided by an applicable income tax treaty, the gain, which may be offset by U.S. source capital losses, generally will be subject to a flat 30% U.S. federal income tax, even though the non-U.S. holder is not considered a resident alien under the Code); or

	•	we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that the non-U.S. holder held our common stock.

Generally, a corporation is a “U.S. real property holding corporation” if the fair market value of its “U.S. real property interests” equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in a trade or business. We believe that we are not currently, and we do not anticipate becoming in the future, a U.S. real property holding corporation. However, because this determination is made from time to time and is dependent upon a number of factors, some of which are beyond our control, including the value of our assets, there can be no assurance that we will not become a U.S. real property holding corporation.

However, even if we are or have been a U.S. real property holding corporation, a non-U.S. holder which did not beneficially own, actually or constructively, more than 5% of the total fair market value of our common stock at any time during the shorter of the five-year period ending on the date of disposition or the period that our common stock was held by the non-U.S. holder (a “non-5% holder”) and which is not otherwise taxed under any other circumstances described above, generally will not be taxed on any gain realized on the disposition of our common stock if, at any time during the calendar year of the disposition, our common stock was regularly traded on an established securities market within the meaning of the applicable United States Treasury regulations.

We have applied to have our common stock listed on the . Although not free from doubt, our common stock should be considered to be regularly traded on an established securities market for any calendar quarter during which it is regularly quoted by brokers or dealers that hold themselves out to buy or sell our common stock at the quoted price. If our common stock were not considered to be regularly traded on an established securities market at any time during the applicable calendar year, then a non-5% holder would be taxed for U.S. federal income tax purposes on any gain realized on the disposition of our common stock on a net income basis as if the gain were effectively connected with the conduct of a U.S. trade or business by the non-5% holder during the taxable year and, in such case, the person acquiring our common stock from a non-5% holder generally would have to withhold 10% of the amount of the proceeds of the disposition. Such withholding may be reduced or eliminated pursuant to a withholding certificate issued by the U.S. Internal Revenue Service in accordance with applicable U.S. Treasury regulations. We urge all non-U.S. holders to consult their own tax advisors regarding the application of these rules to them.

Federal estate tax

Our common stock that is owned or treated as owned by an individual who is not a U.S. citizen or resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise and, therefore, may be subject to U.S. federal estate tax.

Information reporting and backup withholding tax

Dividends paid to a non-U.S. holder may be subject to U.S. information reporting and backup withholding. A non-U.S. holder will be exempt from backup withholding if the non-U.S. holder provides a properly executed U.S. Internal Revenue Service Form W-8BEN or otherwise meets documentary

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evidence requirements for establishing its status as a non-U.S. holder or otherwise establishes an exemption.

The gross proceeds from the disposition of our common stock may be subject to U.S. information reporting and backup withholding. If a non-U.S. holder sells our common stock outside the United States through a non-U.S. office of a non-U.S. broker and the sales proceeds are paid to the non-U.S. holder outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, United States information reporting, but not U.S. backup withholding, will apply to a payment of sales proceeds, even if that payment is made outside the United States, if a non-U.S. holder sells our common stock through a non-U.S. office of a broker that:


	•	is a United States person;

	•	derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States;

	•	is a “controlled foreign corporation” for U.S. federal income tax purposes; or

	•	is a foreign partnership, if at any time during its tax year:


	•	one or more of its partners are United States persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or

	•	the foreign partnership is engaged in a U.S. trade or business,

unless the broker has documentary evidence in its files that the non-U.S. holder is not a United States person and certain other conditions are met or the non-U.S. holder otherwise establishes an exemption.

If a non-U.S. holder receives payments of the proceeds of a sale of our common stock to or through a United States office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless the non-U.S. holder provides a properly executed U.S. Internal Revenue Service Form W-8BEN certifying that the non-U.S. Holder is not a “United States person” or the non-U.S. holder otherwise establishes an exemption.

A non-U.S. holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed the non-U.S. holder’s U.S. federal income tax liability by filing a refund claim with the U.S. Internal Revenue Service.

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UNDERWRITING

The Company, the selling stockholder and the underwriters to be subsequently identified will enter into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table. are the representatives of the underwriters.


Underwriters		Number of Shares

Total

The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised. We expect that the underwriting agreement will provide that the obligations of the underwriters to take and pay for the shares are subject to a number of conditions, including, among others, the accuracy of the Company’s representations and warranties in the underwriting agreement, completion of the Transactions, listing of the shares, receipt of specified letters from counsel and the Company’s independent registered public accounting firm, and receipt of specified officers’ certificates.

To the extent that the underwriters sell more than shares, the underwriters have an option to buy up to an additional shares from the selling stockholder to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares in approximately the same proportion as set forth in the table above.

The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by the Company and the selling stockholder. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional shares of common stock.

Paid by the Company


	No Exercise	Full Exercise

Per Share
Total

Paid by the selling stockholder


	No Exercise	Full Exercise

Per Share
Total

Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $ per share from the initial public offering price. If all of the shares are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms.

The Company, its executive officers, directors and the selling stockholder have agreed with the underwriters, subject to exceptions, not to dispose of or hedge any of the shares of common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this prospectus continuing through the date 180 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans or shares issued in connection with acquisitions or business transactions. See ”Shares Eligible for Future Sale” for a discussion of specified transfer restrictions.

The 180-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the 180-day restricted period the Company issues an earnings release or announces material news or a material event; or (2) prior to the expiration of the 180-day restricted period, the Company announces that it will release earnings results during the

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15-day period following the last day of the 180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the 18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

We do not anticipate that the underwriters will have any intention to release shares or other securities subject to the lock-up agreements. Any determination to release any shares subject to the lock-up agreements would be based on a number of factors at the time of any such determination; such factors may include the market price of the common stock, the liquidity of the trading market for the common stock, general market conditions, the number of shares proposed to be sold, and the timing, purpose and terms of the proposed sale.

At the Company’s request, have reserved for sale, at the initial public offering price, up to % of the shares offered hereby sold to certain directors, officers, employees and persons having relationships with the Company. The number of shares of common stock available for sale to the general public will be reduced to the extent such persons purchase such reserved shares. Any reserved shares which are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered hereby.

Prior to this offering, there has been no public market for the common stock. The initial public offering price will be negotiated among the Company, the selling stockholder and the representatives. The factors to be considered in determining the initial public offering price of the shares include:


	•	the history and prospects for our industry;


	•	our historical performance, including our net sales, net income, margins and certain other financial information;


	•	estimates of our business potential and earnings prospects;


	•	an assessment of our management;


	•	investor demand for our shares of common stock;


	•	market valuations of companies that we and the representatives believe to be comparable; and


	•	prevailing securities markets at the time of this offering.

An application has been made to list the shares of common stock on the under the symbol “ ”.

In connection with this offering, the underwriters may purchase and sell shares of the common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares from the selling stockholder in this offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option granted to them. “Naked” short sales are any sales in excess of that option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares of common stock in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of various bids for or purchases of shares of common stock made by the underwriters in the open market prior to the completion of this offering.

The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of that underwriter in stabilizing or short covering transactions.

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Purchases to cover a short position and stabilizing transactions may have the effect of preventing or retarding a decline in the market price of the shares of common stock and, together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the shares of common stock. As a result, the price of the shares of common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the NYSE, in the over-the-counter market or otherwise.

Each of the underwriters has represented and agreed that:

(a) it has not made or will not make an offer of shares to the public in the United Kingdom within the meaning of section 102B of the Financial Services and Markets Act 2000, as amended, or FSMA, except to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities or otherwise in circumstances which do not require the publication by us of a prospectus pursuant to the Prospectus Rules of the Financial Services Authority, or FSA;

(b) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of section 21 of FSMA) to persons who have professional experience in matters relating to investments falling within Article 19(5) of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 or in circumstances in which section 21 of the FSMA does not apply to us; and

(c) it has complied with, and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.

In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “Relevant Member State”), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “Relevant Implementation Date”) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:

(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;

(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts; or

(c) in any other circumstances which do not require the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.

For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.

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The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.

This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (1) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (2) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (3) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.

Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.

The securities have not been and will not be registered under the Securities and Exchange Law of Japan (the “Securities and Exchange Law”) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

The underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of shares offered.

The Company estimates that its share of the total expenses of this offering, excluding underwriting discounts and commissions, will be approximately $ .

The Company and the selling stockholder have agreed to indemnify the several underwriters against specified liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

The validity of the shares of common stock offered by this prospectus will be passed upon for our company by Fried, Frank, Harris, Shriver & Jacobson LLP, New York, New York. Debevoise &

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Plimpton LLP, New York, New York is acting as counsel to the underwriters. Debevoise & Plimpton LLP has in the past provided, and continues to provide, legal services to Kelso & Company, including relating to Coffeyville Acquisition LLC.

EXPERTS

The consolidated financial statements of CVR Energy, Inc. and subsidiaries, which collectively refer to the consolidated financial statements for the year ended December 31, 2003 and for the 62 day period ended March 2, 2004 for the former Farmland Petroleum Division and one facility within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor), the consolidated financial statements as of December 31, 2004 and for the 304-day period ended December 31, 2004 and for the 174-day period ended June 23, 2005 for Coffeyville Group Holdings, LLC and subsidiaries, excluding Leiber Holdings LLC, as discussed in note 1 to the consolidated financial statements, which we refer to as Immediate Predecessor, and the consolidated financial statements as of December 31, 2005 and for the 233 day period ended December 31, 2005 for Coffeyville Acquisition LLC and subsidiaries, which we refer to as Successor, have been included herein (and in the registration statement) in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.

The audit report covering the consolidated financial statements of CVR Energy, Inc. and subsidiaries noted above contains an explanatory paragraph that states that as discussed in note 1 to the consolidated financial statements, effective March 3, 2004, Immediate Predecessor acquired the net assets of Original Predecessor in a business combination accounted for as a purchase, and 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 these acquisitions, the consolidated financial statements for the periods after the acquisitions are presented on a different cost basis than that for the periods before the acquisitions and, therefore, are not comparable. Furthermore, the audit report covering the consolidated financial statements of Coffeyville Acquisition LLC noted above contains an emphasis paragraph that states, as discussed in note 2 to the consolidated financial statements, Farmland allocated certain general corporate expenses and interest expense to Original Predecessor for the year ended December 31, 2003, and for the 62 day period ended March 2, 2004. The allocation of these costs is not necessarily indicative of the costs that would have been incurred if Original Predecessor had operated as a stand-alone entity.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement on Form S-1 under the Securities Act with respect to the common stock. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common stock, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of all or any part of it may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at 1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.

166

GLOSSARY OF SELECTED TERMS

The following are definitions of certain industry terms used in this prospectus.


2-1-1 crack spread		The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel.


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

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

bpd		Abbreviation for barrels per day.

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


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


Bulk spot basis		Prompt bulk sales (as compared to outer month sales).


By-products		Products that result from extracting high value products such as gasoline and diesel fuel from crude oil; these include black oil, sulfur, propane, pet coke and other products.

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

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

Coffeyville supply area		Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and Iowa.

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

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


Crack spread		A simplified calculation that measures the difference between the price for light products and crude oil. For example, 2-1-1 crack spread is often referenced and represents the

167


		approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel.


Crude slate		The mix of different crude types (qualities) being charged to a crude unit.


Crude slate optimization		The process of determining the most economic crude oils to be refined based upon the prevailing product values, crude prices, crude oil yields and refinery process unit operating unit constraints to maximize profit.


Crude unit		The initial refinery unit to process crude oil by separating the crude oil according to boiling point under high heat to recover various hydrocarbon fractions.


Delayed coker		A refinery unit that processes heavy feedstock using high temperature and produces lighter products and petroleum coke.


Distillates		Primarily diesel fuel, kerosene and jet fuel.

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

Farm belt		Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin.


Feedstocks		Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products.


Fluid catalytic cracking unit		Converts gas oil from the crude unit or coker unit into liquefied petroleum gas, distillates and gasoline blendstocks by applying heat in the presence of a catalyst.


Fluxant		Material added to coke to aid in the removal of coke metal impurities from the gasifier. The material consists of a mixture of fly ash and sand.


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

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

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

168


Liquefied petroleum gas		Light hydrocarbon material gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling.


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


Maya		A heavy, sour crude oil from Mexico characterized by an API gravity of approximately 22.0 and a sulfur content of approximately 3.3 weight percent.


Modified Solomon complexity		Standard industry measure of a refinery’s ability to process less expensive feedstock, such as heavier and high-sulfur content crude oils, into value-added products. The weighted average of the Solomon complexity factors for each operating unit multiplied by the throughput of each refinery unit, divided by the crude capacity of the refinery.


MTBE		Methyl Tertiary Butyl Ether, an ether produced from the reaction of isobutylene and methanol specifically for use as a gasoline blendstock. The EPA required MTBE or other oxygenates to be blended into reformulated gasoline.

Naphtha		The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane.

Netbacks		Refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excludes shipment costs. Also referred to as plant gate price.

PADD I		East Coast Petroleum Area for Defense District which includes Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West Virginia.

PADD II		Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin.

PADD III		Gulf Coast Petroleum Area for Defense District which includes Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas.

PADD IV		Rocky Mountains Petroleum Area for Defense District which includes Colorado, Idaho, Montana, Utah, and Wyoming.

PADD V		West Coast Petroleum Area for Defense District which includes Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington.


Pet coke		A coal-like substance that is produced during the refining process.

169


Rack sales		Sales which are made into tanker truck (versus bulk pipeline batcher) via either a proprietary or third terminal facility designed for truck loading.

Recordable incident		An injury, as defined by OSHA. All work-related deaths and illnesses, and those work-related injuries which result in loss of consciousness, restriction of work or motion, transfer to another job, or require medical treatment beyond first aid.

Recordable injury rate		The number of recordable injuries per 200,000 hours rate worked.


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


Refining margin		A measurement calculated as the difference between net sales and cost of products sold (exclusive of depreciation and amortization).


Reformer unit		A refinery unit that processes naphtha and converts it to high-octane gasoline by using a platinum/rhenium catalyst. Also known as a platformer.

Reformulated gasoline		The composition and properties of which meet the requirements of the reformulated gasoline regulations.


Slag		A glasslike substance removed from the gasifier containing the metal impurities originally present in the coke.


Slurry		A byproduct of the fluid catalytic cracking process that is sold for further processing or blending with fuel oil.


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

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

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

Syngas		A mixture of gases (largely carbon monoxide and hydrogen) that results from heating coal in the presence of steam.


Throughput		The volume processed through a unit or a refinery.


Ton		One ton is equal to 2,000 pounds.

Turnaround		A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years.

UAN		UAN is a solution of urea and ammonium nitrate in water used as a fertilizer.

Utilization		Ratio of total refinery throughput to the rated capacity of the refinery.

170


Vacuum unit		Secondary refinery unit to process crude oil by separating product from the crude unit according to boiling point under high heat and low pressure to recover various hydrocarbons.


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


WTI		West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 38 and 40 and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils.

WTS		West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of 32-33 degrees and a sulfur content of approximately 2 weight percent.

Yield		The percentage of refined products that is produced from crude and other feedstocks.

171

CVR Energy, Inc. and Subsidiaries

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS


Audited Financial Statements:
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2004 and December 31, 2005			F-3
Consolidated Statements of Operations for the year ended December 31, 2003, for the 62-day period ended March 2, 2004, for the 304-day period ended December 31, 2004, for the 174-day period ended June 23, 2005, and for the 233-day period ended December 31, 2005			F-4
Consolidated Statements of Equity for the year ended December 31, 2003, for the 62-day period ended March 2, 2004, for the 304-day period ended December 31, 2004, for the 174-day period ended June 23, 2005, and for the 233-day period ended December 31, 2005			F-5
Consolidated Statements of Cash Flows for the year ended December 31, 2003, for the 62-day period ended March 2, 2004, for the 304-day period ended December 31, 2004, for the 174-day period ended June 23, 2005, and for the 233-day period ended December 31, 2005			F-7
Notes to Consolidated Financial Statements			F-8
Unaudited Condensed Consolidated Financial Statements:
Condensed Consolidated Balance Sheets as of December 31, 2005 (Successor) and September 30, 2006 (Successor) (unaudited)			F-39
Condensed Consolidated Statements of Operations for the 174-day period ended June 23, 2005 (Immediate Predecessor), 141-day period ended September 30, 2005 (Successor) (unaudited) and the nine months ended September 30, 2006 (Successor) (unaudited)			F-40
Condensed Consolidated Statements of Equity for the nine months ended September 30, 2006 (Successor) (unaudited)			F-41
Condensed Consolidated Statements of Cash Flows for the 174-day period ended June 23, 2005 (Immediate Predecessor), 141-day period ended September 30, 2005 (Successor) (unaudited) and the nine months ended September 30, 2006 (Successor) (unaudited)			F-42
Notes to Condensed Consolidated Financial Statements			F-43
EX-10.7: EMPLOYMENT AGREEMENT WITH JOHN J. LIPINSKI
EX-10.8: EMPLOYMENT AGREEMENT WITH STANLEY A. RIEMANN
EX-10.9: EMPLOYMENT AGREEMENT WITH KEVAN A. VICK
EX-10.10: EMPLOYMENT AGREEMENT WITH WYATT E. JERNIGAN
EX-10.11: EMPLOYMENT AGREEMENT WITH JAMES T. RENS
EX-10.12: SEPARATION AND CONSULTING AGREEMENT
EX-10.13.1: AMENDMENT AGREEMENT
EX-10.15: ELECTRIC SERVICES AGREEMENT
EX-23.1: CONSENT OF KPMG LLP

F-1

When the transaction referred to in note 1 of the notes to consolidated financial statements has been consummated, we will be in a position to render the following report:

/s/ KPMG LLP

Report of Independent Registered Public Accounting Firm

The Board of Directors

CVR Energy, Inc.:

We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. (the Company), which collectively refers to the consolidated balance sheet as of December 31, 2004 of Coffeyville Group Holdings, LLC and subsidiaries, excluding Leiber Holdings, LLC, as discussed in note 1 to the consolidated financial statements (Immediate Predecessor), and the consolidated balance sheet as of December 31, 2005 of Coffeyville Acquisition LLC and subsidiaries (the Successor) and the related consolidated statements of operations, equity, and cash flows for the former Farmland Industries, Inc. (Farmland) Petroleum Division and one facility within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor) for the year ended December 31, 2003 and for the 62-day period ended March 2, 2004 and for the Immediate Predecessor for the 304-day period ended December 31, 2004 and for the 174-day period ended June 23, 2005 and for the Successor for the 233-day period ended December 31, 2005. These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.

We conducted our audits in accordance with the Standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.

As discussed in note 2 to the consolidated financial statements, Farmland allocated certain general corporate expense and interest expense to the Original Predecessor for the year ended December 31, 2003 and for the 62-day period ended March 2, 2004. The allocation of these costs is not necessarily indicative of the costs that would have been incurred if the Predecessor had operated as a stand-alone entity.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Immediate Predecessor as of December 31, 2004 and the Successor as of December 31, 2005 and the results of the Original Predecessor’s operations and cash flows for the year ended December 31, 2003 and for the 62-day period ended March 2, 2004 and the results of the Immediate Predecessor’s operations and cash flows for the 304-day period ended December 31, 2004 and for the 174-day period ended June 23, 2005 and the results of the Successor’s operations and cash flows for the 233-day period ended December 31, 2005 in conformity with U.S. generally accepted accounting principles.

As discussed in note 1 to the consolidated financial statements, effective March 3, 2004, the Immediate Predecessor acquired the net assets of the Original Predecessor in a business combination accounted for as a purchase, and effective June 24, 2005, the Successor acquired the net assets of the Immediate Predecessor in a business combination accounted for as a purchase. As a result of these acquisitions, the consolidated financial statements for the periods after the acquisitions are presented on a different cost basis than that for the periods before the acquisitions and, therefore, are not comparable.

Kansas City, Missouri

April 24, 2006

except as to note 1, which is as of , 2006

F-2

CVR Energy, Inc. and Subsidiaries

CONSOLIDATED BALANCE SHEETS


	Coffeyville Group
	Holdings, LLC			Coffeyville
	Immediate			Acquisition LLC
	Predecessor			Successor
	December 31,			December 31,
	2004			2005
ASSETS
Current assets:
Cash and cash equivalents	$	52,651,952		$	64,703,524
Accounts receivable, net of allowance for doubtful accounts of $190,468 and $275,188, respectively		23,383,818			71,560,052
Inventories		80,422,506			154,275,818
Prepaid expenses and other current assets		7,844,264			14,709,309
Deferred income taxes		264,246			31,059,748

Total current assets		164,566,786			336,308,451
Property, plant, and equipment, net of accumulated depreciation		50,005,847			772,512,884
Intangible assets		79,824			1,008,547
Goodwill		—			83,774,885
Deferred financing costs		7,206,653			19,524,839
Other long-term assets		6,946,793			8,418,297
Deferred income taxes		351,434			—

Total assets	$	229,157,337		$	1,221,547,903


LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	1,500,000		$	2,235,973
Revolving debt		56,510			—
Accounts payable		31,059,282			87,914,833
Personnel accruals		6,591,495			10,796,896
Accrued taxes other than income taxes		2,652,948			4,841,234
Accrued income taxes		1,301,160			4,939,614
Payable to swap counterparty		—			96,688,956
Deferred revenue		11,119,905			12,029,987
Other current liabilities		3,723,057			8,831,937

Total current liabilities		58,004,357			228,279,430
Long-term liabilities:
Long-term debt, less current portion		147,375,000			497,201,527
Accrued environmental liabilities		9,100,937			7,009,388
Deferred income taxes		—			209,523,747
Payable to swap counterparty		—			160,033,333
Other long-term liabilities		592,881			—

Total long-term liabilities		157,068,818			873,767,995
Management voting common units subject to redemption, 227,500 units issued and outstanding		—			4,172,350
Less: note receivable from management unitholder		—			(500,000	)

Total management voting common units subject to redemption, net		—			3,672,350
Members’ equity:
Voting preferred units, 63,200,000 units issued and outstanding		10,485,160			—
Non-voting common units, 11,652,941 units issued and outstanding		7,584,993			—
Unearned compensation		(3,985,991	)		—
Voting common units, 23,588,500 units issued and outstanding		—			114,830,560
Management nonvoting override units, 2,758,895 units issued and outstanding		—			997,568

Total members’ equity		14,084,162			115,828,128
Commitments and contingencies

Total liabilities and equity	$	229,157,337		$	1,221,547,903

See accompanying notes to consolidated financial statements.

F-3

CVR Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF OPERATIONS


												Coffeyville
	Farmland Industries, Inc.					Coffeyville Group Holdings, LLC						Acquisition LLC
	Original Predecessor					Immediate Predecessor						Successor
	Year Ended			62 Days Ended		304 Days Ended			174 Days Ended			233 Days Ended
	December 31,			March 2,		December 31,			June 23,			December 31,
	2003			2004		2004			2005			2005
Net sales	$	1,262,196,894		$	261,086,529	$	1,479,893,189		$	980,706,261		$	1,454,259,542
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		1,061,902,866			221,449,177		1,244,207,423			768,067,178			1,168,137,217
Direct operating expenses (exclusive of depreciation and amortization)		133,116,530			23,353,462		116,984,384			80,913,862			85,313,202
Selling, general and administrative expenses (exclusive of depreciation and amortization)		23,617,264			4,649,145		16,284,084			18,341,522			18,320,030
Depreciation and amortization		3,313,526			432,003		2,445,961			1,128,005			23,954,031
Reorganization expenses:
Impairment of property, plant and equipment		9,638,626			—		—			—			—
Rejection of executory contracts		1,250,000			—		—			—			—

Total operating costs and expenses		1,232,838,812			249,883,787		1,379,921,852			868,450,567			1,295,724,480

Operating income		29,358,082			11,202,742		99,971,337			112,255,694			158,535,062
Other income (expense):
Interest expense		(1,281,513	)		—		(10,058,450	)		(7,801,821	)		(25,007,159	)
Interest income		—			—		169,652			511,687			972,264
Gain (loss) on derivatives		303,742			—		546,604			(7,664,725	)		(316,062,111	)
Loss on extinguishment of debt		—			—		(7,166,110	)		(8,093,754	)		—
Other income (expense)		(458,514	)		9,345		52,659			(762,616	)		(563,190	)

Total other income (expense)		(1,436,285	)		9,345		(16,455,645	)		(23,811,229	)		(340,660,196	)

Income (loss) before provision for income taxes		27,921,797			11,212,087		83,515,692			88,444,465			(182,125,134	)
Income tax expense (benefit)		—			—		33,805,480			36,047,516			(62,968,044	)

Net income (loss)	$	27,921,797		$	11,212,087	$	49,710,212		$	52,396,949		$	(119,157,090	)

Unaudited Pro Forma Information (Note 1)
Basic and diluted earnings per common share												$	—
Basic and diluted weighted average common shares outstanding													—

See accompanying notes to consolidated financial statements.

F-4

CVR Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF EQUITY


	Divisional			Voting			Nonvoting			Unearned
	Equity			Preferred			Common			Compensation			Total

Original Predecessor
For the year ended December 31, 2003 and the 62 days ended March 2, 2004
Balance, January 1, 2003	$	49,773,605		$	—		$	—		$	—		$	49,773,605
Net income		27,921,797			—			—			—			27,921,797
Net distribution to Farmland Industries, Inc.		(19,503,913	)		—			—			—			(19,503,913	)

Balance, December 31, 2003		58,191,489			—			—			—			58,191,489
Net income		11,212,087			—			—			—			11,212,087
Net distribution to Farmland Industries, Inc.		(53,216,357	)		—			—			—			(53,216,357	)

Balance, March 2, 2004	$	16,187,219		$	—		$	—		$	—		$	16,187,219

Immediate Predecessor
For the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005
Members’ Equity, March 3, 2004	$	—		$	—		$	—		$	—		$	—
Issuance of 63,200,000 preferred units for cash		—			63,200,000			—			—			63,200,000
Issuance of 11,152,941 common units to management for recourse promissory notes and unearned compensation		—			—			3,100,000			(3,037,000	)		63,000
Issuance of 500,000 common units to management for recourse promissory notes and unearned compensation		—			—			2,047,450			(2,044,600	)		2,850
Recognition of earned compensation expense related to common units		—			—			—			1,095,609			1,095,609
Dividends on preferred units ($1.50 per unit)		—			(94,686,276	)		—			—			(94,686,276	)
Dividends to management on common units ($0.48 per unit)		—			—			(5,301,233	)		—			(5,301,233	)
Net income		—			41,971,436			7,738,776			—			49,710,212

Members’ Equity, December 31, 2004		—			10,485,160			7,584,993			(3,985,991	)		14,084,162
Recognition of earned compensation expense related to common units		—			—			—			3,985,991			3,985,991
Contributed capital		—			728,724			—			—			728,724
Dividends on preferred units ($0.70 per unit)		—			(44,083,323	)		—			—			(44,083,323	)
Dividends to management on common units ($0.70 per unit)		—			—			(8,128,170	)		—			(8,128,170	)
Net income		—			44,239,908			8,157,041			—			52,396,949

Members’ Equity, June 23, 2005	$	—		$	11,370,469		$	7,613,864		$	—		$	18,984,333

F-5

CVR Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF EQUITY — (Continued)


	Management Voting Common			Note Receivable from
	Units Subject to Redemption			Management Unit Holder			Total

Successor
For the 233 days ended December 31, 2005
Balance at May 13, 2005	$	—		$	—		$	—
Issuance of 177,500 common units for cash		1,775,000			—			1,775,000
Issuance of 50,000 common units for note receivable		500,000			(500,000	)		—
Adjustment to fair value for management common units		3,035,586			—			3,035,586
Net loss allocated to management common units		(1,138,236	)		—			(1,138,236	)

Balance at December 31, 2005	$	4,172,350		$	(500,000	)	$	3,672,350


						Management
	Voting			Management		Nonvoting
	Common			Nonvoting Override		Override
	Units			Operating Units		Value Units		Total

For the 233 days ended December 31, 2005
Balance at May 13, 2005	$	—		$	—	$	—	$	—
Issuance of 23,588,500 common units for cash		235,885,000			—		—		235,885,000
Issuance of 919,630 nonvested operating override units		—			—		—		—
Issuance of 1,839,265 nonvested value override units		—			—		—		—
Recognition of share-based compensation expense related to override units		—			602,381		395,187		997,568
Adjustment to fair value for management common units		(3,035,586	)		—		—		(3,035,586	)
Net loss allocated to common units		(118,018,854	)		—		—		(118,018,854	)

Balance at December 31, 2005	$	114,830,560		$	602,381	$	395,187	$	115,828,128

See accompanying notes to consolidated financial statements.

F-6

CVR Energy, Inc. and Subsidiaries

CONSOLIDATED STATEMENTS OF CASH FLOWS


							Coffeyville Group						Coffeyville
	Farmland Industries, Inc.						Holdings, LLC						Acquisition LLC
	Original Predecessor						Immediate Predecessor						Successor
	Year Ended			62 Days Ended			304 Days Ended			174 Days Ended			233 Days Ended
	December 31,			March 2,			December 31,			June 23,			December 31,
	2003			2004			2004			2005			2005
Cash flows from operating activities:
Net income (loss)	$	27,921,797		$	11,212,087		$	49,710,212		$	52,396,949		$	(119,157,090	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		3,313,526			432,003			2,445,961			1,128,005			23,954,031
Provision for doubtful accounts		—			—			190,468			(190,468	)		275,189
Amortization of deferred financing costs		—			—			1,332,890			812,166			1,751,041
Loss on extinguishment of debt		—			—			7,166,110			8,093,754			—
Reorganization expenses — impairment of property, plant, and equipment		9,638,626			—			—			—			—
Share-based compensation		—			—			1,095,609			3,985,991			997,568
Changes in assets and liabilities, net of effect of acquisition:
Accounts receivable		(25,301,358	)		19,635,303			(23,571,436	)		(11,334,177	)		(34,506,244	)
Inventories		10,371,108			(6,399,677	)		20,068,625			(59,045,550	)		1,895,473
Prepaid expenses and other current assets		(23,806,340	)		25,716,107			(6,758,666	)		(937,543	)		(6,491,633	)
Other long-term assets		(90,733	)		715,132			(5,379,727	)		3,036,659			(4,651,733	)
Accounts payable		8,347,575			(6,759,702	)		31,059,282			16,124,794			40,655,763
Accrued income taxes		—			—			1,301,160			4,503,574			(136,398	)
Deferred revenue		1,545,894			8,319,913			1,209,008			(9,073,050	)		9,983,132
Other current liabilities		419,415			364,555			12,967,500			1,254,196			10,499,712
Payable to swap counterparty		—			—			—			—			256,722,289
Accrued environmental liabilities		7,958,165			(20,057	)		(1,746,043	)		(1,553,184	)		(538,365	)
Other long-term liabilities		—			—			(689,372	)		(297,105	)		(295,776	)
Deferred income taxes		—			—			(615,680	)		3,803,937			(98,424,817	)

Net cash provided by operating activities		20,317,675			53,215,664			89,785,901			12,708,948			82,532,142

Cash flows from investing activities:
Cash paid for acquisition of Original Predecessor		—			—			(116,599,329	)		—			—
Cash paid for acquisition of Immediate Predecessor, net of cash acquired		—			—			—			—			(685,125,669	)
Capital expenditures		(813,762	)		—			(14,160,280	)		(12,256,793	)		(45,172,134	)

Net cash used in investing activities		(813,762	)		—			(130,759,609	)		(12,256,793	)		(730,297,803	)

Cash flows from financing activities:
Revolving debt payments		—			—			(57,686,789	)		(343,449	)		(69,286,016	)
Revolving debt borrowings		—			—			57,743,299			492,308			69,286,016
Proceeds from issuance of long-term debt		—			—			171,900,000			—			500,000,000
Principal payments on long-term debt		—			—			(23,025,000	)		(375,000	)		(562,500	)
Repayment of capital lease obligation		—			—			(1,176,424	)		—			—
Net divisional equity distribution		(19,503,913	)		(53,216,357	)		—			—			—
Payment of deferred financing costs		—			—			(16,309,917	)		—			(24,628,315	)
Prepayment penalty on extinguishment of debt		—			—			(1,095,000	)		—			—
Issuance of members’ equity		—			—			63,263,000			—			237,660,000
Distribution of members’ equity		—			—			(99,987,509	)		(52,211,493	)		—

Net cash provided by (used in) financing activities		(19,503,913	)		(53,216,357	)		93,625,660			(52,437,634	)		712,469,185

Net increase (decrease) in cash and cash equivalents		—			(693	)		52,651,952			(51,985,479	)		64,703,524
Cash and cash equivalents, beginning of period		2,250			2,250			—			52,651,952			—

Cash and cash equivalents, end of period	$	2,250		$	1,557		$	52,651,952		$	666,473		$	64,703,524

Supplemental disclosures
Cash paid for income taxes	$	—		$	—		$	33,820,000		$	27,040,000		$	35,593,172
Cash paid for interest	$	—		$	—		$	8,570,069		$	7,287,351		$	23,578,178
Non-cash financing activities:
Contributed capital through Leiber tax savings	$	—		$	—		$	—		$	728,724		$	—

See accompanying notes to consolidated financial statements.

F-7

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) Organization and Nature of Business and the Acquisitions

General

CVR Energy, Inc. (CVR) was incorporated in Delaware in September 2006. CVR has assumed that concurrent with this offering, a newly formed direct subsidiary of CVR’s will merge with Coffeyville Refining & Marketing, Inc. (CRM) and a separate newly formed direct subsidiary of CVR’s will merge with Coffeyville Nitrogen Fertilizers, Inc. (CNF) which will make CRM and CNF directly owned subsidiaries of CVR.

Earnings per share is calculated on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering with respect to the existing shares. Pro forma earnings per share assumes that in conjunction with the initial public offering, the two direct wholly owned subsidiaries of Successor will merge with two of CVR’s direct wholly owned subsidiaries, CVR will effect a -for- stock split prior to completion of this offering, and CVR will issue shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering pursuant to the exercise by the underwriters of their option.

Successor is a Delaware limited liability company formed May 13, 2005. Successor, acting through wholly-owned subsidiaries, is an independent petroleum refiner and marketer in the mid-continental United States and a producer and marketer of upgraded nitrogen fertilizer products in North America.

On June 24, 2005, Successor acquired all of the outstanding stock of Coffeyville Refining & Marketing, Inc. (CRM); Coffeyville Nitrogen Fertilizer, Inc. (CNF); Coffeyville Crude Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and Coffeyville Terminal, Inc. (CT) (collectively, CRIncs) from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). As a result of this transaction, CRIncs ownership increased to 100% of CL JV Holdings, LLC (CLJV), a Delaware limited liability company formed on September 27, 2004. CRIncs directly and indirectly, through CLJV, collectively own 100% of Coffeyville Resources, LLC (CRLLC) and its wholly owned subsidiaries, Coffeyville Resources Refining & Marketing, LLC (CRRM); Coffeyville Resources Nitrogen Fertilizers, LLC (CRNF); Coffeyville Resources Crude Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC (CRP); and Coffeyville Resources Terminal, LLC (CRT).

Successor had no financial statement activity during the period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil, and gasoline option agreements entered into with a related party (see notes 14 and 15) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 233 days ended December 31, 2005.

Immediate Predecessor was a Delaware limited liability company formed in October 2003. There was no financial statement activity until March 3, 2004, when Immediate Predecessor, acting through wholly owned subsidiaries, acquired the assets of the former Farmland Industries, Inc. (Farmland) Petroleum Division and one facility located in Coffeyville, Kansas within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor) (the Initial Acquisition). As of March 3, 2004, Immediate Predecessor owned 100% of CRIncs, and CRIncs owned 100% of CRLLC and its wholly owned subsidiaries, CRRM, CRNF, CRCT, CRP, and CRT. Farmland was a farm supply cooperative and a processing and marketing cooperative. Original Predecessor operated as a division of Farmland (Petroleum), and as a plant within a division of Farmland (Nitrogen Fertilizer). The accompanying Original Predecessor financial statements principally reflect the refining, crude oil gathering, and petroleum distribution operations of Farmland and the only coke gasification plant of Farmland’s nitrogen fertilizer operations.

F-8

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Since the assets and liabilities of Successor and Immediate Predecessor (collectively, CVR) were each presented on a new basis of accounting, the financial information for Successor, Immediate Predecessor, and Original Predecessor (collectively, the Entities) is not comparable.

On October 8, 2004, Immediate Predecessor, acting through its wholly owned subsidiaries, CRM and CNF, contributed 68.7% of its membership in CRLLC to CLJV, in exchange for a controlling interest in CLJV. Concurrently, The Leiber Group, Inc., a company whose majority stockholder is Pegasus Partners II, L.P., the Immediate Predecessor’s principal stockholder, contributed to CLJV its interest in the Judith Leiber business, which is a designer handbag business, in exchange for a minority interest in CLJV. The Judith Leiber business is owned through Leiber Holdings, LLC (LH), a Delaware limited liability company wholly owned by CLJV. Based on the relative values of the properties at the time of contribution to CLJV, CRM and CNF collectively, were entitled to 80.5% of CLJV’s net profits and net losses. Under the terms of CRLLC’s credit agreement, CRLLC was permitted to make tax distributions to its members, including CLJV, in amounts equal to the tax liability that would be incurred by CRLLC if its net income were subject to corporate-level income tax. From the tax distributions CLJV received from CRLLC as of December 31, 2004 and June 23, 2005, CLJV contributed $1,600,000 and $4,050,000, respectively, to LH which is presented as tax expense in the respective periods in the accompanying consolidated statements of operations for the reasons discussed below.

On June 23, 2005, as part of the stock purchase agreement, LH completed a merger with Leiber Merger, LLC, a wholly owned subsidiary of The Leiber Group, Inc. As a result of the merger, the surviving entity was LH. Under the terms of the agreement, CLJV forfeited all of its ownership in LH to The Leiber Group, Inc in exchange for LH’s interest in CLJV. The result of this transaction was to effectively redistribute the contributed businesses back to The Leiber Group, Inc.

The operations of LH and its subsidiaries (collectively, Leiber) have not been included in the accompanying consolidated financial statements of the Immediate Predecessor because Leiber’s operations were unrelated to, and are not part of, the ongoing operations of CVR. CLJV’s management was not the same as the Immediate Predecessor’s, the Successor’s, or CVR’s there were no intercompany transactions between CLJV and the Immediate Predecessor, the Successor, or CVR aside from the contributions, and the Immediate Predecessor only participated in the joint venture for a short period of time. CLJV’s contributions to LH of $1,600,000 and $4,050,000 have been reflected as a reduction to accrued income taxes in the accompanying consolidated balance sheets to appropriately reflect the accrued income tax obligations of Immediate Predecessor as of December 31, 2004 and June 23, 2005, respectively. The tax benefits received from LH, as a result of losses incurred by LH, have been reflected as capital contributions in the accompanying consolidated financial statements of the Immediate Predecessor.

Farmland Industries, Inc.’s Bankruptcy Proceedings and the Initial Acquisition

On May 31, 2002 (the Petition Date), Farmland Industries, Inc. and four of its subsidiaries, Farmland Foods, Inc.; Farmland Pipeline Company, Inc.; Farmland Transportation, Inc.; and SFA, Inc. (collectively, the Debtors or Farmland), filed voluntary petitions for protection under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court, Western District of Missouri (the Court). Petroleum and Nitrogen Fertilizer were divisions of Farmland; therefore, their assets and liabilities were included in the bankruptcy filings. Farmland continued to manage the business as debtor-in-possession but could not engage in transactions outside the ordinary course of business without the approval of the Court.

As a result of the filing on May 31, 2002 of petitions under Chapter 11 of the Bankruptcy Code by the Debtors, the accompanying Original Predecessor’s financial statements have been prepared in

F-9

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

accordance with AICPA Statement of Position (SOP) 90-7, Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, and in accordance with accounting principles generally accepted in the United States of America applicable to a going concern, which, unless otherwise noted, assume the realization of assets and the payment of liabilities in the ordinary course of business.

As debtors-in-possession, the Debtors, subject to any required Court approval, may elect to assume or reject real estate leases, employment contracts, personal property leases, service contracts, and other unexpired executory pre-petition contracts. Damages related to rejected contracts are a pre-petition claim. The Petroleum Segment had no material accruals for any damages as of December 31, 2003. The Nitrogen Fertilizer Segment rejected an operating and maintenance agreement with a vendor resulting in an accrual of approximately $1,250,000 as of December 31, 2003 which was charged to reorganization expenses in the year ending December 31, 2003.

Pursuant to the provisions of the Bankruptcy Code, on November 27, 2002 the Debtors filed with the Court a Plan of Reorganization under which the Debtors’ liabilities and equity interests would be restructured. Subsequently, on July 31, 2003, the Debtors filed with the Court an Amended Plan of Reorganization (the Amended Plan). The Amended Plan as filed in effect contemplated that the Debtors would continue in existence solely for the purpose of liquidating any remaining assets of the estate, including the Petroleum and Nitrogen Fertilizer segments. In accordance with the Amended Plan, on October 10, 2003, the Court entered an order approving the auction and bid procedures for the sale of the Petroleum Division and Coffeyville nitrogen fertilizer plant to subsidiaries of Immediate Predecessor. Through an auction process conducted by the Court, the assets of Original Predecessor were sold on March 3, 2004, to Immediate Predecessor for $106,727,365, including the assumption of $23,216,554 of liabilities. Immediate Predecessor also paid transaction costs of $9,871,964, which consisted of legal, accounting, and advisory fees of $7,371,964 paid to various parties and a finder’s fee of $2,500,000 paid to Pegasus Capital Advisors, L.P. (see note 15). Immediate Predecessor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Initial Acquisition was financed through long-term borrowings of approximately $60.7 million and the issuance of preferred units of approximately $63.2 million. The allocation of the purchase price at March 3, 2004, the date of the Initial Acquisition, was as follows:


Assets acquired
Inventories	$	100,491,131
Prepaid expenses and other current assets		1,085,598
Property, plant, and equipment		38,239,154

Total assets acquired	$	139,815,883

Liabilities assumed
Deferred revenue	$	9,910,897
Capital lease obligations		1,176,424
Accrued environmental liabilities		10,846,980
Other long-term liabilities		1,282,253

Total liabilities assumed	$	23,216,554

Cash paid for acquisition of Original Predecessor	$	116,599,329

F-10

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Subsequent Acquisition

On May 15, 2005, Successor and Immediate Predecessor entered into an agreement whereby Successor acquired 100% of the outstanding stock of CRIncs with an effective date of June 24, 2005 for $673,273,440, including the assumption of $353,084,637 of liabilities. Successor also paid transaction costs of $12,518,702, which consisted of legal, accounting, and advisory fees of $5,782,740 paid to various parties, and transaction fees of $6,000,000 and $735,962 in expenses related to the acquisition paid to institutional investors (see note 15). Successor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Subsequent Acquisition was financed through long-term borrowings of approximately $500 million, short-term borrowings of approximately $12.6 million, and the issuance of common units for approximately $227.7 million. The allocation of the purchase price at June 24, 2005, the date of the Subsequent Acquisition, is as follows:


Assets acquired
Cash	$	666,473
Accounts receivable		37,328,997
Inventories		156,171,291
Prepaid expenses and other current assets		4,865,241
Intangibles, contractual agreements		1,322,000
Goodwill		83,774,885
Other long-term assets		3,837,647
Property, plant, and equipment		750,910,245

Total assets acquired	$	1,038,876,779

Liabilities assumed
Accounts payable	$	47,259,070
Other current liabilities		16,017,210
Current income taxes		5,076,012
Deferred income taxes		276,888,816
Other long-term liabilities		7,843,529

Total liabilities assumed	$	353,084,637

Cash paid for acquisition of Immediate Predecessor	$	685,792,142

Pro forma revenue would be unchanged for the periods presented. Unaudited pro forma net income (loss) as if the Subsequent Acquisition and related debt refinancing had occurred as of the beginning of each period presented compared to historical net income (loss) presented below is as follows (in thousands):

Immediate Predecessor

Successor

Pro Forma

174 Days Ended

233 Days Ended

Year Ended

June 23,

December 31,

2005

Net Income (loss)

52,397

119,157

)

82,898

)

Original Predecessor

Immediate Predecessor

Pro Forma

62 Days Ended

304 Days Ended

Year Ended

March 2,

December 31,

2004

Net Income

11,212

49,710

20,730

F-11

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(2)	Basis of Presentation

The accompanying Original Predecessor financial statements reflect an allocation of certain general corporate expenses of Farmland, including general and corporate insurance, corporate retirement and benefits, human resources and payroll department salaries, facility costs, information services, and information systems support. Those costs allocated to the Original Predecessor were $12,709,178 and $3,802,996 for the year ended December 31, 2003 and the 62-day period ended March 2, 2004, respectively, and are included in selling, general, and administrative expenses. These allocations were based on a variety of factors dependent on the nature of the costs, including fixed asset levels, administrative headcount, and production headcount. The Petroleum Division and Coffeyville nitrogen plant represented a continually increasing percentage of Farmland’s business as a result of Farmland’s restructuring efforts, which by December 2003 included the disposition of nearly all Farmland’s operating assets with the exception of the Petroleum Division and Coffeyville nitrogen plant. As a result, the Petroleum Division and Coffeyville nitrogen plant were allocated a higher percentage of corporate cost in the 62 day period ending on March 2, 2004 than in 2003. The costs of these services are not necessarily indicative of the costs that would have been incurred if Original Predecessor had operated as a stand-alone entity. Reorganization expenses for legal and professional fees incurred by Farmland in connection with the bankruptcy proceedings were not allocated to the Original Predecessor. In addition, umbrella property insurance premiums were allocated across Farmland’s divisions based on recoverable values. Property insurance costs allocated to the Original Predecessor were $2,060,532 and $357,324 for the year ended December 31, 2003 and the 62-day period ended March 2, 2004, respectively, and are included in cost of goods sold. All interest expense on secured borrowings was allocated based on identifiable net assets of each of Farmland’s divisions. Under bankruptcy law, payment of interest on Farmland’s unsecured debt was stayed beginning on the Petition Date. Accordingly, Farmland did not allocate any interest on its unsecured borrowings to the Original Predecessor for the 62 days ended March 2, 2004. Management believes all allocations described above were made on a reasonable basis.

Farmland used a centralized approach to cash management and the financing of its operations. As a result, amounts owed to or by Farmland are reflected as a component of divisional equity on the accompanying consolidated statements of equity. Farmland’s divisional equity represents the net investment Farmland had in the reporting entity.


(3)	Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its subsidiaries, all of which are wholly-owned. All significant intercompany balances and transactions have been eliminated in consolidation.

Cash and Cash Equivalents

For purposes of the consolidated statements of cash flows, CVR considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. CVR had restricted cash held for debt repayment of $3,500,000 and $0 at December 31, 2004 and 2005, respectively; restricted cash was reflected in other long-term assets on the consolidated balance sheet since the restriction was for the term of the debt (see note 10).

F-12

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Accounts Receivable

CVR grants credit to its customers. Credit is extended based on an evaluation of a customer’s financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding longer than their contractual payment terms are considered past due. CVR determines its allowance for doubtful accounts by considering a number of factors, including the length of time trade accounts are past due, the customer’s ability to pay its obligations to CVR, and the condition of the general economy and the industry as a whole. CVR writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2004, three customers individually represented greater than 10% and collectively represented 38% of the accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2004 was 15% of the total accounts receivable balance. At December 31, 2005, two customers individually represented greater than 10% and collectively represented 41% of the total accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2005 was 28% of the accounts receivable balance.

Inventories

Inventories consist primarily of crude oil, blending stock and components, work in progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of moving-average cost, which approximates the first-in, first-out (FIFO) method, or market for fertilizer products and at the lower of FIFO cost or market for refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bare process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

In connection with the initial distribution of the accompanying Original Predecessor financial statements for purposes of effecting a business combination, the Original Predecessor changed its method of accounting for inventories from the last-in, first-out (LIFO) method to the FIFO method. Management believes the FIFO method is preferable in the circumstances because the FIFO method is considered to represent a better matching of costs with related revenues under current volatile market conditions. Accordingly, crude oil, blending stock and components, work in progress, and refined fuels and by-products are valued at the lower of FIFO cost or market for all years presented.

Prepaid Expenses and Other Current Assets

Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to the refinery for which title had not transferred, non-trade accounts receivables, current portions of prepaid insurance and deferred financing costs, and other general current assets.

Property, Plant, and Equipment

Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1,000,000 in cost which is expected to take more than six months to

F-13

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

complete. Depreciation is computed using principally the straight-line method over the estimated useful lives of the assets. The useful lives are as follows:


Asset	Range of useful lives, in years

Improvements to land		15 to 20
Buildings		20 to 30
Machinery and equipment		5 to 30
Automotive equipment		5
Furniture and fixtures		3 to 5

Goodwill and Intangible Assets

Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. CVR uses November 1 of each year as its annual valuation date for the impairment test. The annual review of impairment is performed by comparing the carrying value of the applicable reporting unit to its estimated fair value, using a combination of the discounted cash flow analysis and market approach. Our reporting units are defined as operating segments due to each operating segment containing only one component. As such all goodwill impairment testing is done at each operating segment.

Deferred Financing costs

Deferred financing costs are amortized using the effective-interest method over the life of the loan.

Planned Major Maintenance Costs

The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. During the 304-day period ended December 31, 2004, the Coffeyville nitrogen plant completed a major scheduled turnaround. Costs of approximately $1,800,000 associated with the turnaround are included in cost of goods sold for that period. The Coffeyville nitrogen plant is scheduled for the next turnaround in 2006. The Coffeyville refinery last completed a major scheduled turnaround in 2002 and is scheduled for the next turnaround in 2007.

Income Taxes

Original Predecessor was not a separate legal entity, and its operating results were included with 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, the accompanying Original Predecessor financial statements do not reflect any provision for income taxes.

Income taxes for CVR are accounted for under the asset-and-liability method. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and

F-14

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled.

Impairment of Long-Lived Assets

CVR accounts for long-lived assets in accordance with Statement of Financial Accounting Standards No. 144 (SFAS 144), Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with SFAS 144, CVR reviews long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell.

In its Plan of Reorganization, Farmland stated, among other things, its intent to dispose of its petroleum and nitrogen assets. Despite this stated intent, these assets were not classified as held for sale under SFAS 144 because, ultimately, any disposition required approval of the Court and the Court did not ultimately approve such disposition until March 3, 2004. Since Farmland determined that it was more likely than not that its petroleum and nitrogen fertilizer assets would be disposed of, those assets were tested for impairment in 2002 pursuant to SFAS 144, using projected undiscounted net cash flows 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 sales process. Based on the tests, assumptions and determinations as of the impairment testing date, the assets were determined to be impaired. Farmland’s best estimate at December 31, 2002 was that the carrying value of these assets exceeded the fair value expected to be received on disposition of these assets by $375,068,359. Accordingly, an impairment charge was recognized for such amount in 2002. The ultimate proceeds from disposition of these assets resulted from a bidding and auction process conducted in the bankruptcy proceedings. In 2003, as a result of receiving a stalking horse bid from Coffeyville Resources, LLC 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 of $9,638,626 was taken. No impairment charges were recognized for the years ended December 31, 2004 or 2005.

Revenue Recognition

Sales are recognized when the product is delivered and all significant obligations of CVR have been satisfied. Deferred revenue represents customer prepayments under contracts to guarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business.

Shipping Costs

Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of goods sold.

Derivative Instruments and Fair Value of Financial Instruments

CVR uses futures contracts, options, and forward swap contracts primarily to reduce the exposure to changes in crude oil prices, finished goods product prices and interest rates and to provide economic hedges of inventory positions. These derivative instruments have not been

F-15

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

designated as hedges for accounting purposes. Accordingly, these instruments are recorded in the consolidated balance sheets at fair value, and each period’s gain or loss is recorded as a component of other income (expense) in accordance with Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities.

Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. The carrying value of long-term and revolving debt approximates fair value as a result of the floating interest rates assigned to those financial instruments.

Share-Based Compensation

CVR accounts for share-based compensation in accordance with Statement of Financial Accounting Standards (SFAS) No. 123(R), Share-Based Payments. In accordance with SFAS 123(R), CVR applies a fair-value-based measurement method in accounting for share-based compensation.

Environmental Matters

Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted as new facts or changes in law or technology occur. Environmental expenditures are capitalized when such costs provide future economic benefits.

Use of Estimates

In preparing financial statements in conformity with accounting principles generally accepted in the United States of America, management is required to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Recently Adopted Accounting Standards

In November 2004, the FASB issued Statement of Financial Accounting Standards No. 151 (SFAS 151), Inventory Costs, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and wasted material, and requires that those items be recognized as current-period charges. SFAS 151 also requires that allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. SFAS 151 is effective for fiscal years beginning after June 15, 2005 and is not expected to have a material effect on Successor’s financial position or results of operations.

In December 2004, the FASB issued Statement of Accounting Standards No. 153 (SFAS 153), Exchanges of Nonmonetary Assets, which addresses the measurement of exchanges of nonmonetary assets. SFAS 153 eliminates the exception from fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29, Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges which do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows of the entity are expected to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after

F-16

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

June 15, 2005. The adoption of SFAS 153 is not expected to have a material effect on CVR’s financial position or results of operations.

In December 2004, the FASB issued SFAS 123(R), Share-Based Payments. SFAS 123(R) revises SFAS 123 and supersedes APB 25. SFAS 123(R) requires that compensation costs relating to share-based payment transactions be recognized in a company’s financial statements. SFAS 123(R) applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments. Under SFAS 123(R), CVR is required to apply a fair-value-based measurement method in accounting for share-based payment transactions with employees. SFAS 123(R) is effective for periods beginning after December 15, 2005; however, Successor elected early adoption of SFAS 123(R) for the 233-day period ended December 31, 2005. The effect of the adoption of this standard is described in note 4.

In March 2005, the FASB issued FASB Interpretation No 47 (FIN 47) Accounting for Conditional Asset Retirement Obligations. FIN 47 requires conditional asset retirement obligations to be recognized if a legal obligation exists to perform asset retirement activities and a reasonable estimate of the fair value of the obligation can be made. FIN 47 also provides guidance as to when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. FIN 47 became effective for the period ending December 31, 2005. A net asset retirement obligation of $636,000 was included in other current liabilities on the consolidated balance sheet.


(4)	Members’ Equity

Immediate Predecessor issued 63,200,000 voting preferred units at $1 par value for cash to finance the Initial Acquisition, as described in note 1. The preferred units were the only voting units of Immediate Predecessor and, prior to May 10, 2004, had preferential rights to distributions. The preferred units only had voting preferences and preferences related to the distributions. The preference required that the holders of preferred units were to be distributed $63,200,000, plus a preferred yield equal to 15% per annum compounded monthly, before any distributions could be made to holders of common units. Of the 63,200,000 of voting preferred units issued, all 55,500,000 preferred units issued and outstanding were issued to related parties. Pegasus Partners II, L.P., which held 52,500,000 preferred units, is an affiliate of Pegasus Capital Advisors, L.P. with whom the Immediate Predecessor entered into a management services agreement. The remaining 3,000,000 of preferred units were issued to management members who had employment agreements with subsidiaries of the Immediate Predecessor.

Concurrent with the issuance of the preferred units, management of Immediate Predecessor was issued 11,152,941 nonvoting restricted common units for recourse promissory notes aggregating $63,000. Based on the estimated relative fair value of the restricted common units on March 3, 2004, $3,100,000 was allocated to the common units. Accordingly, unearned compensation of $3,037,000 was recognized as a contra-equity balance in the accompanying consolidated balance sheet. The holders of these common units were not vested at the date of issuance. Prior to May 10, 2004, distribution rights were subordinated to the preferred unit holders, as described above. On May 10, 2004, the promissory notes were repaid with cash and an additional 500,000 nonvoting restricted common units were issued to an officer of Immediate Predecessor for a recourse promissory note of $2,850. Based on the estimated fair value of the units on May 10, 2004, unearned compensation of $2,044,600 was recognized as a contra-equity balance in the accompanying consolidated balance sheet. Concurrent with the Subsequent Acquisition at June 23, 2005, as described in note 1, all of the restricted common units were fully vested. Immediate Predecessor recognized $1,095,609 and

F-17

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$3,985,991 in compensation expense for the 304-day period ended December 31, 2004 and the 174-day period ended June 23, 2005, respectively, related to earned compensation.

On May 10, 2004, Immediate Predecessor refinanced its existing long term-debt with a $150 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under Immediate Predecessor’s previous credit facility. The borrowings were also used to distribute a $99,987,509 dividend, which included the preference payment of $63,200,000 plus the yield of $1,802,956 to the preferred unit holders and a $63,000 payment to the common unit holders for undistributed capital per the LLC agreement. The remaining $34,921,553 was distributed to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.

On June 23, 2005, immediately prior to the Subsequent Acquisition (see note 1), the Immediate Predecessor used available cash balances to distribute a $52,211,493 dividend to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.

Successor issued 22,766,000 voting common units at $10 par value for cash to finance the Subsequent Acquisition, as described in note 1. An additional 50,000 voting common units at $10 par value were issued to a member of management for an unsecured recourse promissory note that bears interest at 7% and requires annual principal and interest payments through December 2009. As required by the term loan agreements to fund certain capital projects, on September 14, 2005 an additional $10,000,000 was received in return for 1,000,000 voting common units at $10 par value (Delayed Draw Capital). Common units held by management contain put rights held by management and call rights held by Successor exercisable at fair value in the event the management member becomes inactive. Accordingly, in accordance with EITF Topic No. D-98, “Classification and Measurement of Redeemable Securities,” common units held by management were initially recorded at fair value at the date of issuance and have been classified in temporary equity as Management Voting Common Units Subject to Redemption (Capital Subject to Redemption) in the accompanying consolidated balance sheets. At December 31, 2005, management held 227,500 of the 23,816,000 voting common units.

The put rights with respect to management’s common units, provide that following their termination of employment, they have the right to sell all (but not less than all) of their common units to Coffeyville Acquisition LLC at their “Fair Market Value” (as that term is defined in the LLC Agreement) if they were terminated without “Cause,” or as a result of death, “Disability” or resignation with “Good Reason” (each as defined in the LLC Agreement) or due to “Retirement” (as that term is defined in the LLC Agreement). Coffeyville Acquisition LLC has call rights with respect to the executives’ common units, so that following the executives’ termination of employment, Coffeyville Acquisition LLC has the right to purchase the common units at their Fair Market Value if the executive was terminated without Cause, or as a result of the executive’s death, Disability or resignation with Good Reason or due to Retirement. The call price will be the lesser of the common unit’s Fair Market Value or Carrying Value (which means the capital contribution, if any, made by the executive in respect of such interest less the amount of distributions made in respect of such interest) if the executive is terminated for Cause or he resigns without Good Reason. For any other termination of employment, the call price will be at the Fair Market Value or Carrying Value of such common units, in the sole discretion of Coffeyville Acquisition LLC’s board of directors. No put or call rights apply to override units following the executive’s termination of employment unless Coffeyville Acquisition LLC’s board of directors (or the compensation committee thereof) determines in its discretion that put and call rights will apply.

F-18

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CVR accounts for changes in redemption value of management common units in the period the changes occur and adjusts the carrying value of the Capital Subject to Redemption to equal the redemption value at the end of each reporting period with an equal and offsetting adjustment to Members’ Equity. None of the Capital Subject to Redemption was redeemable at December 31, 2005.

At December 31, 2005, the Capital Subject to Redemption was revalued through an independent appraisal process, and the value was determined to be $18.34 per unit. Accordingly, the carrying value of the Capital Subject to Redemption increased by $3,035,586 for the 233-day period ended December 31, 2005 with an equal and offsetting decrease to Members’ Equity.

Concurrent with the Subsequent Acquisition, Successor issued nonvoting override units to certain management members who hold common units. There were no required capital contributions for the override units.

919,630 Override Operating Units at a Benchmark Value of $10 per Unit

In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,604,950. Pursuant to the forfeiture schedule described below, the Company is recognizing compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in-substance, multiple awards. Compensation expense in the 233-day period ended December 31, 2005 was $602,381. Significant assumptions used in the valuation were as follows:


•	Estimated forfeiture rate	None
•	Explicit service period	Based on forfeiture schedule below
•	Grant-date fair value — controlling basis	$5.16 per share
•	Marketability and minority interest discounts	$1.24 per share (24% discount)
•	Volatility	37%

Override operating units participate in distributions in proportion to the number of total common, non-forfeited override operating and participating override value units issued. Distributions to override operating units will be reduced until the total cumulative reductions are equal to the benchmark value. Override operating units are forfeited upon termination of employment for cause. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:


	Forfeiture
Minimum Period Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

On the tenth anniversary of the issuance of override operating units, such units shall convert into an equivalent number of override value units.

1,839,265 Override Value Units at a Benchmark Value of $10 per Unit

F-19

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Compensation expense in the 233-day period ended December 31, 2005 was $395,187. Significant assumptions used in the valuation were as follows:


•	Estimated forfeiture rate	None
•	Derived service period	6 years
•	Grant-date fair value — controlling basis	$2.91 per share
•	Marketability and minority interest discounts	$0.70 per share (24% discount)
•	Volatility	37%

Value units fully participate in cash distributions when the amount of such cash distributions to certain investors (Current Common Value) is equal to four times the original contributed capital of such investors (including the Delayed Draw Capital required to be contributed pursuant to the long term credit agreements). If the Current Common Value is less than two times the original contributed capital of such investors at the time of a distribution, none of the override value units participate. In the event the Current Common Value is greater than two times the original contributed capital of such investors but less than four times, the number of participating override value units is the product of 1) the number of issued override value units and 2) the fraction, the numerator of which is the Current Common Value minus two times original contributed capital, and the denominator of which is two times the original contributed capital. Distributions to participating override value units will be reduced until the total cumulative reductions are equal to the benchmark value. On the tenth anniversary of any override value unit (including any override value unit issued on the conversion of an override operating unit) the “two times” threshold referenced above will become “10 times” and the “four times” threshold referenced above will become “12 times”. Unless the compensation committee of the board of directors takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:


	Subject to
	Forfeiture
Minimum Period Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

Successor, through a wholly-owned subsidiary, has a Phantom Unit Appreciation Plan whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points have rights to receive distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units receive distributions. There are no other rights or guarantees, and the plan expires on July 25, 2015, or at the discretion of the compensation committee of the board of directors. The total combined interest of the Phantom Unit Plan and the override units (combined Profits Interest) cannot exceed 15% of the notional and aggregate equity interests of the Successor. As of December 31, 2005, the issued Profits Interest represented 11.73% of combined common unit interest and Profits Interest of the Company. The Profits Interest was comprised of 10.22% and 1.51% of override interest and phantom interest, respectively. Subject to the valuation, vesting and forfeiture provisions consistent with other profit interests described previously, $95,019 is included in personnel accruals as of

F-20

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2005 and as compensation expense for the 233-day period ending December 31, 2005 related to the Phantom Unit Plan.


(5)	Inventories

Inventories consisted of the following (in thousands):


	Immediate
	Predecessor		Successor
	December 31,		December 31,
	2004		2005
Finished goods	$	24,704	$	58,513
Raw materials and catalysts		26,136		47,437
In-process inventories		14,059		33,397
Parts and supplies		15,524		14,929

	$	80,423	$	154,276


(6)	Property, Plant, and Equipment

A summary of costs for property, plant, and equipment is as follows (in thousands):


	Immediate
	Predecessor		Successor
	December 31,		December 31,
	2004		2005
Land and improvements	$	1,061	$	9,346
Buildings		768		10,306
Machinery and equipment		39,617		715,381
Automotive equipment		660		3,396
Furniture and fixtures		1,372		271
Construction in progress		8,738		57,382

		52,216		796,082
Accumulated depreciation		2,210		23,569

	$	50,006	$	772,513

Construction in progress of $2,067,869 and $26,977,642 as of December 31, 2004 and 2005, respectively, related to capital improvements for compliance with EPA regulations intended to limit amounts of sulfur in diesel and gasoline.

Capitalized interest recognized as a reduction in interest expense for the 174-day period ended June 23, 2005 and the 233-day period ended December 31, 2005, totaled approximately $297,694 and $831,264, respectively.


(7)	Goodwill and Intangible Assets

In connection with the Subsequent Acquisition described in note 1, Successor recorded goodwill of $83,774,885. Successor completed its annual test for impairment of goodwill as of November 1, 2005. Based on the results of the test, no impairment of goodwill was recorded as of December 31, 2005. The annual review of impairment is performed by comparing the carrying value of the applicable reporting unit to its estimated fair value using a combination of the discounted cash flow analysis and

F-21

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

market approach. Our reporting units are defined as operating segments due to each operating segment containing only one component. As such all goodwill impairment testing is done at each operating segment.

Contractual agreements with a fair market value of $1,322,000 were acquired in the Subsequent Acquisition described in note 1. The intangible value of these agreements is amortized over the life of the agreements through June 2025. Accumulated amortization was $313,453 at December 31, 2005. Amortization expense for the 233-days ended December 31, 2005 of $202,303 was reported as cost of goods sold and $111,150 was reported as selling, general, and administrative expenses.

Estimated amortization of the contractual agreements is as follows (in thousands):


	Contractual
Year Ending December 31,	Agreements

2006	$	370
2007		165
2008		64
2009		33
2010		33
Thereafter		344

		1,009


(8)	Deferred Financing Costs

Deferred financing costs of $6,300,727 were paid in the Initial Acquisition described in note 1. Additional deferred financing costs of $10,009,193 were paid with the debt refinancing on May 10, 2004, as described in notes 4 and 10. The unamortized deferred financing costs of $6,071,110 related to the Initial Acquisition financing were written off when the related debt was extinguished and refinanced with the existing credit facility and these costs were included in loss on extinguishment of debt for the 304 days ended December 31, 2004. A prepayment penalty of $1,095,000 on the previous credit facility was also paid and expensed and included in loss on extinguishment of debt for the 304 days ended December 31, 2004. The unamortized deferred financing costs of $8,093,754 related to the May 10, 2004 refinancing were written off when the related debt was extinguished upon the Subsequent Acquisition described in note 1 and these costs were included in loss on extinguishment of debt for the 174 days ended June 23, 2005. For the 304 days ended December 31, 2004 and for the 174 days ended June 23, 2005, amortization of deferred financing costs reported as interest expense was $1,332,890 and $812,166, respectively, using the effective-interest amortization method.

Deferred financing costs of $24,628,315 were paid in the Subsequent Acquisition, and will be amortized through June 2013. For the 233 days ended December 31, 2005, amortization of deferred financing costs reported as interest expense totaled $1,751,041 using the effective-interest amortization method.

F-22

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Deferred financing costs consisted of the following (in thousands):


	Immediate
	Predecessor		Successor
	December 31,		December 31,
	2004		2005
Deferred financing costs	$	10,009	$	24,628
Less accumulated amortization		1,103		1,751

Unamortized deferred financing costs		8,906		22,877
Less current portion		1,699		3,352

	$	7,207	$	19,525

Estimated amortization of deferred financing costs is as follows (in thousands):


	Deferred
Year Ending December 31,	Financing

2006	$	3,352
2007		3,337
2008		3,332
2009		3,308
2010		3,293
Thereafter		6,255

	$	22,877


(9)	Other Long-Term Assets

Other long-term assets consisted of the following (in thousands):


	Immediate
	Predecessor		Successor
	December 31,		December 31,
	2004		2005
Restricted cash held for debt repayment	$	3,500	$	—
Prepaid insurance charges		3,047		2,447
Non-current receivables		—		4,889
Other assets		400		1,082

	$	6,947	$	8,418

Non-current receivables consist of unsettled mark-to-market gains on derivatives relating to the interest rate swap agreements described in notes 14 & 15.

CVR has prepaid two environmental insurance policies. One policy covers environmental site protection, and the other is a cost cap remediation policy for costs to be incurred beyond the next twelve months. See note 13 for a further description of the environmental commitments and contingencies.

F-23

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Estimated amortization of prepaid insurance is as follows (in thousands):


	Prepaid
Year Ending December 31,	Insurance

2006	$	1,062
2007		394
2008		333
2009		333
2010		333
Thereafter		1,054

		3,509
Less current portion		(1,062	)

Total long-term	$	2,447


(10)	Long-Term Debt

At March 3, 2004, Immediate Predecessor entered into an agreement with a financial institution for a term loan of $21,900,000 with an interest rate based on the greater of the Index Rate (the greater of prime or the federal funds rate plus 50 basis points per annum) plus 4.5% or 9% and a $100,000,000 revolving credit facility with interest at the borrower’s election of either the Index Rate plus 3% or the LIBOR rate plus 3.5%. Amounts totaling $21,900,000 of the term loan borrowings and $38,821,970 of the revolving credit facility were used to finance the Initial Acquisition on March 3, 2004 as described in note 1. Outstanding borrowings on May 10, 2004 were repaid in connection with the refinancing described below.

Effective May 10, 2004, Immediate Predecessor entered into a term loan of $150,000,000 and a $75,000,000 revolving loan facility with a syndicate of banks, financial institutions, and institutional lenders. Both loans were secured by substantially all of the Immediate Predecessor’s real and personal property, including receivables, contract rights, general intangibles, inventories, equipment, and financial assets. There were outstanding borrowings of $148,875,000 and $56,510 at December 31, 2004, respectively. Outstanding borrowings on June 23, 2005 were repaid in connection with the Subsequent Acquisition as described in note 1.

Effective June 24, 2005, Successor entered into a first lien credit facility and a guaranty agreement with two banks and one related party institutional lender (see note 15). The credit facility is in an aggregate amount not to exceed $525,000,000, consisting of $225,000,000 Tranche B Term Loans; $50,000,000 of Delayed Draw Term Loans available for the first 18 months of the agreement and subject to accelerated payment terms; a $100,000,000 Revolving Loan Facility; and a Funded Letters of Credit Facility (Funded Facility) of $150,000,000. The credit facility is secured by substantially all of Successor’s assets. At December 31, 2005, $224,437,500 of Tranche B Term Loans was outstanding, and there was no outstanding balance on the Revolving Loan Facility or the Delayed Draw Term Loans. At December 31, 2005, Successor had $150,000,000 in Funded Letters of Credit outstanding to secure payment obligations under derivative financial instruments (see note 14).

The Term Loans and Revolving Loan Facility provide CVR the option of a 3-month LIBOR rate plus 2.5% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 1.5%). Interest is paid quarterly when using the Index Rate and at the expiration of the LIBOR term selected when using the LIBOR rate; interest varies with the Index Rate or LIBOR rate in effect at the time of the borrowing. The interest rate on December 31, 2005 was 7.06%. The annual fee for the Funded Facility is 2.725% of outstanding Funded Letters of Credit.

F-24

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Effective June 24, 2005, Successor entered into a second lien $275,000,000 term loan and guaranty agreement with a bank and a related party institutional lender (see note 15) with the entire amount outstanding at December 31, 2005. CVR has the option of a 3-month LIBOR rate plus 6.75% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 5.75%). The interest rate on December 31, 2005 was 11.31%. The loan is secured by a second lien on substantially all of CVR’s assets.

The loan and security agreements contain customary restrictive covenants applicable to CVR, including limitations on the level of additional indebtedness, commodity agreements, capital expenditures, payment of dividends, creation of liens, and sale of assets. These covenants also require CVR to maintain specified financial ratios as follows:

Second Lien Credit

First Lien Credit Facility

Facility

Maximum

Minimum Interest

Leverage

Fiscal Quarter Ending

Coverage Ratio

Ratio

March 31, 2006

2.25:1.00

5.00:1.00

5.25:1.00

June 30, 2006

2.25:1.00

5.00:1.00

5.25:1.00

September 30, 2006

2.25:1.00

5.00:1.00

5.25:1.00

December 31, 2006

2.25:1.00

5.00:1.00

5.25:1.00

March 31, 2007

2.25:1.00

4.75:1.00

5.00:1.00

June 30, 2007

2.50:1.00

4.50:1.00

4.75:1.00

September 30, 2007

2.75:1.00

4.25:1.00

4.75:1.00

December 31, 2007

3.00:1.00

3.50:1.00

4.00:1.00

March 31, 2008

3.25:1.00

3.50:1.00

4.00:1.00

June 30, 2008

3.25:1.00

3.75:1.00

September 30, 2008

3.25:1.00

3.00:1.00

3.50:1.00

December 31, 2008

3.25:1.00

2.75:1.00

3.25:1.00

March 31, 2009 and thereafter

3.50:1.00

2.50:1.00

3.00:1.00

Failure to comply with the various restrictive and affirmative covenants of the loan agreements could negatively affect CVR’s ability to incur additional indebtedness and/or pay required distributions. Successor is required to measure its compliance with these financial ratios and covenants quarterly and was in compliance with all covenants and reporting requirements under the terms of the agreement at December 31, 2005. As required by the debt agreements, CVR has entered into interest rate swap agreements (as described in note 14) that are required to be held for a minimum of four years.

Long-term debt consisted of the following at December 31, 2005:


First lien Tranche B term loans; principal payments of .25% of the principal balance due quarterly commencing October 2005, increasing to 23.5% of the principal balance due quarterly commencing October 2011, with a final payment of the aggregate remaining unpaid principal balance due July 2012	$	224,437,500
Second lien term loan, due in full June 2013		275,000,000

		499,437,500
Less current portion		2,235,973

	$	497,201,527

F-25

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Future maturities of long-term debt are as follows:


Year Ending December 31,	Amount

2006	$	2,235,973
2007		2,213,697
2008		2,191,642
2009		2,169,808
2010		2,148,191
Thereafter		488,478,189

	$	499,437,500

At December 31, 2005, Successor had $3.2 million in letters of credit outstanding to collateralize its environmental obligations and state motor fuels tax obligations. The letters of credit expire in July and August 2006. At December 31, 2005, Successor had a $22.6 million letter of credit outstanding to secure the purchase of crude oil. The letter of credit expired January 2006. These letters of credit were outstanding against the Revolving Loan Facility. The fee for the revolving letters of credit is 2.75%.


(11)	Benefit Plans

CVR sponsors two defined-contribution 401(k) plans (the Plans) for all employees. Participants in the Plans may elect to contribute up to 50% of their annual salaries, and up to 100% of their annual income sharing. CVR matches up to 75% of the first 6% of the participant’s contribution for the nonunion plan and 50% of the first 6% of the participant’s contribution for the union plan. Both plans are administered by CVR and contributions for the union plan are determined in accordance with provisions of negotiated labor contracts. Participants in both Plans are immediately vested in their individual contributions. Both Plans have a three year vesting schedule for CVR’s matching funds and contain a provision to count service with any predecessor organization. Successor’s contributions under the Plans were $647,054, $661,922, and $446,753 for the 304 days ended December 31, 2004, the 174 days ended June 23, 2005, and the 233 days ended December 31, 2005, respectively.

Coffeyville Acquisition LLC sponsors share-based compensation plans that participate in profit distributions, as described in note 4.

F-26

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(12)	Income Taxes

Income tax expense (benefit) is summarized below (in thousands):


	Immediate Predecessor					Successor
	304 Days			174 Days		229 Days
	Ended			Ended		Ended
	December 31,			June 23,		December 31,
	2004			2005		2005
Current — Federal	$	27,902		$	26,145	$	29,000
State		6,519			6,099		6,457

		34,421			32,244		35,457

Deferred — Federal		(499	)		3,083		(80,500	)
State		(117	)		721		(17,925	)

		(616	)		3,804		(98,425	)

Total income taxes	$	33,805		$	36,048	$	(62,968	)

Income tax expense differed from the expected income tax (computed by applying the federal income tax rate of 35% to income before income taxes) as follows (in thousands):


	Immediate Predecessor					Successor
	304 Days		174 Days			229 Days
	Ended		Ended			Ended
	December 31,		June 23,			December 31,
	2004		2005			2005
Computed expected taxes	$	29,230	$	30,956		$	(63,744	)
Loss on unexercised option agreements with no tax benefit to Successor		—		—			8,750
State taxes, net of federal benefit		4,162		4,433			(7,454	)
Manufacturing deduction		—		(825	)		(897	)
Other, net		413		1,484			377

Total income tax expense	$	33,805	$	36,048		$	(62,968	)

As more fully described in note 14, the loss on unexercised option agreements of $25,000,000 occurred at Coffeyville Acquisition LLC, and the tax deduction related to the loss was passed through to the partners of Coffeyville Acquisition LLC.

The provision for income taxes for the year ended December 31, 2005 reflects an estimated benefit from a provision of the American Jobs Creation Act of 2004 (“the Act”). The Act created the new Internal Revenue Code section 199 which provides an income tax benefit to domestic manufacturers. The Company recognized an income tax benefit related to this manufacturing deduction of $825,011 and $896,890 for the 174 days ended June 23, 2005 and the 233 days ended December 31, 2005, respectively.

F-27

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The income tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are summarized below (in thousands):


	Immediate
	Predecessor		Successor
	December 31,		December 31,
	2004		2005
Deferred tax assets:
Allowance for doubtful accounts	$	74	$	109
Personnel accruals		342		483
Inventories		215		560
Environmental obligations		166		—
Electricity contract		229		—
Unrealized derivative losses		—		91,226

Deferred tax assets		1,026		92,378

Deferred tax liabilities:
Unrealized derivative gains		326		—
Property, plant, and equipment		84		269,462
Environmental obligations		—		1,238
Other		—		142

Deferred tax liabilities		410		270,842

Net deferred tax assets (liabilities)	$	616	$	(178,464	)

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that CVR will realize the benefits of these deductible differences. Therefore, Successor has not recorded any valuation allowances against deferred tax assets as of December 31, 2004 or 2005.

F-28

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(13)	Commitments and Contingent Liabilities

The minimum required payments for CVR’s lease agreements and unconditional purchase obligations are as follows:


Year Ending	Operating		Unconditional
December 31,	Leases		Purchase Obligations

2006	$	3,654,956	$	22,462,157
2007		3,445,287		22,840,325
2008		3,354,004		18,716,401
2009		2,595,539		18,685,325
2010		1,259,805		16,293,845
Thereafter		644,669		153,877,335

	$	14,954,260	$	252,875,388

CVR leases various equipment and real properties under long-term operating leases. For the year ended December 31, 2003, the 62-day period ended March 2, 2004, the 304-day period ended December 31, 2004, the 174-day period ended June 23, 2005, and the 233-day period ended December 31, 2005, lease expense totaled approximately $2,985,022, $518,918, $2,531,823, $1,754,564, and $1,737,373, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.

CVR licenses a gasification process from a third party associated with gasifier equipment used in the Nitrogen Fertilizer segment. The royalty fees for this license are incurred as the equipment is used and are subject to a cap which is expected to be paid in full by June 2007 at an estimated total cost of $5.5 million. Royalty fee expense reflected in cost of goods sold for the 304-day period ended December 31, 2004, the 174-day period ended June 23, 2005, and the 233-day period ended December 31, 2005 was $1,403,304, $1,042,286, and $914,878, respectively.

Coffeyville Resources Nitrogen Fertilizers LLC (CRNF) has an agreement with the City of Coffeyville pursuant to which it must make a series of future payments for electrical generation transmission and city margin. As of December 31, 2005, the remaining obligations of CRNF totaled $31.8 million through December 31, 2019. Total minimum committed contractual payments under the agreement will be $5.7 million for each of the fiscal years 2006 and 2007 and $1.7 million per year for each subsequent year. Successor is contractually liable for payments to Farmland, as part of deferred purchase consideration related to the electricity contract with the City of Coffeyville. As of December 31, 2005, approximately $750,000 remains to be paid in equal monthly installments of approximately $83,000 each through September 2006.

Coffeyville Resources Refining and Marketing, LLC (CRRM) has a Pipeline Construction, Operation and Transportation Commitment Agreement with Plains Pipeline, L.P. (Plains Pipeline) pursuant to which Plains Pipeline constructed a crude oil pipeline from Cushing, Oklahoma to Caney, Kansas. The term of the agreement is 20 years from when the pipeline became operational on March 1, 2005. Pursuant to the agreement, CRRM must transport approximately 80,000 barrels per day of its crude oil requirements for the Coffeyville refinery at a fixed charge per barrel for the first five years of the agreement. For the final fifteen years of the agreement, CRRM must transport all of its non-gathered crude oil up to the capacity of the Plains Pipeline. The rate is subject to a Federal Energy Regulatory Commission (FERC) tariff and is subject to change on an annual basis per the agreement. Lease expense associated with this agreement and included in cost of goods sold for the

F-29

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

174-day period ended June 23, 2005 and the 233-day period ended December 31, 2005 totaled approximately $2,603,066 and $4,372,115, respectively.

During 1997, Farmland (subsequently assigned to CRRM) entered into an Agreement of Capacity Lease and Operating Agreement with Williams Pipe Line Company (subsequently assigned to Magellan Pipe Line Company (Magellan)) pursuant to which CRRM leases pipeline capacity in certain pipelines between Coffeyville, Kansas and Caney, Kansas and between Coffeyville, Kansas and Independence, Kansas. Pursuant to this agreement, CRRM is obligated to pay a fixed monthly charge to Magellan for annual leased capacity of 6,300,000 barrels until the scheduled expiration of the agreement on April 30, 2007. Lease expense associated with this agreement and included in cost of goods sold for the 174-day period ended June 23, 2005 and the 233-day period ended December 31, 2005 totaled approximately $232,500 and $193,750, respectively.

During 2005, CRRM amended a Pipeline Capacity Lease Agreement with Mid-America Pipeline Company (MAPL) pursuant to which CRRM leases pipeline capacity in an outbound MAPL-operated pipeline between Coffeyville, Kansas and El Dorado, Kansas for the transportation of natural gas liquids (NGLs) and refined petroleum products. Pursuant to this agreement, CRRM is obligated to make fixed monthly lease payments. The agreement also obligates CRRM to reimburse MAPL a portion of certain permitted costs associated with obligations imposed by certain governmental laws. Lease expense associated with this agreement, included in cost of goods sold for the 174-day period ended June 23, 2005 and the 233-day period ended December 31, 2005, totaled approximately $156,271, and $208,316, respectively. The lease expires September 30, 2011.

During 2005, CRRM entered into a Pipeage Contract with MAPL pursuant to which CRRM agreed to ship a minimum quantity of NGLs on an inbound pipeline operated by MAPL between Conway, Kansas and Coffeyville, Kansas. Pursuant to the contract, CRRM is obligated to ship 2,000,000 barrels (Minimum Commitment) of NGLs per year at a fixed rate per barrel through the expiration of the contract on September 30, 2011. All barrels above the Minimum Commitment are at a different fixed rate per barrel. The rates are subject to a tariff approved by the Kansas Corporation Commission (KCC) and are subject to change throughout the term of this contract as ordered by the KCC. Lease expense associated with this contract agreement and included in cost of goods sold for the 233-day period ended December 31, 2005 totaled approximately $172,525.

During 2004, CRRM entered into a Pipeline Capacity Lease Agreement with ONEOK Field Services (OFS) and Frontier El Dorado Refining Company (Frontier) pursuant to which CRRM leases capacity in pipelines operated by OFS between Conway, Kansas and El Dorado, Kansas. Prior to the completion of a planned expansion project specified in the agreement, CRRM will be obligated to pay a fixed monthly charge which will increase after the expansion is complete. The lease expires September 30, 2011. It is estimated the pipeline will be operational in the second quarter of 2006.

During 2004, CRRM entered into a Transportation Services Agreement with CCPS Transportation, LLC (CCPS) pursuant to which CCPS reconfigured an existing pipeline (Spearhead Pipeline) to transport Canadian sourced crude oil to Cushing, Oklahoma. The term of the agreement is 10 years from the time the pipeline becomes operational, which occurred March 1, 2006. Pursuant to the agreement and pursuant to options for increased capacity which CRRM has exercised, CRRM is obligated to pay an incentive tariff, which is a fixed rate per barrel for a minimum of 10,000 barrels per day.

During 2004, CRRM entered into a Terminalling Agreement with Plains Marketing, LP (Plains) whereby CRRM has the exclusive storage rights for working storage, blending, and terminalling services at several Plains tanks in Cushing, Oklahoma. Pursuant to the agreement, CRRM is obligated to pay a minimum throughput volume commitment of 29,200,000 barrels per year. This rate

F-30

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

is subject to change annually based on changes in the Consumer Price Index (CPI-U) and the Producer Price Index (PPI-NG). Expenses associated with this agreement, included in cost of goods sold for the 174-day period ended June 23, 2005 and the 233-day period ended December 31, 2005, totaled approximately $811,815 and $1,251,087, respectively. The agreement expires December 31, 2009.

During 2005 CRNF entered into a on-site product supply agreement with the BOC Group, Inc. Pursuant to the agreement, which expires in 2020, CRNF pays approximately $300,000 per month for the supply of oxygen and nitrogen to the fertilizer operation.

Effective December 31, 2005, a crude oil Supply agreement with Supplier A expired and was replaced by a new crude oil supply agreement with Supplier B (see note 17). Supplier A has initiated discussions with CRRM concerning alleged certain crude oil losses and other charges which Supplier A claims were eligible to be passed through to CRRM under the terms of the expired agreement. Supplier A has not filed a formal claim and CRRM does not believe based on current information that the losses and other charges can be passed through to CRRM. Accordingly, a liability has not been recognized for these losses and other charges as of December 31, 2005.

From time to time, CVR is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, “Environmental, Health, and Safety Matters,” and those described above. Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the company has accrued for losses for which it may ultimately be responsible. It is possible management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements.

Environmental, Health, and Safety (EHS) Matters

CVR is subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries. Such liabilities include estimates of CVR’s share of costs attributable to potentially responsible parties which are insolvent or otherwise unable to pay. All liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.

CVR owns and/or operates manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.

F-31

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$1,209,663 and $1,211,000, respectively, included in other current liabilities. The Immediate Predecessor and Successor accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the Environmental Protection Agency (the EPA) and are discounted at the appropriate risk free rates at December 31, 2004 and 2005, respectively. The accruals include estimated closure and post-closure costs of $1,975,100 and $1,812,000 for two landfills at December 31, 2004 and 2005, respectively. The estimated future payments for these required obligations are as follows (in thousands):


Year Ending December 31,	Amount

2006	$	1,211
2007		1,712
2008		616
2009		508
2010		473
Thereafter		6,798

Undiscounted total		11,318
Less amounts representing interest at 4.51%		3,098

Accrued environmental liabilities at December 31, 2005	$	8,220

CVR has purchased insurance (see note 9) to cover costs above accrued amounts related to this contaminated property. Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

The EPA has issued regulations intended to limit amounts of sulfur in diesel and gasoline. The EPA has granted Original Predecessor’s petition for a technical hardship waiver with respect to the date for compliance in meeting the sulfur-lowering standards. Immediate Predecessor and Successor spent approximately $2 million in 2004 and $27 million in 2005 and, based on information currently available, CVR anticipates spending approximately $83 million in 2006, $2 million in 2007, and $6 million in 2008 to comply with the low-sulfur rules. The entire amounts are expected to be capitalized.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the year ended December 31, 2003, the 62-day period ended March 2, 2004, the 304-day period ended December 31, 2004, the 174-day period ended June 23, 2005, and the 233-day period ended December 31, 2005, capital expenditures were approximately $334,235, $0, $2,563,295, $6,065,713, and $20,165,483, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

CVR believes it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.


(14)	Derivative Financial Instruments

CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the Entities may enter into various derivative transactions. In addition, the Successor, as further described below, entered into certain

F-32

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

commodity derivate contracts and an interest rate swap as required by the long-term debt agreements.

For purposes of these financial statements, CVR has adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS 133). SFAS 133 imposes extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative instruments, such as exchange-traded crude oil futures, certain over-the-counter forward swap agreements, and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives.

At December 31, 2005, Successor’s Petroleum Segment held commodity derivative contracts (swap agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see note 15). The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of the Immediate Predecessor and required under the terms of the long-term debt agreements. The notional quantities on the date of execution were 100,911,000 barrels of crude oil; 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil. The swap agreements were executed at the prevailing market rate at the time of execution and Management believes the swap agreements provide an economic hedge on future transactions. At December 31, 2005 the notional open amounts under the swap agreements were 88,951,000 barrels of crude oil; 2,097,642,750 gallons of unleaded gasoline and 1,638,229,250 gallons of heating oil. At December 31, 2005, these positions resulted in unrealized losses of $235,851,568 using a valuation method that utilizes quoted market prices and assumptions for the estimated forward yield curves of the related commodities in periods when quoted market prices are unavailable. During the 233 days ended December 31, 2005, the Petroleum Segment recorded $59,300,670 in realized losses on these swap agreements.

Successor entered certain crude oil, heating oil, and gasoline option agreements with a related party (see notes 1 and 15) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 233 days ended December 31, 2005.

CVR has recorded margin account balances in cash and cash equivalents of $8,373,417 and $1,540,952 at December 31, 2004 and 2005, respectively. The Petroleum Segment also recorded mark-to-market net gains (losses), exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, in gain (loss) on derivatives of $303,742, $0 , $546,604, $(7,664,725), and $(3,565,153), for the year ended December 31, 2003, the 62-day period ended March 2, 2004, the 304-day period ended December 31, 2004, the 174-day period ended June 23, 2005, and the 233-day period ended December 31, 2005, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.

At December 31, 2005, Successor held derivative contracts known as interest rate swap agreements that converted Successor’s floating-rate bank debt (see note 10) into 3.835% fixed-rate debt on a notional amount of $375,000,000. Half of the agreements are held with a related party (as

F-33

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

described in note 15), and the other half are held with a financial institution that is a lender under CVR’s long-term debt agreements. The swap agreements carry the following terms:


	Notional		Fixed
Period Covered	Amount		Interest Rate

June 30, 2005 to June 30, 2006	$	375 million		3.835	%
June 30, 2006 to June 30, 2007		325 million		4.038	%
June 30, 2007 to March 31, 2008		325 million		4.195	%
March 31, 2008 to March 31, 2009		250 million		4.195	%
March 31, 2009 to March 31, 2010		180 million		4.195	%
March 31, 2010 to June 30, 2010		110 million		4.195	%

CVR pays the fixed rates listed above and receives a floating rate based on three-month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The swap is settled quarterly and marked to market at each reporting date, and all unrealized gains and losses are currently recognized in income. Transactions related to the interest rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments. Mark-to-market net gains on derivatives and quarterly settlements were $7,655,280 for the 233-day period ended December 31, 2005.


(15)	Related Party Transactions

Pegasus Partners II, L.P. (Pegasus) was a majority owner of Immediate Predecessor.

On March 3, 2004, Immediate Predecessor entered into a management services agreement with an affiliate company of Pegasus, Pegasus Capital Advisors, L.P. (Affiliate) pursuant to which Affiliate provided Immediate Predecessor with managerial and advisory services. Amounts totaling approximately $545,000 and $1,000,000 relating to the agreement were expensed in selling, general, and administrative expenses for the 304 days ended December 31, 2004 and for the 174 days ended June 23, 2005, respectively. Immediate Predecessor expensed approximately $455,000 in selling, general and administrative expenses for legal fees paid on behalf of Affiliate in lieu of the remaining amounts owed under the management services agreement for the 304 days ended December 31, 2004.

Immediate Predecessor paid Affiliate a $4.0 million transaction fee upon closing of the Initial Acquisition referred to in note 1. The transaction fee relates to a $2.5 million finder’s fee included in the cost of the Initial Acquisition and $1.5 million in deferred financing costs. The deferred financing cost was subsequently written off in May 2004 as part of the refinancing. In conjunction with the debt refinancing on May 10, 2004, a $1.25 million fee was paid to Affiliate as a deferred financing cost and was subsequently written-off immediately prior to the Subsequent Acquisition.

GS Capital Partners V Fund, L.P. and related entities (GS or Goldman Sachs Funds) and Kelso Investment Associates VII, L.P. and related entity (Kelso or Kelso Funds) are majority owners of Successor.

Successor paid companies related to GS and Kelso each equal amounts totaling $6.0 million for transaction fees related to the Subsequent Acquisition, as well as an additional $0.7 million paid to GS for reimbursed expenses related to the Subsequent Acquisition. These expenditures were included in the cost of the Subsequent Acquisition referred to in note 1.

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CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

An affiliate of GS is one of the lenders in conjunction with the financing of the Subsequent Acquisition. Successor paid this affiliate of GS a $22.1 million fee included in deferred financing costs. For the 233 days ended December 31, 2005, Successor made interest payments of $1.8 million recorded in interest expense and paid letter of credit fees of approximately $155,000 recorded in selling, general, and administrative expenses, to this affiliate of GS.

On June 24, 2005, Successor entered into a management services agreement with GS and Kelso pursuant to which GS and Kelso provide Successor with managerial and advisory services. In consideration for these services, an annual fee of $1.0 million each is paid to GS and Kelso, plus reimbursement for any out-of-pocket expenses. The agreement has a term ending on the date GS and Kelso cease to own any interests in Successor. Relating to the agreement, $1,310,416 was expensed in selling, general, and administrative expenses for the 233 days ended December 31, 2005. In addition, $1,046,575 was included in other current liabilities and approximately $78,671 was included in accounts payable at December 31, 2005.

Successor entered into certain crude oil, heating oil, and gasoline swap agreements with a subsidiary of GS. The original swap agreements were entered into on May 16, 2005 and were terminated on June 16, 2005, resulting in a $25 million loss on termination of swap agreements for the 233 days ended December 31, 2005. Additional swap agreements with this subsidiary of GS were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in note 14). Amounts totaling $297,010,762 were expensed related to these swap agreements for the 233 days ended December 31, 2005 and are reflected in loss on derivatives. In addition, the consolidated balance sheet at December 31, 2005 includes liabilities of $96,688,956 included in current payable to swap counterparty and $160,033,333 included in long-term payable to swap counterparty.

On June 30, 2005, Successor entered into three interest-rate swap agreements with the same subsidiary of GS (as described in note 14). Amounts totaling $3,826,342 of income were recognized related to these swap agreements for the 233 days ended December 31, 2005 and are reflected in gain (loss) on derivatives. In addition, the consolidated balance sheet at December 31, 2005 includes $1,441,697 in prepaid expenses and other current assets and $2,441,216 in other long-term assets related to the same agreements.

Effective December 30, 2005, Successor entered into a crude oil supply agreement with a subsidiary of GS (Supplier). This agreement replaces a similar contract held with an independent party (see note 17). Both parties will negotiate the cost of each barrel of crude oil to be purchased from a third party. Successor will pay Supplier a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is adjusted further using a spread adjustment calculation based on the time period the crude oil is estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The monthly spread quantity for any delivery month at any time shall not exceed approximately 3.1 million barrels. The initial term of the agreement is to December 31, 2006 and it continues for one additional year unless either party terminates it effective December 31, 2006. $1,290,731 was recorded on the consolidated balance sheet at December 31, 2005 in prepaid expenses and other current assets for prepayment of crude oil.


(16)	Business Segments

CVR measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in Statement of Financial Accounting Standards No. 131, Disclosures About Segments of an Enterprise and Related Information.

F-35

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Petroleum

Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products including coke. CVR uses the coke in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For CVR, a $15-per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of goods sold for the Nitrogen Fertilizer Segment. The intercompany transactions are eliminated in the Other Segment. For Original Predecessor, the coke was transferred from the Petroleum Segment to the Nitrogen Fertilizer Segment at zero value such that no sales revenue on the part of the Petroleum Segment or corresponding cost of goods sold for the Nitrogen Fertilizer Segment was recorded. Because Original Predecessor did not record these transfers in its segment results and the information to restate these segment results in Original Predecessor periods is not available, financial results from those periods have not been restated. As a result, the results of operations for Original Predecessor periods are not comparable with those of Immediate Predecessor or Successor periods.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Nitrogen fertilizer sales increased throughout the periods presented as the on stream factor improved.

Other Segment

The Other Segment reflects intercompany eliminations, cash and cash equivalents, all debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments.


	Original Predecessor				Immediate Predecessor						Successor
	Year		62-Day Period		304-Day Period			174-Day Period			233-Day Period
	Ended		Ended		Ended			Ended			Ended
	December 31,		March 2,		December 31,			June 23,			December 31,
	2003		2004		2004			2005			2005
Net sales
Petroleum	$	1,161,287,249	$	241,640,365	$	1,390,768,126		$	903,802,983		$	1,363,390,142
Nitrogen Fertilizer		100,909,645		19,446,164		93,422,503			79,347,843			93,651,855
Other		—		—		(4,297,440	)		(2,444,565	)		(2,782,455	)

Total	$	1,262,196,894	$	261,086,529	$	1,479,893,189		$	980,706,261		$	1,454,259,542

Depreciation and amortization
Petroleum	$	2,094,627	$	271,284	$	1,522,464		$	770,728		$	15,566,987
Nitrogen Fertilizer		1,218,899		160,719		855,289			316,446			8,360,911
Other		—		—		68,208			40,831			26,133

Total	$	3,313,526	$	432,003	$	2,445,961		$	1,128,005		$	23,954,031

Operating income (loss)
Petroleum	$	21,544,374	$	7,687,745	$	77,094,034		$	76,654,428		$	123,044,854
Nitrogen Fertilizer		7,813,708		3,514,997		22,874,227			35,267,752			35,731,056
Other		—		—		3,076			333,514			(240,848	)

Total	$	29,358,082	$	11,202,742	$	99,971,337		$	112,255,694		$	158,535,062

F-36

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Original Predecessor				Immediate Predecessor					Successor
	Year		62-Day Period		304-Day Period			174-Day Period		233-Day Period
	Ended		Ended		Ended			Ended		Ended
	December 31,		March 2,		December 31,			June 23,		December 31,
	2003		2004		2004			2005		2005
Capital expenditures
Petroleum	$	489,083	$	—	$	11,267,244		$	10,790,042	$	42,107,751
Nitrogen fertilizer		324,679		—		2,697,852			1,434,921		2,017,385
Other		—		—		195,184			31,830		1,046,998

Total	$	813,762	$	—	$	14,160,280		$	12,256,793	$	45,172,134

Reorganization expenses —
Impairment of property, plant, and equipment
Petroleum	$	3,950,519	$	—	$	—		$	—	$	—
Nitrogen fertilizer		5,688,107		—		—			—		—
Other		—		—		—			—		—

Total	$	9,638,626	$	—	$	—		$	—	$	—

Total assets
Petroleum					$	145,861,715				$	664,870,240
Nitrogen Fertilizer						83,561,149					425,333,621
Other						(265,527	)				131,344,042

Total					$	229,157,337				$	1,221,547,903

Goodwill
Petroleum					$	—				$	42,806,422
Nitrogen Fertilizer						—					40,968,463
Other						—					—

Total					$	—				$	83,774,885

F-37

CVR Energy, Inc. and Subsidiaries

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(17)	Major Customers and Suppliers

Sales to major customers were as follows:


	Original Predecessor						Immediate Predecessor						Successor
	Year			62-Day Period			304-Day Period			174-Day Period			233-Day Period
	Ended			Ended			Ended			Ended			Ended
	December 31,			March 2,			December 31,			June 23,			December 31,
	2003			2004			2004			2005			2005
Petroleum
Customer A		89	%		10	%		18	%		17	%		16	%
Customer B		3	%		25	%		10	%		5	%		6	%
Customer C		1	%		18	%		17	%		17	%		15	%
Customer D		—			—			8	%		14	%		17	%
Customer E		1	%		9	%		15	%		11	%		11	%

		94	%		62	%		68	%		64	%		65	%

Nitrogen Fertilizer
Customer F		66	%		48	%		24	%		16	%		10	%
Customer G		0	%		0	%		5	%		9	%		10	%

		66	%		48	%		29	%		25	%		20	%

The Petroleum Segment maintains long-term contracts with one supplier for the purchase of its crude oil. The agreement with Supplier A expired in December 2005, at which time Successor entered into a similar arrangement with Supplier B, a related party (as described in note 15). Purchases contracted as a percentage of the total cost of goods sold for each of the periods were as follows:

Original Predecessor

Immediate Predecessor

Successor

Year

62-Day Period

304-Day Period

174-Day Period

233-Day Period

Ended

December 31,

March 2,

December 31,

June 23,

December 31,

2003

2004

2005

Supplier A

The Nitrogen Fertilizer Segment maintains long-term contracts with one supplier. Purchases from this supplier as a percentage of the total cost of goods sold were as follows:

Original Predecessor

Immediate Predecessor

Successor

Year

62-Day Period

304-Day Period

174-Day Period

233-Day Period

Ended

December 31,

March 2,

December 31,

June 23,

December 31,

2003

2004

2005

Supplier

F-38

CVR Energy, Inc. and Subsidiaries

CONDENSED CONSOLIDATED BALANCE SHEET


						Pro Forma
	Successor			Successor		Successor
	December 31,			September 30,		September 30,
	2005			2006		2006
				(unaudited)		(unaudited)
						(Note 3)

ASSETS
Current assets:
Cash and cash equivalents	$	64,703,524		$	38,085,502	$	—
Accounts receivable, net of allowance for doubtful accounts of $275,188 and $277,852, respectively		71,560,052			48,407,925
Inventories		154,275,818			214,058,461
Income tax receivable		—			11,786,287
Prepaid expenses and other current assets		14,709,309			31,104,515
Deferred income taxes		31,059,748			17,271,108

Total current assets		336,308,451			360,713,798		—
Property, plant, and equipment, net of accumulated depreciation		772,512,884			928,152,935
Intangible assets		1,008,547			730,979
Goodwill		83,774,885			83,774,885
Deferred financing costs		19,524,839			17,027,193
Other long-term assets		8,418,297			7,253,308

Total assets	$	1,221,547,903		$	1,397,653,098	$	—


LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	2,235,973		$	2,219,245	$	—
Accounts payable		87,914,833			107,729,484
Personnel accruals		10,796,896			9,891,357
Accrued taxes other than income taxes		4,841,234			2,331,067
Accrued income taxes		4,939,614			—
Payable to swap counterparty		96,688,956			54,633,859
Deferred revenue		12,029,987			5,365,673
Other current liabilities		8,831,937			5,176,125

Total current liabilities		228,279,430			187,346,810		—
Long-term liabilities:
Long-term debt, less current portion		497,201,527			525,539,179
Accrued environmental liabilities		7,009,388			5,628,547
Deferred income taxes		209,523,747			253,338,137
Payable to swap counterparty		160,033,333			113,630,301

Total long-term liabilities		873,767,995			898,136,164		—
Management voting common units subject to redemption, 227,500 units issued and outstanding		4,172,350			9,020,375
Less: note receivable from management unitholder		(500,000	)		—

Total management voting common units subject to redemption, net		3,672,350			12,156,269		—
Members’ equity:
Voting common units, 25,588,500 units issued and outstanding		114,830,560			300,778,557
Management nonvoting override units, 2,758,895 units outstanding		997,568			2,371,192

Total members’ equity		115,828,128			303,149,749		—

PRO FORMA STOCKHOLDERS’ EQUITY
Stockholders’ equity:
Common stock, $0.01 par value, shares authorized; shares issued and outstanding
Additional paid-in capital
Retained earnings
Total pro forma stockholders’ equity
Commitments and contingencies

Total liabilities and equity	$	1,221,547,903		$	1,397,653,098	$	—

See accompanying notes to condensed consolidated financial statements.

F-39

CVR Energy, Inc. and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS


	Immediate
	Predecessor			Successor
	174 Days Ended			141 Days Ended			Nine Months Ended
	June 23,			September 30,			September 30,
	2005			2005			2006
				(unaudited)			(unaudited)
Net sales	$	980,706,261		$	776,628,260		$	2,329,152,871
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		768,067,178			624,862,774			1,848,076,557
Direct operating expenses (exclusive of depreciation and amortization)		80,913,862			36,674,930			144,461,227
Selling, general and administrative expenses (exclusive of depreciation and amortization)		18,341,522			7,415,773			32,796,414
Depreciation and amortization		1,128,005			11,924,349			36,809,644

Total operating costs and expenses		868,450,567			680,877,826			2,062,143,842

Operating income		112,255,694			95,750,434			267,009,029
Other income (expense):
Interest expense		(7,801,821	)		(12,236,014	)		(33,016,684	)
Interest income		511,687			181,341			2,773,949
Gain (loss) on derivatives		(7,664,725	)		(487,045,767	)		44,746,853
Loss on extinguishment of debt		(8,093,754	)		—			—
Other income (expense), net		(762,616	)		10,341			310,704

Total other income (expense)		(23,811,229	)		(499,090,099	)		14,814,822

Income (loss) before provision for income taxes		88,444,465			(403,339,665	)		281,823,851
Income tax expense (benefit)		36,047,516			(150,773,609	)		111,027,829

Net income (loss)	$	52,396,949		$	(252,566,056	)	$	170,796,022

Unaudited Pro Forma Information (Note 3)
Basic and diluted earnings per common share							$	—
Basic and diluted weighted average common shares outstanding								—

See accompanying notes to condensed consolidated financial statements.

F-40

CVR Energy, Inc. and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF EQUITY

(unaudited)


	Management Voting
	Common
	Units Subject to				Note Receivable
	Redemption				from Management			Total
	Units		Dollars		Unit Holder			Dollars

For the nine months ended September 30, 2006
Balance at December 31, 2005		227,500	$	4,172,350	$	(500,000	)	$	3,672,350
Payment of note receivable				—		150,000			150,000
Forgiveness of note receivable						350,000			350,000
Adjustment to fair value for management common units				3,342,908		—			3,342,908
Net income allocated to management common units				1,505,117		—			1,505,117

Balance at September 30, 2006		227,500	$	9,020,375	$	—		$	9,020,375


						Management				Management
						Nonvoting Override				Nonvoting Override
	Voting Common Units					Operating Units				Value Units				Total
	Units		Dollars			Units		Dollars		Units		Dollars		Dollars

For the nine months ended September 30, 2006
Balance at December 31, 2005		23,588,500	$	114,830,560			919,630	$	602,381		1,839,265	$	395,187	$	115,828,128
Issuance of 2,000,000 common units for cash		2,000,000		20,000,000					—				—		20,000,000
Recognition of share-based compensation expense related to override units				—					865,527				508,097		1,373,624
Adjustment to fair value for management common units				(3,342,908	)				—				—		(3,342,908	)
Net income allocated to common units				169,290,905			—		—				—		169,290,905

Balance at September 30, 2006		25,588,500	$	300,778,557			919,630	$	1,467,908		1,839,265	$	903,284	$	303,149,749

See accompanying notes to condensed consolidated financial statements.

F-41

CVR Energy, Inc. and Subsidiaries

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Immediate
	Predecessor			Successor
	174 Days Ended			141 Days Ended			Nine Months Ended
	June 23,			September 30,			September 30,
	2005			2005			2006
				(unaudited)			(unaudited)
Cash flows from operating activities:
Net income (loss)	$	52,396,949		$	(252,566,056	)	$	170,796,022
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		1,128,005			11,924,349			36,809,644
Provision for doubtful accounts		(190,468	)		285,514			2,664
Amortization of deferred financing costs		812,166			896,640			2,508,847
Loss on extinguishment of debt		8,093,754			—			—
Loss on disposition of fixed assets		—			—			1,188,360
Forgiveness of note receivable		—			—			350,000
Share-based compensation		3,985,991			536,523			1,373,624
Changes in assets and liabilities, net of effect of acquisition:
Accounts receivable		(11,334,177	)		(13,024,860	)		23,149,463
Inventories		(59,045,550	)		15,046,799			(59,782,643	)
Prepaid expenses and other current assets		(937,543	)		(3,105,606	)		(16,537,977	)
Other long-term assets		3,036,659			(3,729,006	)		1,081,470
Accounts payable		16,124,794			2,544,442			(380,356	)
Accrued income taxes		4,503,574			4,088,672			(16,725,901	)
Deferred revenue		(9,073,050	)		5,066,510			(6,664,314	)
Other current liabilities		1,254,196			5,298,237			(7,071,516	)
Payable to swap counterparty		—			466,661,429			(88,458,131	)
Accrued environmental liabilities		(1,553,184	)		(791,259	)		(1,380,841	)
Other long-term liabilities		(297,105	)		(216,335	)		—
Deferred income taxes		3,803,937			(175,605,857	)		57,603,030

Net cash provided by operating activities		12,708,948			63,310,136			97,861,445

Cash flows from investing activities:
Cash paid for acquisition of Immediate Predecessor, net of cash acquired		—			(685,125,669	)		—
Capital expenditures		(12,256,793	)		(12,056,423	)		(172,950,391	)

Net cash used in investing activities		(12,256,793	)		(697,182,092	)		(172,950,391	)

Cash flows from financing activities:
Revolving debt payments		(343,449	)		(69,286,016	)		—
Revolving debt borrowings		492,308			69,286,016			—
Proceeds from issuance of long-term debt		—			500,000,000			30,000,000
Principal payments on long-term debt		(375,000	)		—			(1,679,076	)
Payment of deferred financing costs		—			(24,436,970	)		—
Issuance of members’ equity		—			237,660,000			20,000,000
Payment of note receivable		—			—			150,000
Distribution of members’ equity		(52,211,493	)		—			—

Net cash provided by (used in) financing activities		(52,437,634	)		713,223,030			48,470,924

Net increase (decrease) in cash and cash equivalents		(51,985,479	)		79,351,074			(26,618,022	)
Cash and cash equivalents, beginning of period		52,651,952			—			64,703,524

Cash and cash equivalents, end of period	$	666,473		$	79,351,074		$	38,085,502

Supplemental disclosures
Cash paid for income taxes	$	27,040,000		$	20,743,577		$	70,150,700
Cash paid for interest	$	7,287,351		$	10,993,563		$	38,229,085
Non-cash investing and financing activities:
Accrual of construction in progress additions	$	—		$	—		$	20,195,007
Contributed capital through Leiber tax savings	$	728,724		$	—		$	—

See accompanying notes to condensed consolidated financial statements.

F-42

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

(1) Basis of Presentation

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and in accordance with the rules and regulations of the Securities and Exchange Commission. The consolidated financial statements include the accounts of CVR Energy, Inc. and its subsidiaries (CVR or the Company). All significant intercompany accounts and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under U.S. generally accepted accounting principles have not been included pursuant to such rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2005 audited financial statements and notes thereto of CVR.

In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position as of December 31, 2005 and September 30, 2006, and the results of operations and cash flows for the 174 days ended June 23, 2005, the 141 days ended September 30, 2005 and the nine months ended September 30, 2006.

Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 2006 or any other interim period. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affected the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

(2) Organization and Nature of Business and the Acquisitions

General

On June 24, 2005, Coffeyville Acquisition LLC and subsidiaries (Successor) acquired all of the outstanding stock of Coffeyville Refining & Marketing, Inc. (CRM); Coffeyville Nitrogen Fertilizers, Inc. (CNF); Coffeyville Crude Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and Coffeyville Terminal, Inc. (CT) (collectively, CRIncs) from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). Immediate Predecessor was a Delaware limited liability company formed in October 2003. As a result of this transaction, CRIncs ownership increased to 100% of CL JV Holdings, LLC (CLJV), a Delaware limited liability company formed on September 27, 2004. CRIncs directly and indirectly, through CLJV, collectively own 100% of Coffeyville Resources, LLC (CRLLC) and its wholly owned subsidiaries, Coffeyville Resources Refining & Marketing, LLC (CRRM); Coffeyville Resources Nitrogen Fertilizers, LLC (CRNF); Coffeyville Resources Crude Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC (CRP); and Coffeyville Resources Terminal, LLC (CRT).

F-43

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

Successor had no financial statement activity during the period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil, and gasoline option agreements entered into with a related party (see notes 7 and 8) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying condensed consolidated statements of operations as loss on derivatives for the 141 days ended September 30, 2005.

Since the assets and liabilities of Successor are each presented on a different cost basis than that for the period before the acquisition, the financial information for Successor and Immediate Predecessor are not comparable.

The Subsequent Acquisition

On May 15, 2005, Successor and Immediate Predecessor entered into an agreement whereby Successor acquired 100% of the outstanding stock of CRIncs with an effective date of June 24, 2005 for $673,273,440, including the assumption of $353,084,637 of liabilities. Successor also paid transaction costs of $12,518,702, which consisted of legal, accounting, and advisory fees of $5,782,740 paid to various parties, and transaction fees of $6,000,000 and $735,962 in expenses related to the acquisition paid to institutional investors (see note 8). Successor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Subsequent Acquisition was financed through long-term borrowings of approximately $500 million, short-term borrowings of approximately $12.6 million, and the issuance of common units for approximately $227.7 million. The allocation of the purchase price at June 24, 2005, the date of the Subsequent Acquisition, is as follows:


Assets acquired
Cash	$	666,473
Accounts receivable		37,328,997
Inventories		156,171,291
Prepaid expenses and other current assets		4,865,241
Intangibles, contractual agreements		1,322,000
Goodwill		83,774,885
Other long-term assets		3,837,647
Property, plant, and equipment		750,910,245

Total assets acquired	$	1,038,876,779

Liabilities assumed
Accounts payable	$	47,259,070
Other current liabilities		16,017,210
Current income taxes		5,076,012
Deferred income taxes		276,888,816
Other long-term liabilities		7,843,529

Total liabilities assumed	$	353,084,637

Cash paid for acquisition of Immediate Predecessor	$	685,792,142

F-44

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

Pro forma revenue would be unchanged for the periods presented. Unaudited pro forma net income (loss) as if the Subsequent Acquisition and subsequent debt refinancing had occurred on January 1, 2005 compared to historical net income presented below is as follows (in thousands):

Immediate Predecessor

Successor

Pro Forma

174 Days Ended

141 Days Ended

Nine Months Ended

June 23,

September 30,

2005

Net Income (loss)

52,397

252,566

)

216,657

)

(3) Unaudited Pro Forma Information

Earnings per share is calculated on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering with respect to the existing shares. Pro forma earnings per share assumes that in conjunction with the initial public offering, the two direct wholly owned subsidiaries of Successor will merge with two of CVR’s direct wholly owned subsidiaries, CVR will effect a -for- stock split prior to the completion of this offering, and CVR will issue shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering pursuant to the exercise by the underwriters of their opinion. The pro forma balance sheet assumes the transactions noted above occurred on September 30, 2006.

(4) Members’ Equity

CVR accounts for changes in the redemption value of the management voting common units in the period the changes occur and adjusts the carrying value of the Capital Subject to Redemption to equal the redemption value at the end of each reporting period with an equal and offsetting adjustment to Members’ Equity. None of the Capital Subject to Redemption was redeemable at December 31, 2005 or September 30, 2006.

At September 30, 2006, the Capital Subject to Redemption was revalued through an independent appraisal process, and the value was determined to be $39.65 per unit. Accordingly, the carrying value of the Capital Subject to Redemption increased by $3,342,908 for the nine month period ended September 30, 2006 with an equal and offsetting decrease to Members’ Equity.

919,630 override operating units at a benchmark value of $10 per unit

In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,604,950. Pursuant to the forfeiture schedule described below, the Company is recognizing compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in-substance, multiple awards. Compensation expense for the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005 and nine months ending

F-45

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

September 30, 2006 were $0, $310,702 and $865,527, respectively. Significant assumptions used in the valuation were as follows:


• Estimated forfeiture rate		None
• Explicit service period		Based on forfeiture schedule below
• Grant-date fair value — controlling basis		$5.16 per share
• Marketability and minority interest discounts		$1.24 per share (24% discount)
• Volatility		37%


Minimum
Period	Forfeiture
Held	Percentage

2 years		75%
3 years		50%
4 years		25%
5 years		0%

On the tenth anniversary of the issuance of override operating units, such units shall convert into an equivalent number of override value units.

1,839,265 override value units at a benchmark value of $10 per unit

In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override value units on June 24, 2005 was $4,064,776. For the override value units, CVR is recognizing compensation expense ratably over the implied service period of 6 years. Compensation expense for the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005 and nine months ended September 30, 2006 were $0, $225,821 and $508,907, respectively. Significant assumptions used in the valuation were as follows:


• Estimated forfeiture rate		None
• Derived service period		6 years
• Grant-date fair value — controlling basis		$2.91 per share
• Marketability and minority interest discounts		$0.70 per share (24% discount)
• Volatility		37%

F-46

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

value units is the product of 1) the number of issued override value units and 2) the fraction, the numerator of which is the Current Common Value minus two times original contributed capital, and the denominator of which is two times the original contributed capital. Distributions to participating override value units will be reduced until the total cumulative reductions are equal to the benchmark value. On the tenth anniversary of any override value unit (including any override value unit issued on the conversion of an override operating unit) the “two times” threshold referenced above will become “10 times” and the “four times” threshold referenced above will become “12 times”. Unless the compensation committee of the board of directors takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:


Minimum	Subject to
Period	Forfeiture
Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

Successor, through a wholly-owned subsidiary, has a Phantom Unit Appreciation Plan whereby directors, employees, and service providers may be awarded phantom points at the discretion of the board of directors or the compensation committee. Holders of service phantom points have rights to receive distributions when holders of override operating units receive distributions. Holders of performance phantom points have rights to receive distributions when holders of override value units receive distributions. There are no other rights or guarantees, and the plan expires on July 25, 2015, or at the discretion of the compensation committee of the board of directors. The total combined interest of the Phantom Unit Plan and the override units (combined Profits Interest) cannot exceed 15% of the notional and aggregate equity interests of the Company. As of September 30, 2006, the issued Profits Interest represented 11.55% of combined common unit interest and Profits Interest of the Company. The Profits Interest was comprised of 9.46% and 2.09% of override interest and phantom interest, respectively. In accordance with SFAS 123(R), using the Binomial Option Pricing Model as a method of valuation through an independent valuation process, the service phantom interest was valued at $6.53 per point and the performance phantom interest was valued at $5.10 per point. We have recorded $995,515 in personnel accruals as of September 30, 2006. Compensation expense for the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005 and nine month period ended September 30, 2006 related to the Phantom Unit Plan was $0, $51,104 and $900,496, respectively.

(5) Inventories

F-47

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

Inventories consisted of the following (in thousands):


	Successor
	December 31,		September 30,
	2005		2006
			(Unaudited)

Finished goods	$	58,513	$	63,042
Raw materials and catalysts		47,437		70,398
In-process inventories		33,397		56,610
Parts and supplies		14,929		24,008

	$	154,276	$	214,058

(6) Commitments and Contingent Liabilities

The minimum required payments for Successor’s lease agreements and unconditional purchase obligations are as follows:


	Operating		Unconditional
	Leases		Purchase Obligations

Three months ending December 31, 2006	$	869,068	$	6,616,246
Year ending December 31, 2007		3,751,500		24,811,345
Year ending December 31, 2008		3,645,218		20,566,369
Year ending December 31, 2009		2,899,193		20,533,845
Year ending December 31, 2010		1,596,818		18,142,365
Year ending December 31, 2011		857,494		16,272,447
Thereafter		108,063		145,315,392

	$	13,727,354	$	252,258,009

CVR leases various equipment and real properties under long-term operating leases. For the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005, and the nine month period ended September 30, 2006, lease expense totaled approximately $1,754,564, $840,815, and $2,823,689, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.

From time to time, CVR is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, “Environmental, Health, and Safety Matters”. Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the company has accrued for losses for which it may ultimately be responsible. It is possible management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements.

F-48

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

Environmental, Health, and Safety (EHS) Matters

CVR is subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries. Such liabilities include estimates of the Company’s share of costs attributable to potentially responsible parties which are insolvent or otherwise unable to pay. All liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.

Through an Administrative Order issued to Original Predecessor under the Resource Conservation and Recovery Act, as amended (RCRA), CVR is a potential party responsible for conducting corrective actions at its Coffeyville, Kansas and Phillipsburg, Kansas facilities. In 2005, Coffeyville Resources Nitrogen Fertilizers, LLC agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (VCPRP) to address a reported release of urea ammonium nitrate (UAN) at the Coffeyville UAN loading rack. As of December 31, 2005 and September 30, 2006, environmental accruals of $8,220,338 and $7,447,138, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Order and the VCPRP, including amounts totaling $1,211,000 and $1,818,591, respectively, included in other current liabilities. The Immediate Predecessor and Successor accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the Environmental Protection Agency (the EPA) and are discounted at the appropriate risk free rates at December 31, 2005 and September 30, 2006, respectively. The accruals include estimated closure and post-closure costs of $1,812,000 and $1,732,000 for two landfills at December 31, 2005 and September 30, 2006, respectively. The estimated future payments for these required obligations are as follows (in thousands):


	Amount

Three months ending December 31, 2006	$	347
Year ending December 31, 2007		1,737
Year ending December 31, 2008		904
Year ending December 31, 2009		493
Year ending December 31, 2010		341
Year ending December 31, 2011		341
Thereafter		6,001

Undiscounted total		10,164
Less amounts representing interest at 4.72%		2,717

Accrued environmental liabilities at September 30, 2006	$	7,447

Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.

F-49

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

The EPA has issued regulations intended to limit amounts of sulfur in diesel and gasoline. The EPA has granted the Company a petition for a technical hardship waiver with respect to the date for compliance in meeting the sulfur-lowering standards. CVR has spent approximately $2 million in 2004, $27 million in 2005, $68 million in the first nine months of 2006 and, based on information currently available, anticipates spending approximately $28 million in the last three months of 2006, $1 million in 2007, and $25 million between 2008 and 2010 to comply with the low-sulfur rules. The entire amounts are expected to be capitalized.

Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005, and the nine month period ended September 30, 2006, capital expenditures were approximately $6,065,713, $6,639,891 and $75,217,059, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.

(7) Derivative Financial Instruments

CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR may enter into various derivative transactions. In addition, the Successor, as further described below, entered into certain commodity derivate contracts and an interest rate swap as required by the long-term debt agreements.

CVR has adopted Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS 133). SFAS 133 imposes extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative instruments, such as exchange-traded crude oil futures, certain over-the-counter forward swap agreements, and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives.

At September 30, 2006, Successor’s Petroleum Segment held commodity derivative contracts (swap agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see note 8). The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of the Immediate Predecessor and required under the terms of the long-term debt agreements. The notional quantities on the date of execution were 100,911,000 barrels of crude oil; 1,889,459,250 gallons of heating oil and 2,348,802,750 gallons of unleaded gasoline. The swap agreements were executed at the prevailing market rate at the time of execution and Management believes the swap agreements provide an economic hedge on future transactions. At September 30, 2006 the notional open amounts under the swap agreements were 71,206,000 barrels of crude oil; 1,495,326,000 gallons of heating oil and 1,495,326,000 gallons of unleaded gasoline. These positions resulted in unrealized gains (losses) for the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005 and the nine months ended September 30, 2006 of $0, $(427,061,117) and $80,322,487 using a valuation method that utilizes quoted market prices and assumptions for the estimated forward yield curves of the related commodities in periods when quoted market prices are unavailable. The Petroleum Segment recorded $0, $38,137,450 and $46,147,786 in realized losses on

F-50

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

these swap agreements for the 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005 and the nine months ended September 30, 2006.

Successor entered certain crude oil, heating oil, and gasoline option agreements with a related party (see notes 1 and 8) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 141 days ended September 30, 2005.

CVR has recorded margin account balances in cash and cash equivalents of $1,540,952 and $8,353,933 at December 31, 2005 and September 30, 2006, respectively. The Petroleum Segment also recorded mark-to-market net gains (losses), exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, in gain (loss) on derivatives of $(7,664,725), $(2,275,848), and $7,676,963, for 174-day period ended June 23, 2005, the 141-day period ended September 30, 2005, and the nine month period ended September 30, 2006, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.

At September 30, 2006, Successor held derivative contracts known as interest rate swap agreements that converted Successor’s floating-rate bank debt into 4.038% fixed-rate debt on a notional amount of $375,000,000. Half of the agreements are held with a related party (as described in note 8), and the other half are held with a financial institution that is a lender under the Successor’s long-term debt agreements. The swap agreements carry the following terms:


	Notional		Fixed
Period Covered	Amount		Interest Rate

September 30, 2006 to March 31, 2007		375 million		4.038%
March 31, 2007 to June 30, 2007		325 million		4.038%
June 30, 2007 to March 31, 2008		325 million		4.195%
March 31, 2008 to March 31, 2009		250 million		4.195%
March 31, 2009 to March 31, 2010		180 million		4.195%
March 31, 2010 to June 30, 2010		110 million		4.195%

Successor pays the fixed rates listed above and receives a floating rate based on three-month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The swap is settled quarterly and marked to market at each reporting date, and all unrealized gains and losses are currently recognized in income. Transactions related to the interest rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments. Mark-to-market net gains on derivatives and quarterly settlements were $5,428,648 and $2,895,189 for the 141-day period ended September 30, 2005 and the nine month period ended September 30, 2006.

(8) Related Party Transactions

GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates VII, L.P. and related entity (Kelso) are majority owners of Successor.

F-51

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

reimbursement for any out-of-pocket expenses. The agreement has a term ending on the date GS and Kelso cease to own any interests in Successor. Relating to the agreement, $542,465 and $1,566,890 was expensed in selling, general, and administrative expenses for the 141 days ended September 30, 2005 and the nine month period ended September 30, 2006, respectively. In addition, $1,046,575 was included in other current liabilities and approximately $78,671 was included in accounts payable at December 31, 2005. $504,110 was included in prepaid expenses and other current assets at September 30, 2006.

Successor entered into certain crude oil, heating oil, and gasoline swap agreements with a subsidiary of GS. The original swap agreements were entered into on May 16, 2005 and were terminated on June 16, 2005, resulting in a $25 million loss on termination of swap agreements for the 233 days ended December 31, 2005. Additional swap agreements with this subsidiary of GS were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in note 7). Amounts totaling $(467,885,141) and $34,174,701 were recognized related to these swap agreements for the 141 days ended September 30, 2005 and the nine month period ended September 30, 2006, respectively, and are reflected in gain (loss) on derivatives. In addition, the consolidated balance sheet at December 31, 2005 and September 30, 2006 includes liabilities of $96,688,956 and $54,633,859 included in current payable to swap counterparty and $160,033,333 and $113,630,301 included in long-term payable to swap counterparty. During the 141 days ended September 30, 2005 and nine month period ended September 30, 2006, losses of $38,137,050 and $46,147,786 were realized on these swap agreements.

Effective December 30, 2005, Successor entered into a crude oil supply agreement with a subsidiary of GS (Supplier). This agreement replaces a similar contract held with an independent party (see note 10). Both parties will negotiate the cost of each barrel of crude oil to be purchased from a third party. Successor will pay Supplier a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is adjusted further using a spread adjustment calculation based on the time period the crude oil is estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The monthly spread quantity for any delivery month at any time shall not exceed approximately 3.1 million barrels. The initial term of the agreement is to December 31, 2006. $1,290,731 and $2,185,000 were recorded on the consolidated balance sheet at December 31, 2005 and September 30, 2006, respectively, in prepaid expenses and other current assets for prepayment of crude oil. Approximately $28,564,336 and $6,312,928 were recorded in Inventory and Accounts Payable at September 30, 2006. Expenses associated with this agreement, included in cost of goods sold for the nine month period ended September 30, 2006 totaled approximately $1,230,270,562.

The Company had a note receivable with an executive member of management. During the period ended September 30, 2006, the board of directors approved to forgive the note receivable and related accrued interest receivable. The balance of the note receivable forgiven was $350,000. Accrued interest receivable forgiven was approximately $17,989. The total amount was charged to compensation expense.

(9) Business Segments

F-52

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

Petroleum

Nitrogen Fertilizer

The principal products of the Nitrogen Fertilizer Segment are anhydrous ammonia and urea ammonia nitrate solution (UAN).

Other Segment

F-53

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)


	Immediate Predecessor			Successor
	174-Day Period			141-Day Period			Nine Months
	Ended			Ended			Ended
	June 23,			September 30,			September 30,
	2005			2005			2006
				(unaudited)			(unaudited)
Net sales
Petroleum	$	903,802,983		$	731,565,974		$	2,204,959,676
Nitrogen Fertilizer		79,347,843			46,590,621			128,155,190
Other		(2,444,565	)		(1,528,335	)		(3,961,995	)

Total	$	980,706,261		$	776,628,260		$	2,329,152,871

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	761,719,405		$	617,186,711		$	1,828,052,007
Nitrogen Fertilizer		9,125,852			9,172,463			23,829,421
Other		(2,778,079	)		(1,496,400	)		(3,804,871	)

Total	$	768,067,178		$	624,862,774		$	1,848,076,557

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	52,611,148		$	22,525,113		$	97,254,100
Nitrogen Fertilizer		28,302,714			14,149,817			47,207,127
Other		—			—			—

Total	$	80,913,862		$	36,674,930		$	144,461,227

Depreciation and amortization
Petroleum	$	770,728		$	7,735,006		$	23,561,843
Nitrogen Fertilizer		316,446			4,176,123			12,714,478
Other		40,831			13,220			533,323

Total	$	1,128,005		$	11,924,349		$	36,809,644

Operating income (loss)
Petroleum	$	76,654,428		$	79,081,672		$	233,522,252
Nitrogen Fertilizer		35,267,752			16,729,633			34,058,010
Other		333,514			(60,871	)		(571,233	)

Total	$	112,255,694		$	95,750,434		$	267,009,029

F-54

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)


	Immediate Predecessor		Successor
	174-Day Period		141-Day Period		Nine Months
	Ended		Ended		Ended
	June 23,		September 30,		September 30,
	2005		2005		2006
			(unaudited)		(unaudited)
Capital expenditures
Petroleum	$	10,790,042	$	10,920,718	$	157,606,403
Nitrogen fertilizer		1,434,921		947,991		12,710,765
Other		31,830		187,714		2,633,223

Total	$	12,256,793	$	12,056,423	$	172,950,391

Total assets
Petroleum					$	865,356,278
Nitrogen Fertilizer						421,830,249
Other						110,466,571

Total					$	1,397,653,098

Goodwill
Petroleum					$	42,806,422
Nitrogen Fertilizer						40,968,463
Other						—

Total					$	83,774,885

F-55

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

(10) Major Customers and Suppliers

Sales to major customers were as follows:


	Immediate
	Predecessor			Successor
	174-Day Period			141-Day Period			Nine Months
	Ended			Ended			Ended
	June 23,			September 30,			September 30,
	2005			2005			2006
Petroleum
Customer A		17	%		18	%		2	%
Customer B		17	%		18	%		16	%
Customer C		14	%		14	%		11	%
Customer D		11	%		11	%		10	%

		59	%		61	%		39	%

Nitrogen Fertilizer
Customer E		16	%		5	%		6	%
Customer F		9	%		11	%		4	%

		25	%		16	%		10	%

The Petroleum Segment maintains long-term contracts with one supplier for the purchase of its crude oil. The agreement with Supplier A expired in December 2005, at which time Successor entered into a similar arrangement with Supplier B, a related party (as described in note 8). Purchases contracted as a percentage of the total cost of goods sold for each of the periods were as follows:


	Immediate
	Predecessor			Successor
	174-Day Period			141-Day Period			Nine Months
	Ended			Ended			Ended
	September 23,			September 30,			September 30,
	2005			2005			2006
Supplier A		77	%		70	%		0	%
Supplier B		—			—			67	%

		77	%		70	%		67	%

F-56

CVR Energy, Inc. and Subsidiaries

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited) — (Continued)

(11) Subsequent Events

On November 30, 2006, an amendment to the Second Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC was approved with a pro rata reduction among all holders of common units in order to effect a total reduction of the number of outstanding Common Units. This amendment reduced the number of outstanding Common Units by 11.62%. Additionally, the benchmark amount with respect to each override unit was adjusted to $11.31.

On December 1, 2006, Successor entered into an Amendment Agreement (Amendment) to a Crude Oil Supply Agreement (Supply Agreement) with a subsidiary of GS (Supplier). The Amendment provides for an extension of the terms of the original Supply Agreement, as discussed in more detail in Note 8, which was originally effective December 30, 2005 with an initial term to December 31, 2006 and to continue one additional year unless either party terminated it. Successor and Supplier agreed to extend the term of the Supply Agreement for an additional 12 month period, January 1, 2007 through December 31, 2007 and in connection with the extension amended certain terms and conditions of the Supply Agreement.

Effective December 11, 2006, the compensation and override units committee of the Board approved the issuance of additional Phantom service points and Phantom performance points to members of management of the Company. After giving effect for the additional points, the total issued profits interest represented 14.31% of the combined common unit interest and profits interest of the Company. The profits interest was comprised of 10.37% and 3.94% of override units and phantom interest, respectively.

F-57

No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.

TABLE OF CONTENTS


	Page
Prospectus Summary		1
Risk Factors		17
Cautionary Note Regarding Forward-Looking Statements		33
Use of Proceeds		35
Dividend Policy		36
Capitalization		37
Dilution		38
Unaudited Pro Forma Condensed Consolidated Statement of Operations		39
Selected Historical Consolidated Financial Data		42
Management’s Discussion and Analysis of Financial Condition and Results of Operations		50
Industry Overview		99
Business		106
Management		129
Principal and Selling Stockholders		140
Certain Relationships and Related Party Transactions		143
Description of Our Indebtedness and the Cash Flow Swap		149
Description of Capital Stock		155
Shares Eligible for Future Sale		157
United States Tax Consequences to Non-United States Holders		158
Underwriting		162
Legal Matters		166
Experts		166
Where You Can Find More Information		166
Glossary of Selected Terms		167
Index To Consolidated Financial Statements		F-1

Through and including , 2007 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.

CVR Energy, Inc.

Common Stock

PROSPECTUS

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS


Item 13.	*Other Expenses of Issuance and Distribution.*

The following table sets forth the costs and expenses to be paid by the Registrant in connection with the sale of the shares of common stock being registered hereby. All amounts are estimates except for the SEC registration fee, the NASD filing fee and the listing fee.


SEC registration fee	$	32,100.00
NASD filing fee		30,500.00
listing fee
Accounting fees and expenses
Legal fees and expenses
Printing and engraving expenses
Blue Sky qualification fees and expenses
Transfer agent and registrar fees and expenses
Miscellaneous expenses

Total	$


Item 14.	*Indemnification of Directors and Officers.*

Section 145 of the Delaware General Corporation Law authorizes a court to award, or a corporation’s board of directors to grant, indemnity to directors and officers in terms sufficiently broad to permit such indemnification under certain circumstances for liabilities (including reimbursement for expenses incurred) arising under the Securities Act of 1933, as amended (the “Securities Act”).

As permitted by the Delaware General Corporation Law, the Registrant’s Certificate of Incorporation includes a provision that eliminates the personal liability of its directors for monetary damages for breach of fiduciary duty as a director, except for liability:


	•	for any breach of the director’s duty of loyalty to the Registrant or its stockholders;

	•	for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law;

	•	under section 174 of the Delaware General Corporation Law regarding unlawful dividends and stock purchases; or

	•	for any transaction for which the director derived an improper personal benefit.

As permitted by the Delaware General Corporation Law, the Registrant’s Bylaws provide that:


	•	the Registrant is required to indemnify its directors and officers to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions;

	•	the Registrant may indemnify its other employees and agents to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions;

	•	the Registrant is required to advance expenses, as incurred, to its directors and officers in connection with a legal proceeding to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions;

	•	the Registrant may advance expenses, as incurred, to its employees and agents in connection with a legal proceeding; and

	•	the rights conferred in the Bylaws are not exclusive.

II-1

The Registrant may enter into Indemnity Agreements with each of its current directors and officers to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in the Registrant’s Certificate of Incorporation and to provide additional procedural protections. At present, there is no pending litigation or proceeding involving a director, officer or employee of the Registrant regarding which indemnification is sought, nor is the Registrant aware of any threatened litigation that may result in claims for indemnification.

The indemnification provisions in the Registrant’s Certificate of Incorporation and Bylaws and any Indemnity Agreements entered into between the Registrant and each of its directors and officers may be sufficiently broad to permit indemnification of the Registrant’s directors and officers for liabilities arising under the Securities Act.

CVR Energy, Inc. and its subsidiaries are covered by liability insurance policies which indemnify their directors and officers against loss arising from claims by reason of their legal liability for acts as such directors, officers or trustees, subject to limitations and conditions as set forth in the policies.

The underwriting agreement to be entered into among the company, the selling stockholder and the underwriters will contain indemnification and contribution provisions.


Item 15.	*Recent Sales of Unregistered Securities.*

We issued shares of common stock to Coffeyville Acquisition LLC in September 2006. The issuance was exempt from registration in accordance with Section 4(2) of the Securities Act of 1933.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) The following exhibits are filed herewith:


Number			Exhibit Title

	1	.1*	Form of Underwriting Agreement.
	3	.1*	Certificate of Incorporation of CVR Energy, Inc.
	3	.2*	Bylaws of CVR Energy, Inc.
	4	.1*	Specimen Common Stock Certificate.
	5	.1*	Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP.
	10	.1*	Amended and Restated First Lien Credit and Guaranty Agreement, dated as of June 29, 2006, among Coffeyville Resources, LLC and the other parties thereto.
	10	.2*	Second Lien Credit and Guaranty Agreement, dated as of June 24, 2005, as amended.
	10	.3*	First Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, Cayman Islands Branch, as collateral agent.
	10	.4*	Second Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Wachovia Bank, National Association, as collateral agent.
	10	.5*	Swap agreements with J. Aron & Company.

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Number			Exhibit Title

	10	.6†**	Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. and Coffeyville Resources Nitrogen Fertilizers, LLC.
	10	.7	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and John J. Lipinski.
	10	.8	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Stanley A. Riemann.
	10	.9	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Kevan A. Vick.
	10	.10	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan.
	10	.11	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and James T. Rens.
	10	.12	Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi.
	10	.13†**	Crude Oil Supply Agreement, dated as of December 23, 2005, as amended, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC.
	10	.13.1†	Amendment Agreement dated as of December 1, 2006 between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC.
	10	.14†**	Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC.
	10	.15	Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas.
	21	.1*	List of Subsidiaries of CVR Energy, Inc.
	23	.1	Consent of KPMG LLP.
	23	.2*	Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1).
	24	.1**	Power of Attorney.


*		To be filed by amendment.

**		Previously filed.

†		Certain portions of this exhibit have been omitted and separately filed with the Securities and Exchange Commission pursuant to a request for confidential treatment.

(b) None.


Item 17.	*Undertakings.*

The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.

Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its

II-3

counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.

The undersigned Registrant hereby undertakes that:

(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and

(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.

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SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized in Sugar Land, State of Texas, on this 18th day of December, 2006.

CVR ENERGY, INC.


	By:	/s/ John J. Lipinski

John J. Lipinski

Chief Executive Officer and President

Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.


Signature		Title	Date

/s/ John J. Lipinski John J. Lipinski		Chief Executive Officer, President and Director (principal executive officer)	December 18, 2006

* James T. Rens		Chief Financial Officer (Principal Financial and Accounting Officer)	December 18, 2006

* Wesley Clark		Director	December 18, 2006

* Scott Lebovitz		Director	December 18, 2006

* George E. Matelich		Director	December 18, 2006

* Stanley de J. Osborne		Director	December 18, 2006

* Kenneth A. Pontarelli		Director	December 18, 2006

* By:	/s/ John J. Lipinski John J. Lipinski, As Attorney-in-Fact

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EXHIBIT INDEX


Number			Exhibit Title

	1	.1*	Form of Underwriting Agreement.
	3	.1*	Certificate of Incorporation of CVR Energy, Inc.
	3	.2*	Bylaws of CVR Energy, Inc.
	4	.1*	Specimen Common Stock Certificate.
	5	.1*	Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP.
	10	.1*	Amended and Restated First Lien Credit and Guaranty Agreement, dated as of June 29, 2006, among Coffeyville Resources, LLC and the other parties thereto.
	10	.2*	Second Lien Credit and Guaranty Agreement, dated as of June 24, 2005, as amended.
	10	.3*	First Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, Cayman Islands Branch, as collateral agent.
	10	.4*	Second Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Wachovia Bank, National Association, as collateral agent.
	10	.5*	Swap agreements with J. Aron & Company.
	10	.6†**	Amended and Restated On-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. and Coffeyville Resources Nitrogen Fertilizers, LLC.
	10	.7	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and John J. Lipinski.
	10	.8	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Stanley A. Riemann.
	10	.9	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Kevan A. Vick.
	10	.10	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan.
	10	.11	Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and James T. Rens.
	10	.12	Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi.
	10	.13†**	Crude Oil Supply Agreement, dated as of December 23, 2005, as amended, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC.
	10	.13.1†	Amendment Agreement dated as of December 1, 2006 between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC.
	10	.14†**	Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC.


Number			Exhibit Title

	10	.15	Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas.
	21	.1*	List of Subsidiaries of CVR Energy, Inc.
	23	.1	Consent of KPMG LLP.
	23	.2*	Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1).
	24	.1**	Power of Attorney.


*		To be filed by amendment.

**		Previously filed.

†		Certain portions of this exhibit have been omitted and separately filed with the Securities and Exchange Commission pursuant to a request for confidential treatment.

EX-10.7

Exhibit 10.7

AMENDMENT NUMBER 1
TO EMPLOYMENT AGREEMENT

AMENDMENT NUMBER 1 TO EMPLOYMENT AGREEMENT, dated as of December 13, 2006, by and between Coffeyville Resources, LLC, a Delaware limited liability company (the “Company”), and John J. Lipinski (the “Executive”).

WHEREAS, the Company and the Executive entered into an employment agreement dated as of July 12, 2005 (the “Employment Agreement”); and

WHEREAS, the Company and the Executive desire to amend the Employment Agreement with respect to the Executive’s target Annual Bonus beginning with, the 2007 fiscal year.

NOW THEREFORE, the parties hereby agree to amend the Employment Agreement as follows:

1. Section 2.2 is hereby deleted in its entirety and replaced with the following:

2.2. Annual Bonus. For each completed fiscal year occurring during the Term, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”). Commencing with fiscal year 2007, the target Annual Bonus shall be 250% of the Executive’s Base Salary as in effect at the beginning of such fiscal year 2007 and at the beginning of each such fiscal year thereafter during the Term, the actual Annual Bonus to be based upon such individual and/or Company performance criteria established for each such fiscal year by the Board.

2. In all other respects the Employment Agreement shall remain in effect and is hereby confirmed by the parties.


	COFFEYVILLE RESOURCES, LLC

/s/ John J. Lipinski John J. Lipinski	By:	/s/ James T. Rens Name: James T. Rens
		Title: CFO

EMPLOYMENT AGREEMENT

EMPLOYMENT AGREEMENT, dated as of July 12, 2005 (the “Employment Agreement”), by and between Coffeyville Resources, LLC, a Delaware limited liability company (the “Company”), and John J. Lipinski (the “Executive”).

WHEREAS, pursuant to the Stock Purchase Agreement, dated as of May 15, 2005 (the “Stock Purchase Agreement”), between Coffeyville Group Holdings, LLC, a Delaware limited liability company (“Seller”) and Coffeyville Acquisition LLC, a Delaware limited liability company (“Buyer”), Buyer agreed to purchase from Seller all of the issued and outstanding shares of capital stock of Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. and Coffeyville Terminal, Inc.; and

WHEREAS, the Company and the Executive desire to, effective as of the consummation of the transactions contemplated in the Stock Purchase Agreement, enter into this Employment Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein and other valid consideration the sufficiency of which is acknowledged, the parties hereto agree as follows:

Section 1. Employment.

1.1. Term. The Company agrees to employ the Executive, and the Executive agrees to be employed by the Company, in each case pursuant to this Employment Agreement, for a period commencing on the “Closing Date” (as such term is defined in the Stock Purchase Agreement) and ending on the earlier of (i) the third (3^rd) anniversary of the Closing Date and (ii) the termination of the Executive’s employment in accordance with Section 3 hereof (the “Term”), provided, however, that at the end of each calendar month after the Closing Date, the term of this Employment Agreement shall be automatically extended for one month.

1.2. Duties. During the Term, the Executive shall serve as Chief Executive Officer of the Company and such other positions as an officer or director of the Company and such affiliates of the Company as the Executive and the board of directors of the Company (the “Board”) shall mutually agree from time to time. In such positions, the Executive shall perform such duties, functions and responsibilities during the Term commensurate with the Executive’s positions as reasonably directed by the Board. The Executive shall be employed in the State of Texas during the Term.

1.3. Exclusivity. During the Term, the Executive shall devote substantially all of his working time to the business and affairs of the Company, shall faithfully serve the Company, and shall in all material respects conform to and comply with the lawful and reasonable directions and instructions given to him by the Board, consistent with Section 1.2 hereof. During the Term, the Executive shall use his best efforts during his working time to promote and serve the interests of the Company and shall not engage in any other business

activity, whether or not such activity shall be engaged in for pecuniary profit. The provisions of this Section 1.3 shall not be construed to prevent Executive from (i) investing his personal, private assets as a passive investor in such form or manner as will not require any active services on the part of Executive in the management or operation of the affairs of the companies, partnerships, or other business entities in which any such passive investments are made; (ii) serving on the boards of directors for Intercat Inc. and Thumbs Up Enterprises Limited; or (iii) providing consulting services to Gulf Atlantic Operations, LLC and Dunhill Products, L.P.

Section 2. Compensation.

2.1. Salary. As compensation for the performance of the Executive’s services hereunder, during the Term, the Company shall pay to the Executive a salary at an annual rate of Six Hundred Fifty Thousand Dollars ($650,000), payable in accordance with the Company’s standard payroll policies, as may be adjusted upward by the Board in its discretion (as adjusted, the “Base Salary”).

2.2. Bonus.

(a) Annual Bonus. For each completed fiscal year occurring during the Term, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”). The target Annual Bonus shall be 75% of the Executive’s Base Salary as in effect at the beginning of such fiscal year, the actual Annual Bonus to be based upon such individual and/or Company performance criteria established for each such fiscal year by the Board. The Executive shall be eligible to receive a pro-rated Annual Bonus for the fiscal year in which the Closing Date occurs based upon the portion of the fiscal year during the Term that the Executive is employed and individual and/or Company performance criteria established for that period by the Board.

(b) Special Bonus. The Executive shall be eligible to participate in any special bonus program that the Board may implement to reward senior management for extraordinary performance on terms and conditions established by the Board.

2.3. Employee Benefits. During the Term, the Executive shall be eligible to participate in such health, insurance, retirement, and other employee benefit plans and programs of the Company as in effect from time to time on the same basis as other senior executives of the Company.

2.4. Vacation. During the Term, the Executive shall be entitled to four (4) weeks of paid vacation each year.

2.5. Business Expenses. The Company shall pay or reimburse the Executive for all commercially reasonable business out-of-pocket expenses that the Executive incurs during the Term in performing his duties under this Employment Agreement upon presentation of documentation and in accordance with the expense reimbursement policy of the Company as approved by the Board and in effect from time to time.

Section 3. Employment Termination.

3.1. Termination of Employment. The Company may terminate the Executive’s employment for any reason during the Term, and the Executive may voluntarily terminate his employment for any reason during the Term, in each case (other than a termination by the Company for Cause) at any time upon not less than thirty (30) days’ notice to the other party. Upon the termination of the Executive’s employment with the Company for any reason (whether during the Term or thereafter), the Executive shall be entitled to any Base Salary earned but unpaid through the date of termination, any earned but unpaid Annual Bonus for completed fiscal years, and any unreimbursed expenses in accordance with Section 2.5 hereof (collectively, the “Accrued Amounts”).

3.2. Certain Terminations.

(a) Termination by the Company Other Than For Cause or Disability; Termination by the Executive for Good Reason. If (i) the Executive’s employment is terminated by the Company during the Term other than for Cause or Disability or (ii) the Executive resigns for Good Reason, in addition to the Accrued Amounts the Executive shall be entitled to the following payments and benefits: (x) the continuation of his Base Salary at the rate in effect immediately prior to the date of termination for a period of thirty-six (36) months and (y) the continuation on the same terms as an active employee of medical benefits the Executive would otherwise be eligible to receive as an active employee of the Company for thirty-six (36) months or until the Executive becomes eligible for medical benefits from a subsequent employer (such payments, the “Severance Payments”). The Company’s obligations to make the Severance Payments shall be conditioned upon: (i) the Executive’s continued compliance with his obligations under Section 4 of this Employment Agreement and (ii) the Executive’s execution, delivery and non-revocation of a valid and enforceable general release of claims arising in connection with the Executive’s employment and termination of employment with the Company and its affiliates in a form reasonably acceptable to the Company and the Executive (“Release”). In the event that the Executive breaches any of the covenants set forth in Section 4 of this Employment Agreement, the Executive will immediately return to the Company any portion of the Severance Payments that have been paid to the Executive pursuant to this Section 3.2(a). Subject to Section 3.2(e), the Severance Payments will commence to be paid to the Executive as soon as practicable following the effectiveness of the Release.

(b) Termination by the Company For Disability. If the Executive’s employment is terminated during the Term by the Company by reason of the Executive’s Disability, in addition to the Accrued Amounts and any payments to be made to the Executive under the Company’s disability plan(s) as a result of such Disability, the Company shall pay to the Executive such supplemental amounts (the “Supplemental Disability Payments”) as shall be necessary to result in the payment of aggregate amounts to the Executive as a result of his Disability that shall be equal to the Executive’s Base Salary as in effect immediately before such Disability; provided, that, at the Company’s option, the Company may purchase insurance to cover its obligations under this Section 3.2(b) and the Executive shall cooperate to assist the Company in obtaining such insurance. Such Supplemental Disability Payments shall be made for a period of thirty-six (36) months from the Date of Disability. The Company’s obligations to

make the Supplemental Disability Payments shall be conditioned upon: (i) the Executive’s continued compliance with his obligations under Section 4 of this Employment Agreement and (ii) the Executive’s execution, delivery and non-revocation of a Release. In the event that the Executive breaches any of the covenants set forth in Section 4 of this Employment Agreement, the Executive will immediately return to the Company any portion of the Supplemental Disability Payments that have been paid to the Executive pursuant to this Section 3.2(b). Subject to Section 3.2(e), the Supplemental Disability Payments will commence to be paid to the Executive as soon as practicable following the effectiveness of the Release.

(c) Termination by Reason of Death. If the Executive’s employment is terminated during the Term by reason of his death, in addition to the Accrued Amounts and any employee benefits to which the Executive’s estate, spouse or other beneficiaries, as applicable, may be entitled, the Company shall pay to the beneficiary designated in writing by the Executive (or to his estate if no such beneficiary has been so designated), the Base Salary which the Executive would have received if he had remained employed under this Employment Agreement for a total of thirty-six months from the commencement of the Term, assuming for such remaining period the Executive’s Base Salary as in effect on the date of the Executive’s death; provided, that, at the Company’s option, the Company may purchase insurance to cover its obligations under this Section 3.2(c) and the Executive shall cooperate to assist the Company in obtaining such insurance.

(d) Definitions. For purposes of this Section 3.2, the following terms shall have the following meanings:

(1) A termination for “Good Reason” shall mean a termination by the Executive within thirty (30) days following the date on which the Company has engaged in any of the following: (i) the assignment of duties or responsibilities to the Executive that reflect a material diminution of the Executive’s position with the Company; (ii) a relocation of the Executive’s principal place of employment that increases the Executive’s commute by more than fifty (50) miles; or (iii) a reduction in the Executive’s Base Salary, other than across-the-board reductions applicable to similarly situated employees of the Company; provided, however, that the Executive must provide the Company with notice promptly following the occurrence of any of foregoing and at least ten (10) business days to cure.

(2) “Cause” shall mean that the Executive has engaged in any of the following: (i) willful misconduct or breach of fiduciary duty; (ii) intentional failure or refusal to perform reasonably assigned duties after written notice of such willful failure or refusal and the failure or refusal is not corrected within ten (10) business days; provided, however, that the Executive’s refusal to participate in or perform any act on behalf of the Company which upon advice of counsel the Executive in good faith believes is illegal or unethical shall not constitute Cause; (iii) the indictment for, conviction of or entering a plea of guilty or nolo contendere to a crime constituting a felony (other than a traffic violation or other offense or violation outside of the course of employment which does not adversely affect the Company and its affiliates or their reputation or the ability of the Executive to perform his employment-related duties or to represent the Company); provided, however, that (A) if the Executive is terminated for Cause by reason of his indictment pursuant to this clause (iii) and the

indictment is subsequently dismissed or withdrawn or the Executive is found to be not guilty in a court of law in connection with such indictment, then the Executive’s termination shall be treated for purposes of this Employment Agreement as a termination by the Company other than for Cause, and the Executive will be entitled to receive (without duplication of benefits and to the extent permitted by law and the terms of the then-applicable medical benefit plans) the payments and benefits set forth in Section 3.2(a) following such dismissal, withdrawal or finding, payable in the manner and subject to the conditions set forth in such Section and (B) if such indictment relates to environmental matters and does not allege that the Executive was directly involved in or directly supervised the action(s) forming the basis of the indictment, Cause shall not be deemed to exist under this Employment Agreement by reason of such indictment until the Executive is convicted or enters a plea of guilty or nolo contendere in connection with such indictment; or (iv) material breach of the Executive’s covenants in Section 4 of this Employment Agreement or any material written policy of the Company after written notice of such breach and failure by the Executive to cure such breach within ten (10) business days; provided, however, that no such notice of, nor opportunity to cure, such breach shall be required hereunder if the breach cannot be cured by the Executive.

(3) “Disability” shall mean that: (i) the Executive is unable to perform his duties hereunder as a result of illness or physical injury for a period of at least 90 days; (ii) the Executive is entitled to receive payments under the Company’s long-term disability insurance plan; (iii) the Executive has started to receive such disability insurance payments; and (iv) no person has contested or questioned the Executive’s right to receive such payments or, if such payments have been contested, the Company has irrevocably and unconditionally agreed to pay the Executive such amounts as will net to Executive after reduction for applicable federal and state income taxes the same amount as he would have received after such taxes from such insurance. The “Date of Disability” shall mean the first date on which all of the requirements set forth in clauses (i) through (iv) above have been satisfied.

(e) Section 409A. Any payments under Section 2.2 of this Employment Agreement shall be made no later than two and one-half months after the later of the end of the Company’s fiscal year in which all conditions entitling Executive to such payments have been satisfied or the calendar year in which all conditions entitling Executive to such payments have been satisfied . If the Executive is a “specified employee” for purposes of Section 409A of the Code and the regulations thereunder, any Severance Payments or Supplemental Disability Payments required to be made pursuant to Section 3.2(a) or 3.2(b) which are subject to Section 409A shall not commence until six (6) months from the date of termination, with the first payment equaling six (6) months of his Base Salary at the rate in effect immediately prior to the date of termination.

3.3. Exclusive Remedy. The foregoing payments upon termination of the Executive’s employment shall constitute the exclusive severance payments due the Executive upon a termination of his employment under this Employment Agreement.

3.4. Resignation from All Positions. Upon the termination of the Executive’s employment with the Company for any reason, the Executive shall be deemed to have resigned, as of the date of such termination, from all positions he then holds as an officer,

director, employee and member of the board (and any committee thereof) of the Company and any of its direct or indirect subsidiaries (collectively, “Subsidiaries”).

3.5. Cooperation. Following the termination of the Executive’s employment with the Company for any reason and during any period in which the Executive is receiving Severance Payments or Supplemental Disability Payments, or for one (1) year following termination of the Executive’s employment with the Company if no Severance Payments or Supplemental Disability Payments are payable, the Executive agrees to reasonably cooperate with the Company upon reasonable request of the Board and to be reasonably available to the Company with respect to matters arising out of the Executive’s services to the Company and its Subsidiaries. The Company shall reimburse the Executive for expenses reasonably incurred in connection with such matters as agreed by the Executive and the Board and the Company shall compensate the Executive for such cooperation at an hourly rate based on the Executive’s most recent base salary rate assuming two thousand (2,000) working hours per year; provided, that if the Executive is required to spend more than forty (40) hours in any month on Company matters pursuant to this Section 3.5, the Executive and the Board shall mutually agree to an appropriate rate of compensation for the Executive’s time over such forty (40) hour threshold.

Section 4. Unauthorized Disclosure; Non-Solicitation; Non-Competition; Proprietary Rights.

4.1. Unauthorized Disclosure. The Executive agrees and understands that in the Executive’s position with the Company, the Executive has been and will be exposed to and has and will receive information relating to the confidential affairs of the Company and its affiliates, including, without limitation, technical information, intellectual property, business and marketing plans, strategies, customer information, software, other information concerning the products, promotions, development, financing, expansion plans, business policies and practices of the Company and its affiliates and other forms of information considered by the Company and its affiliates to be confidential and in the nature of trade secrets (including, without limitation, ideas, research and development, know-how, formulas, technical data, designs, drawings, specifications, customer and supplier lists, pricing and cost information and business and marketing plans and proposals) (collectively, the “Confidential Information”); provided however, that Confidential Information shall not include information which (i) is or becomes generally available to the public not in violation of this Employment Agreement or any written policy of the Company, or (ii) was in the Executive’s possession or knowledge on a non-confidential basis prior to such disclosure. The Executive agrees that at all times during the Executive’s employment with the Company and thereafter, the Executive shall not disclose such Confidential Information, either directly or indirectly, to any individual, corporation, partnership, limited liability company, association, trust or other entity or organization, including a government or political subdivision or an agency or instrumentality thereof (each a “Person”) without the prior written consent of the Company and shall not use or attempt to use any such information in any manner other than in connection with his employment with the Company, unless required by law to disclose such information, in which case the Executive shall provide the Company with written notice of such requirement as far in advance of such anticipated disclosure as possible. This confidentiality covenant has no temporal, geographical or territorial

restriction. Upon termination of the Executive’s employment with the Company, the Executive shall promptly supply to the Company all property, keys, notes, memoranda, writings, lists, files, reports, customer lists, correspondence, tapes, disks, cards, surveys, maps, logs, machines, technical data and other tangible products or documents, in each case, which have been produced by, received by or otherwise submitted to the Executive during or prior to the Executive’s employment with the Company and which are or contain Confidential Information, and any copies thereof in his (or capable of being reduced to his) possession.

4.2. Non-Competition. By and in consideration of the Company’s entering into this Employment Agreement and the payments to be made and benefits to be provided by the Company hereunder, and in further consideration of the Executive’s exposure to the Confidential Information of the Company and its affiliates, the Executive agrees that the Executive shall not, during the Executive’s employment with the Company (whether during the Term or thereafter) and thereafter for the period during which the Severance Payments or Supplemental Disability Payments are payable or one (1) year following termination of the Executive’s employment with the Company if no Severance Payments or Supplemental Disability Payments are payable (the “Restriction Period”), directly or indirectly, own, manage, operate, join, control, be employed by, or participate in the ownership, management, operation or control of, or be connected in any manner with, including, without limitation, holding any position as a stockholder, director, officer, consultant, independent contractor, employee, partner, or investor in, any Restricted Enterprise (as defined below); provided, that in no event shall ownership of one percent (1%) or less of the outstanding securities of any class of any issuer whose securities are registered under the Securities Exchange Act of 1934, as amended, standing alone, be prohibited by this Section 4.2, so long as the Executive does not have, or exercise, any rights to manage or operate the business of such issuer other than rights as a stockholder thereof. For purposes of this paragraph, “Restricted Enterprise” shall mean any Person that is actively engaged in any business which is either (i) in competition with the business of the Company or any of its Subsidiaries conducted during the preceding twelve (12) months (or following the Executive’s termination of employment, the twelve (12) months preceding the date of termination of the Executive’s employment with the Company) or (ii) proposed to be conducted by the Company or any of its Subsidiaries in the Company’s business plan as in effect at that time (or following the Executive’s termination of employment, the business plan as in effect as of the date of termination of the Executive’s employment with the Company); provided, that (x) with respect to any Person that is actively engaged in the refinery business, a Restricted Enterprise shall only include such a Person that operates or markets in any geographic area in which the Company or any of its Subsidiaries operates or markets with respect to its refinery business, and (y) with respect to any Person that is actively engaged in the fertilizer business, a Restricted Enterprise shall only include such a Person that operates or markets in any geographic area in which the Company or any of its Subsidiaries operates or markets with respect to its fertilizer business. During the Restriction Period, upon request of the Company, the Executive shall notify the Company of the Executive’s then-current employment status. For the avoidance of doubt, (A) the foregoing shall not prohibit the Executive from working in the State of Texas; provided, that the Executive’s so working does not involve any Restricted Enterprise that is operating in the State of Texas if the Company or any of its Subsidiaries is then operating in the State of Texas and (B) a Restricted Enterprise shall not include any Person or division thereof that is engaged in the business of supplying (but not refining) crude oil or natural gas.

4.3. Non-Solicitation of Employees. During the Restriction Period, the Executive shall not directly or indirectly solicit (or assist any Person to solicit) for employment any person who is, or within twelve (12) months prior to the date of such solicitation was, an employee of the Company or any of its Subsidiaries; provided, however, that this Section 4.3 shall not prohibit the hiring of any individual as a result of the individual’s response to an advertisement in a publication of general circulation.

4.4. Non-Solicitation of Customers/Suppliers. During the Restriction Period, the Executive shall not (i) solicit (or assist any Person to solicit) any Person which has a business relationship with the Company or of any of its Subsidiaries in order to terminate, curtail or otherwise interfere with such business relationship or (ii) solicit, other than on behalf of the Company and its Subsidiaries, any Person that the Executive knows or should have known (x) is a current customer of the Company or any of its Subsidiaries in any geographic area in which the Company or any of its Subsidiaries operates or markets or (y) is a Person in any geographic area in which the Company or any of its Subsidiaries operates or markets with respect to which the Company or any of its Subsidiaries has, within the twelve (12) months prior to the date of such solicitation, devoted more than de minimis resources in an effort to cause such Person to become a customer of the Company or any of its Subsidiaries in that geographic area. For the avoidance of doubt, the foregoing does not preclude the Executive from soliciting, outside of the geographic areas in which the Company or any of its Subsidiaries operates or markets, any Person that is a customer or potential customer of the Company or any of its Subsidiaries in the geographic areas in which it operates or markets.

4.5. Extension of Restriction Period. The Restriction Period shall be tolled for any period during which the Executive is in breach of any of Sections 4.2, 4.3 or 4.4 hereof.

4.6. Proprietary Rights. The Executive shall disclose promptly to the Company any and all inventions, discoveries, and improvements (whether or not patentable or registrable under copyright or similar statutes), and all patentable or copyrightable works, initiated, conceived, discovered, reduced to practice, or made by him, either alone or in conjunction with others, during the Executive’s employment with the Company and related to the business or activities of the Company and its affiliates (the “Developments”). Except to the extent any rights in any Developments constitute a work made for hire under the U.S. Copyright Act, 17 U.S.C. § 101 et seq. that are owned ab initio by the Company and/or its applicable affiliate, the Executive assigns all of his right, title and interest in all Developments (including all intellectual property rights therein) to the Company or its nominee without further compensation, including all rights or benefits therefor, including without limitation the right to sue and recover for past and future infringement. The Executive acknowledges that any rights in any developments constituting a work made for hire under the U.S. Copyright Act, 17 U.S.C § 101 et seq. are owned upon creation by the Company and/or its applicable affiliate as the Executive’s employer. Whenever requested to do so by the Company, the Executive shall execute any and all applications, assignments or other instruments which the Company shall deem necessary to apply for and obtain trademarks, patents or copyrights of the United States or any foreign country or otherwise protect the interests of the Company and its affiliates therein. These obligations shall continue beyond the end of the Executive’s employment with the Company

with respect to inventions, discoveries, improvements or copyrightable works initiated, conceived or made by the Executive while employed by the Company, and shall be binding upon the Executive’s employers, assigns, executors, administrators and other legal representatives. In connection with his execution of this Employment Agreement, the Executive has informed the Company in writing of any interest in any inventions or intellectual property rights that he holds as of the date hereof. If the Company is unable for any reason, after reasonable effort, to obtain the Executive’s signature on any document needed in connection with the actions described in this Section 4.6, the Executive hereby irrevocably designates and appoints the Company and its duly authorized officers and agents as the Executive’s agent and attorney in fact to act for and in the Executive’s behalf to execute, verify and file any such documents and to do all other lawfully permitted acts to further the purposes of this Section with the same legal force and effect as if executed by the Executive.

4.7. Confidentiality of Agreement. Other than with respect to information required to be disclosed by applicable law, the parties hereto agree not to disclose the terms of this Employment Agreement to any Person; provided the Executive may disclose this Employment Agreement and/or any of its terms to the Executive’s immediate family, financial advisors and attorneys. Notwithstanding anything in this Section 4.7 to the contrary, the parties hereto (and each of their respective employees, representatives, or other agents) may disclose to any and all Persons, without limitation of any kind, the tax treatment and tax structure of the transactions contemplated by this Employment Agreement, and all materials of any kind (including opinions or other tax analyses) related to such tax treatment and tax structure; provided that this sentence shall not permit any Person to disclose the name of, or other information that would identify, any party to such transactions or to disclose confidential commercial information regarding such transactions.

4.8. Remedies. The Executive agrees that any breach of the terms of this Section 4 would result in irreparable injury and damage to the Company for which the Company would have no adequate remedy at law; the Executive therefore also agrees that in the event of said breach or any threat of breach, the Company shall be entitled to an immediate injunction and restraining order to prevent such breach and/or threatened breach and/or continued breach by the Executive and/or any and all Persons acting for and/or with the Executive, without having to prove damages, in addition to any other remedies to which the Company may be entitled at law or in equity, including, without limitation, the obligation of the Executive to return any Severance Payments or Supplemental Disability Payments made by the Company to the Company. The terms of this paragraph shall not prevent the Company from pursuing any other available remedies for any breach or threatened breach hereof, including, without limitation, the recovery of damages from the Executive. The Executive and the Company further agree that the provisions of the covenants contained in this Section 4 are reasonable and necessary to protect the businesses of the Company and its affiliates because of the Executive’s access to Confidential Information and his material participation in the operation of such businesses.

Section 5. Representation.

The Executive represents and warrants that (i) he is not subject to any contract, arrangement, policy or understanding, or to any statute, governmental rule or regulation, that in any way limits his ability to enter into and fully perform his obligations under this Employment Agreement and (ii) he is not otherwise unable to enter into and fully perform his obligations under this Employment Agreement.

Section 6. Withholding.

All amounts paid to the Executive under this Employment Agreement during or following the Term shall be subject to withholding and other employment taxes imposed by applicable law.

Section 7. Effect of Section 280G of the Internal Revenue Code.

7.1. Payment Reduction. Notwithstanding anything contained in this Employment Agreement to the contrary, to the extent that any payment or distribution of any type to or for the Executive by the Company, any affiliate of the Company, any Person who acquires ownership or effective control of the Company or ownership of a substantial portion of the Company’s assets (within the meaning of Section 280G of the Internal Revenue Code of 1986, as amended (the “Code”) and the regulations thereunder), or any affiliate of such Person, whether paid or payable or distributed or distributable pursuant to the terms of this Employment Agreement or otherwise (the “Payments”) is or will be subject to the excise tax imposed under Section 4999 of the Code (the “Excise Tax”), then the Payments shall be reduced (but not below zero) if and to the extent necessary so that no Payments to be made or benefit to be provided to the Executive shall be subject to the Excise Tax; provided, however, that the Company shall use its reasonable best efforts to obtain shareholder approval of the Payments provided for in this Employment Agreement in a manner intended to satisfy requirements of the “shareholder approval” exception to Section 280G of the Code and the regulations promulgated thereunder, such that payment may be made to the Executive of such Payments without the application of an Excise Tax. Unless the Executive shall have given prior written notice to the Company specifying a different order by which to effectuate the reduction, the Company shall reduce or eliminate the Payments (x) by first reducing or eliminating the portion of the Payments which are not payable in cash (other than that portion of the Payments subject to clause (z) hereof), (y) then by reducing or eliminating cash payments (other than that portion of the Payments subject to clause (z) hereof) and (z) then by reducing or eliminating the portion of the Payments (whether payable in cash or not payable in cash) to which Treasury Regulation § 1.280G-1 Q/A 24(c) (or successor thereto) applies, in each case in reverse order beginning with payments or benefits which are to be paid the farthest in time. Any notice given by the Executive pursuant to the preceding sentence shall take precedence over the provisions of any other plan, arrangement or agreement governing the Executive’s rights and entitlements to any benefits or compensation.

7.2. Determination of Amount of Reduction. The determination of whether the Payments shall be reduced as provided in Section 7.1 and the amount of such reduction shall be made at the Company’s expense by an accounting firm selected by the Company from among the four (4) largest accounting firms in the United States (the

“Accounting Firm”). The Accounting Firm shall provide its determination (the “Determination”), together with detailed supporting calculations and documentation, to the Company and the Executive within ten (10) days after the Executive’s final day of employment. If the Accounting Firm determines that no Excise Tax is payable by the Executive with respect to the Payments, it shall furnish the Executive with an opinion reasonably acceptable to the Executive that no Excise Tax will be imposed with respect to any such payments and, absent manifest error, such Determination shall be binding, final and conclusive upon the Company and the Executive.

Section 8. Miscellaneous.

8.1. Indemnification. To the extent permitted by applicable law, the Company shall indemnify the Executive for losses or damages incurred by the Executive as a result of all causes of action arising from the Executive’s performance of duties for the benefit of the Company, whether or not the claim is asserted during the Term. This indemnity shall not apply to the Executive’s acts of willful misconduct or gross negligence. The Executive shall be covered under any directors’ and officers’ insurance that the Company maintains for its directors and other officers in the same manner and on the same basis as the Company’s directors and other officers.

8.2. Amendments and Waivers. This Employment Agreement and any of the provisions hereof may be amended, waived (either generally or in a particular instance and either retroactively or prospectively), modified or supplemented, in whole or in part, only by written agreement signed by the parties hereto; provided, that, the observance of any provision of this Employment Agreement may be waived in writing by the party that will lose the benefit of such provision as a result of such waiver. The waiver by any party hereto of a breach of any provision of this Employment Agreement shall not operate or be construed as a further or continuing waiver of such breach or as a waiver of any other or subsequent breach, except as otherwise explicitly provided for in such waiver. Except as otherwise expressly provided herein, no failure on the part of any party to exercise, and no delay in exercising, any right, power or remedy hereunder, or otherwise available in respect hereof at law or in equity, shall operate as a waiver thereof, nor shall any single or partial exercise of such right, power or remedy by such party preclude any other or further exercise thereof or the exercise of any other right, power or remedy.

8.3. Assignment. This Employment Agreement, and the Executive’s rights and obligations hereunder, may not be assigned by the Executive, and any purported assignment by the Executive in violation hereof shall be null and void.

8.4. Notices. Unless otherwise provided herein, all notices, requests, demands, claims and other communications provided for under the terms of this Employment Agreement shall be in writing. Any notice, request, demand, claim or other communication hereunder shall be sent by (i) personal delivery (including receipted courier service) or overnight delivery service, (ii) facsimile during normal business hours, with confirmation of receipt, to the number indicated, (iii) reputable commercial overnight delivery service courier or (iv) registered or certified mail, return receipt requested, postage prepaid and addressed to the intended recipient as set forth below:


		If to the Company:
				Coffeyville Resources, LLC
				10 E. Cambridge Circle, Suite 250
				Kansas City, KS 66103
				Attention: General Counsel
				Facsimile: (913) 981-0000

		with a copy to:

				Fried, Frank, Harris, Shriver & Jacobson LLP
				One New York Plaza
				New York, NY 10004
				Attention: Donald P. Carleen, Esq.
				Facsimile: (212) 859-4000

		If to the Executive:

				John J. Lipinski
				806 Skimmer Court
				Sugar Land, TX 77478

All such notices, requests, consents and other communications shall be deemed to have been given when received. Any party may change its facsimile number or its address to which notices, requests, demands, claims and other communications hereunder are to be delivered by giving the other parties hereto notice in the manner then set forth.

8.5. Governing Law. This Employment Agreement shall be construed and enforced in accordance with, and the rights and obligations of the parties hereto shall be governed by, the laws of the State of Kansas, without giving effect to the conflicts of law principles thereof. Each of the parties hereto irrevocably and unconditionally consents to submit to the exclusive jurisdiction of the courts of Kansas (collectively, the “Selected Courts”) for any action or proceeding relating to this Employment Agreement, agrees not to commence any action or proceeding relating thereto except in the Selected Courts, and waives any forum or venue objections to the Selected Courts.

8.6. Severability. Whenever possible, each provision or portion of any provision of this Employment Agreement, including those contained in Section 4 hereof, will be interpreted in such manner as to be effective and valid under applicable law but the invalidity or unenforceability of any provision or portion of any provision of this Employment Agreement in any jurisdiction shall not affect the validity or enforceability of the remainder of this Employment Agreement in that jurisdiction or the validity or enforceability of this Employment Agreement, including that provision or portion of any provision, in any other jurisdiction. In addition, should a court or arbitrator determine that any provision or portion of any provision of this Employment Agreement, including those contained in Section 4 hereof, is not reasonable or valid, either in period of time, geographical area, or otherwise, the parties hereto agree that such

provision should be interpreted and enforced to the maximum extent which such court or arbitrator deems reasonable or valid.

8.7. Entire Agreement. From and after the Closing Date, this Employment Agreement constitutes the entire agreement between the parties hereto, and supersedes all prior representations, agreements and understandings (including any prior course of dealings), both written and oral, between the parties hereto with respect to the subject matter hereof; provided, however, that the foregoing shall not affect the terms of any employee benefit or compensation plan in which the Executive participates.

8.8. Counterparts. This Employment Agreement may be executed in any number of counterparts, each of which shall be deemed an original, but all such counterparts shall together constitute one and the same instrument.

8.9. Binding Effect. This Employment Agreement shall inure to the benefit of, and be binding on, the successors and assigns of each of the parties, including, without limitation, the Executive’s heirs and the personal representatives of the Executive’s estate and any successor to all or substantially all of the business and/or assets of the Company.

8.10. General Interpretive Principles. The name assigned this Employment Agreement and headings of the sections, paragraphs, subparagraphs, clauses and subclauses of this Employment Agreement are for convenience of reference only and shall not in any way affect the meaning or interpretation of any of the provisions hereof. Words of inclusion shall not be construed as terms of limitation herein, so that references to “include”, “includes” and “including” shall not be limiting and shall be regarded as references to non-exclusive and non-characterizing illustrations.

8.11. Mitigation. Notwithstanding any other provision of this Employment Agreement, (a) the Executive will have no obligation to mitigate damages for any breach or termination of this Employment Agreement by the Company, whether by seeking employment or otherwise and (b) except for medical benefits provided pursuant to Section 3.2(a), the amount of any payment or benefit due the Executive after the date of such breach or termination will not be reduced or offset by any payment or benefit that the Executive may receive from any other source.

[signature page follows]

IN WITNESS WHEREOF, the parties have executed this Employment Agreement as of the date first written above.


	COFFEYVILLE RESOURCES, LLC

/s/ John J. Lipinski	By:	/s/ James T. Rens

John J. Lipinski		Name: James T. Rens Title: CFO

EX-10.8

Exhibit 10.8

AMENDMENT NUMBER 1
TO EMPLOYMENT AGREEMENT

WHEREAS, the Company and the Executive entered into an employment agreement dated as of July 12, 2005 (the “Employment Agreement”); and

WHEREAS, the Company and the Executive desire to amend the Employment Agreement with respect to the Executive’s target Annual Bonus beginning with the 2007 fiscal year.

NOW THEREFORE, the parties hereby agree to amend the Employment Agreement as follows:

Section 2.2 is hereby deleted in its entirety and replaced with the following:

2.2. Annual Bonus. For each completed fiscal year occurring during the Term, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”). Commencing with fiscal year 2007, the target Annual Bonus shall be 200% of the Executive’s Base Salary as in effect at the beginning of such fiscal year 2007 and at the beginning of each such fiscal year thereafter during the Term, the actual Annual Bonus to be based upon such individual and/or Company performance criteria established for each such fiscal year by the Board.

In all other respects the Employment Agreement shall remain in effect and is hereby confirmed by the parties.


	COFFEYVILLE RESOURCES, LLC

/s/ Stanley A. Riemann Stanley A. Riemann	By:	/s/ John J. Lipinski Name: John J. Lipinski
		Title: CEO

EMPLOYMENT AGREEMENT

WHEREAS, the Company and the Executive are currently parties to an employment agreement, dated as of March 3, 2004 (the “Existing Employment Agreement”);

WHEREAS, pursuant to the Stock Purchase Agreement, dated as of May 15, 2005 (the “Stock Purchase Agreement”), between Coffeyville Group Holdings, LLC, a Delaware limited liability company (“Seller”) and Coffeyville Acquisition LLC, a Delaware limited liability company (“Buyer”), Buyer purchased from Seller all of the issued and outstanding shares of capital stock of Coffeyville Pipeline, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. and Coffeyville Terminal, Inc.; and

WHEREAS, the Company and the Executive desire to, effective as of the consummation of the transactions contemplated in the Stock Purchase Agreement, terminate the Existing Employment Agreement and enter into this Employment Agreement.

NOW, THEREFORE, in consideration of the mutual covenants contained herein and other valid consideration the sufficiency of which is acknowledged, the parties hereto agree as follows:

Section 1. Employment.

1.2. Duties. During the Term, the Executive shall serve as Chief Operating Officer of the Company and such other positions as an officer or director of the Company and such affiliates of the Company as the Executive and the board of directors of the Company (the “Board”) shall mutually agree from time to time. In such positions, the Executive shall perform such duties, functions and responsibilities during the Term commensurate with the Executive’s positions as reasonably directed by the Board.

1.3. Exclusivity. During the Term, the Executive shall devote substantially all of his working time and attention to the business and affairs of the Company, shall faithfully serve the Company, and shall in all material respects conform to and comply with the lawful and reasonable directions and instructions given to him by the Board, consistent with Section 1.2 hereof. During the Term, the Executive shall use his best efforts during his working time to promote and serve the interests of the Company and shall not engage in any other business activity, whether or not such activity shall be engaged in for pecuniary profit. The

provisions of this Section 1.3 shall not be construed to prevent the Executive from investing his personal, private assets as a passive investor in such form or manner as will not require any active services on the part of the Executive in the management or operation of the affairs of the companies, partnerships, or other business entities in which any such passive investments are made. Notwithstanding the foregoing, during the Term the Executive shall not engage in any activity related to the construction or operation of ammonia, urea ammonium nitrate or fertilizer plants or facilities anywhere outside of the United States.

Section 2. Compensation.

2.1. Salary. As compensation for the performance of the Executive’s services hereunder, during the Term, the Company shall pay to the Executive a salary at an annual rate of Three Hundred Fifty Thousand Dollars ($350,000), payable in accordance with the Company’s standard payroll policies, as may be adjusted upward by the Board in its discretion (as adjusted, the “Base Salary”).

2.2. Bonus.

(a) Annual Bonus. For each completed fiscal year occurring during the Term, the Executive shall be eligible to receive an annual cash bonus (the “Annual Bonus”). The target Annual Bonus shall be 60% of the Executive’s Base Salary as in effect at the beginning of such fiscal year, the actual Annual Bonus to be based upon such individual and/or Company performance criteria established for each such fiscal year by the Board. For 2005, the Executive will be eligible to receive an Annual Bonus under the 2005 Coffeyville Resources, LLC and Affiliated Companies Performance Based Income Sharing Plan (the “2005 Plan”) with appropriate adjustments to the performance criteria thereunder to reflect the impact, if any, of the transactions contemplated in the Stock Purchase Agreement. Notwithstanding the foregoing, the Executive shall not be eligible for any pro rata bonus upon termination of the Executive’s employment under the 2005 Plan (or any successor plan).

(c) Retention Bonus. The Executive shall be eligible to receive a retention bonus (the “Retention Bonus”), payable in installments of $122,916.67 on each of March 3, 2006 and March 3, 2007.

2.4. Vacation. During the Term, the Executive shall be entitled to paid vacation in accordance with the Company’s vacation policy as in effect on the date hereof.

2.5. Business Expenses. The Company shall pay or reimburse the Executive for all commercially reasonable business out-of-pocket expenses that the Executive

incurs during the Term in performing his duties under this Employment Agreement upon presentation of documentation and in accordance with the expense reimbursement policy of the Company as approved by the Board and in effect from time to time.

Section 3. Employment Termination.

3.1. Termination of Employment. The Company may terminate the Executive’s employment for any reason during the Term, and the Executive may voluntarily terminate his employment for any reason during the Term, in each case (other than a termination by the Company for Cause) at any time upon not less than thirty (30) days’ notice to the other party. Upon the termination of the Executive’s employment with the Company for any reason (whether during the Term or thereafter), the Executive shall be entitled to any Base Salary earned but unpaid through the date of termination, any earned but unpaid Annual Bonus for completed fiscal years, any unpaid installments of the Retention Bonus and any unreimbursed expenses in accordance with Section 2.5 hereof (collectively, the “Accrued Amounts”).

3.2. Certain Terminations.

(a) Termination by the Company Other Than For Cause or Disability; Termination by the Executive for Good Reason. If (i) the Executive’s employment is terminated by the Company during the Term other than for Cause or Disability or (ii) the Executive resigns for Good Reason, in addition to the Accrued Amounts the Executive shall be entitled to the following payments and benefits: (x) the continuation of his Base Salary at the rate in effect immediately prior to the date of termination for a period of eighteen (18) months and (y) the continuation on the same terms as an active employee of medical benefits the Executive would otherwise be eligible to receive as an active employee of the Company for eighteen (18) months or until such time as the Executive becomes eligible for medical benefits from a subsequent employer (such payments, the “Severance Payments”). The Company’s obligations to make the Severance Payments shall be conditioned upon: (i) the Executive’s continued compliance with his obligations under Section 4 of this Employment Agreement and (ii) the Executive’s execution, delivery and non-revocation of a valid and enforceable release of claims arising in connection with the Executive’s employment and termination of employment with the Company and its affiliates (the “Release”) in a form reasonably acceptable to the Company and the Executive. In the event that the Executive breaches any of the covenants set forth in Section 4 of this Employment Agreement, the Executive will immediately return to the Company any portion of the Severance Payments that have been paid to the Executive pursuant to this Section 3.2(a). Subject to Section 3.2(c), the Severance Payments will commence to be paid to the Executive as soon as practicable following the effectiveness of the Release.

(b) Definitions. For purposes of this Section 3.2, the following terms shall have the following meanings:


	COFFEYVILLE RESOURCES, LLC

/s/ Stanley A. Riemann	By:	/s/ John J. Lipinski

Stanley A. Riemann		Name: John J. Lipinski
		Title: CEO


	COFFEYVILLE RESOURCES, LLC

/s/ Kevan A.Vick	By:	/s/ John J. Lipinski

Kevan A.Vick		Name: John J. Lipinski
		Title: CEO


	COFFEYVILLE RESOURCES, LLC

/s/ Kevan A. Vick Kevan A. Vick	By:	/s/ John J. Lipinski Name: John J. Lipinski
		Title: CEO


		If to the Executive:
				Wyatt E. Jernigan
				250 South Post Oak Lane
				Houston, TX 77056


		If to the Executive:

				James T. Rens
				8112 NE 73^rd Terrace
				Kansas City, MO 64158

	(A)		rights of the Employee under this Agreement;

	(B)		the right of the Employee to receive COBRA continuation coverage in accordance with applicable law;

	(C)		claims for benefits under any health, disability, retirement, life insurance or other, similar employee benefit plan (within the meaning of Section 3(3) of ERISA) of the Company Affiliated Group, provided, however, that the Company agrees to cooperate with the timely transfer of the Employee’s 401(k) to a qualified IRA as directed by the Employee; and

	(D)		rights to indemnification the Employee has or may have under the by-laws or certificate of incorporation of any member of the Company Affiliated Group or as an insured under any director’s and officer’s liability insurance policy now or previously in force.


		COFFEYVILLE RESOURCES, LLC

/s/ Philip L. Rinaldi		/s/ Stanley A. Riemann
Philip L. Rinaldi		By: Stanley A. Riemann
		Its: COO


	J. ARON & COMPANY

	By:	/s/ Jeff Fraze
	Name:	Jeff Fraze
	Title:	Managing Director

	COFFEYVILLE RESOURCES REFINING & MARKETING, LLC

	By:	/s/ Stanley A. Riemann
	Name:	Stanley A. Riemann
	Title:	COO


	Flow Date	Invoice Date	Invoice Day	Payment Date	Payment Day
*	31-Dec-06	29-Dec-06	Fri	2-Jan-07	Tue
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*	4-Jan-07	4-Jan-07	Thu	5-Jan-07	Fri
*	5-Jan-07	5-Jan-07	Fri	8-Jan-07	Mon
*	6-Jan-07	5-Jan-07	Fri	8-Jan-07	Mon
	7-Jan-07	8-Jan-07	Mon	9-Jan-07	Tue
	8-Jan-07	9-Jan-07	Tue	10-Jan-07	Wed
	9-Jan-07	10-Jan-07	Wed	11-Jan-07	Thu
	10-Jan-07	11-Jan-07	Thu	12-Jan-07	Fri
*	11-Jan-07	11-Jan-07	Thu	12-Jan-07	Fri
*	12-Jan-07	12-Jan-07	Fri	16-Jan-07	Tue
*	13-Jan-07	12-Jan-07	Fri	16-Jan-07	Tue
*	14-Jan-07	12-Jan-07	Fri	16-Jan-07	Tue
	15-Jan-07	16-Jan-07	Tue	17-Jan-07	Wed
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		TABLE OF CONTENTS
ARTICLE I.		DEFINITIONS

ARTICLE II.		ELECTRIC SERVICE CUSTOMER INFORMATION

ARTICLE III.		PAYMENT SECURITY

ARTICLE IV		ELECTRIC TRANSMISSION

ARTICLE V.		ELECTRIC POWER AND ENERGY

ARTICLE VI.		RATES AND CHARGES

ARTICLE VII.		BILLINGS AND PAYMENTS; TERMINATION OF SERVICE

ARTICLE VIII.		SERVICE CHARACTERISTICS

ARTICLE IX.		ELECTRIC STANDARDS FOR THE FACILITY

ARTICLE X.		METERING

ARTICLE XI.		FORCE MAJEURE

ARTICLE XII.		RIGHTS-OF-WAY AND ACCESS

ARTICLE XIII.		DELIVERY POINTS

ARTICLE XIV.		TERM

ARTICLE XV.		ASSIGNMENT

ARTICLE XVI.		LIABILITY; LEGAL REMEDIES

ARTICLE XVII.		AMENDMENT(S) AND RESERVATION OF POWERS

ARTICLE XVIII.		MOTORS-STARTING PROCEDURES AND ALLOWABLE CURRENTS

ARTICLE XIX.		MISCELLANEOUS


¹		As modified by the Kansas Corporation Commission on Jane 26, 2000, to include that portion of the Facility which originally was situated beyond the City’s Certified Electric Service Territory at the time the City entered into that certain Electric Service Agreement with Farmland Industries, Inc.

	1.1		“AEP” shall mean the American Electric Power Company, Inc., a New York corporation, and the facilities of any electric company division, affiliate, and/or subsidiary of AEP and any purchaser, successor, or transferee of AEP or any of AEP’s division, affiliates and/or subsidiaries.

	1.2		“AEP Charges” shall mean the transmission charges and the ancillary services charges for power and energy transferred through the CSWS Transmission Service Agreement for the Facility, as set forth in Item 2 of the Rate Schedule.

	1.3		“City” shall have the meaning given in the introductory paragraph.

	1.4		“City Certified Electric Service Territory” shall mean the geographic area in which the City has the responsibility and exclusive right to supply retail electric service pursuant to K S A 66-1,170, et seq.

	1.5		“Coffeyville Resources” shall mean Coffeyville Resources Nitrogen Fertilizers, LLC, a limited liability company organized and existing under the laws of the State of Delaware, together with its successors and assigns.

	1.6		“CSWS Transmission Service Agreement” shall mean the “Firm Point to Point Transmission Service Agreement” between the City and Central South West Services, Inc (CSWS subsequently purchased by AEP) attached hereto as Exhibit 1.

	1.7		“Demand” shall mean the rate at which electric energy is delivered expressed in kilowatts, megawatts, or other suitable unit at a given instant.

	1.8		“Demand Charge” shall be that portion of the charge for electric service based upon the electric power (kW or kVA) consumed and billed under the Rate Schedule on the basis of the Demand Reading, taking into account any minimum demand requirement pursuant to the then applicable Power and Energy Supply Contract.

	1.9		“Demand Reading” shall mean the highest or maximum demand for electricity the Facility registers in a given 30 minute interval during each billing period, but not less than forty (40) megawatts except as otherwise provided in the applicable Power and Energy Supply Contract. The Demand Reading, if applicable pursuant to the then existing Power and Energy Supply Contract, sets the Demand Charge for each billing period.

	1.10		“Distribution Facilities” shall mean any electric line used to furnish retail electric service, including any line from a Substation to an electric consuming facility, but such term does not include any transmission facilities (including the Transmission Facilities as defined in this Agreement) There are no Distribution Facilities used to furnish retail electric service to the Facility Delivery Point(s) pursuant to this Agreement.

	1.11		“Effective Date” shall mean that date upon which the sale of assets authorized by that certain Sale Order issued by the United States Bankruptcy Court in the Western District of Missouri on November 14, 2003, in connection with the jointly administered Case No 02-50557-JWV of Farmland Industries, Inc in Bankruptcy Proceedings under Chapter 11, are concluded.

	1.12		“Energy Charge” shall mean that portion of the charge for electric service based upon the electric energy (kWh) consumed or billed under the Rate Schedule, taking into account any minimum energy, load factor, or Energy Lost and Unaccounted For requirement pursuant to the then applicable Power and Energy Supply Contract.

	1.13		“Energy Lost and Unaccounted For” shall mean the difference between total net wholesale energy purchased by the City for the Facility in kilowatt-hours and the sum of kilowatt-hour sales to the Facility.

	1.14		“Facility” shall mean any piece of land or real estate or any building, structure, or improvement or portion thereof that make up the Coffeyville Resources nitrogen fertilizer facility, the associated BOC Air Separation Unit, and any other related facilities or enhancements within the City Certified Electric Service Territory and within the area highlighted on the attached Exhibit 10 that receives or may receive power through the Facility Delivery Point(s) as defined in 1.15.

	1.15		“Facility Delivery Point(s)” shall mean the 13.8 kV metering location(s) in 138/13.8 kV Substation B, as depicted on Exhibit 3, attached hereto.

	1.16		“Force Majeure” shall mean “acts of God,” including but not limited to, flood, earthquake, storm, lightning or fire Force Majeure shall also include labor strikes, slow downs, or walkouts, war, riot, civil disturbance, sabotage, or restraint by a court or public authority, which by the exercise of due diligence and foresight could not reasonably have been avoided Force Majeure shall also include the temporary interruption or reduction in electric service, which, in the reasonable opinion of the City, is necessary to prevent severe system overload, or for the purpose of necessary maintenance, repairs, replacements, or installation of equipment. Except in the case of emergency, the City will give Coffeyville Resources as much prior notice as is reasonably possible of such temporary interruptions or reductions and will perform any necessary, replacements, repairs,

			or installation of equipment in accordance with a mutually agreeable schedule so as to cause the least inconvenience to the City and Coffeyville Resources.

	1.17		“Meter” shall mean any device or devices used to measure or register electric power and energy.

	1.18		“Operation & Maintenance Charges” shall mean the actual City cost of operating, maintaining, repairing, replacing and insuring the Transmission Facilities serving the Facility plus the overhead mark-up, all as set forth in the Rate Schedule.

	1.19		“Payment Security Instrument” shall mean the instrument furnished pursuant to Article III hereof.

	1.20		“Power and Energy Supply Contract” shall mean the City’s July 1, 1999 through December 31, 2002 “Firm Partial Requirements Electric Power and Energy Contract” with the Grand River Dam Authority, as amended on April 9, 2002 to extend the term through December 31, 2007, attached hereto as Exhibit 2, or any subsequent Power and Energy Supply Contracts executed by the City to serve the Facility.

	1.21		“Power Factor” shall mean the ratio of real power (kW) to apparent power (kVA) for any given load and time. Generally, it is expressed as a percentage ratio.

	1.22		“Power Factor Adjustment” shall mean an adjustment in the billing under the Rate Schedule if the Facility’s Power Factor varies from the specified range of percentages set forth herein.

	1.23		“PSO” shall mean the Public Service Company of Oklahoma.

	1.24		“PSO Interconnection Agreement” shall mean the Interconnection Agreement between the City and Public Service Company of Oklahoma (PSO), attached hereto as Exhibit 4.

	1.25		“Rate Schedule” shall mean the schedule, attached hereto as Exhibit A, setting forth the amount to be paid by Coffeyville Resources to the City for electric service.

	1.26		“Substation B” shall mean the 138/13 8 kV Substation as depicted on Exhibit 9, attached hereto.

	1.27		“SWEPCO” shall mean Southwestern Electric Power Company.

	1.28		“Transmission Capacity” shall mean the 90 megawatts of transmission capacity available for the use and benefit of the Facility over the Transmission Facilities and provided by the CSWS Transmission Service Agreement.

	1.29		“Transmission Facilities” shall mean the City owned transmission facilities, inclusive of but not limited to, the two 138 kV transmission lines from the City/PSO Interconnection Point to and including Substation B used for the bulk transfer of energy from the City/PSO interconnection point to the Facility Delivery Point(s), but such term does not include any Distribution Facilities.

	1.30		“Transmission Wheeling Charge” shall mean the wheeling charge to Coffeyville Resources for energy transferred across the transmission system and/or through the CSWS Transmission Service Agreement, as set forth in the Rate Schedule.

	3.1		Coffeyville Resources shall furnish the City with a Payment Security Instrument, which shall be (a) an irrevocable Letter of Credit from a bank or financial institution acceptable to the City, (b) a Payment Security Bond from an insurance company acceptable to the City, (c) such other equivalent instrument or instruments from an entity or entities acceptable to the City, or (d) an interest-bearing, cash collateralized trust account with a financial institution in trust of the City, in each case in the amount of three million dollars ($3,000,000), to cover Coffeyville Resources’ obligations with respect to payment of the minimum Transmission Wheeling Charges and of monthly electric use billings. In the event Coffeyville Resources expands the Facility, and such expansion increases the average monthly electric charges by more than $125,000 per month measured at one hundred twenty (120) day intervals following the expansion, Coffeyville Resources shall increase the amount of the Payment Security Instrument by two (2) times the amount of the average increase.

	3.2		In the event Coffeyville Resources breaches its requirement to make any of the payments or portions thereof as they become due for payment for the charges outlined in Section 3.1 above, and such breach has not been cured or corrected by Coffeyville Resources within ten (10) days after its receipt of written notice by the City to Coffeyville Resources of such breach, all of the remaining aggregate of payments shall immediately become due and payable If said payment is not made by Coffeyville Resources within ten (10) days after its receipt of written notice by the City to Coffeyville Resources as set forth above, then the City will

			make demand for all of the remaining aggregate of payments against the issuer of the Payment Security Instrument.

	3.3		The Payment Security Instrument identified above is attached hereto as Exhibit 5. As of the date of this Agreement, the form of the Payment Security Instrument is in the full amount of $3,000,000 and is acceptable in form to the City for its term thereof.

	3.4		If the Payment Security Instrument furnished pursuant to this Article III expires or is terminated prior to the expiration of the term of this Agreement, then Coffeyville Resources shall furnish a substitute Payment Security Instrument acceptable to the City no later than forty-five (45) days prior to the expiration or termination date of the Payment Security Instrument, or pay the aggregate unpaid balance of the amounts secured and owing. If the full amount owing is not paid in full by Coffeyville Resources or an acceptable substitute Payment Security Instrument is not furnished within thirty-five (35) days prior to the expiration or termination date of the Payment Security Instrument, then the City will make demand for payment due and owing against the issuer of the Payment Security Instrument.

	4.1		Subject to receipt by the City of the Payment Security Instrument required by Article III hereof, the City will have available for the use and benefit of the Facility ninety (90) megawatts of firm Transmission Capacity from the PSO/City Interconnection Point to the Facility Delivery Points and ninety (90) megawatts of Transmission Capacity provided by the CSWS Transmission Service Agreement, throughout the term of this Agreement.

			The City is not obligated to provide in excess of ninety (90) megawatts of Transmission Capacity to Coffeyville Resources for the Facility.

	4.2		If the Facility does not use the full ninety (90) megawatts of Transmission Capacity available for its use, the City may use such capacity to serve any retail customer within the City Certified Electric Service Territory without compensation to Coffeyville Resources However, for any new commercial or industrial customer that individually has a peak demand of 2 megawatts or more, commencing operations subsequent to the date of execution of this Agreement, the City shall provide during the term of this Agreement, a $0.001 (1 mill) rebate to Coffeyville Resources for each kilowatt-hour of energy paid for by such customer that was wheeled across the Transmission Facilities to serve such customer. This rebate is limited to a maximum of $2,500,000 over the life of the Agreement.

	4.3		If the City sells any of the Facility’s unused ninety (90) megawatts of Transmission Capacity to any entity outside of the City Certified Electric Service Territory, the net revenues generated from the sale shall be divided equally between the City and Coffeyville Resources.

	4.4		Any net revenue generated by the City from the transmission of energy across the Transmission Facilities by another power provider to serve retail customers outside of the City Certified Electric Service Territory shall be shared equally with Coffeyville Resources.

	4.5		On or before July 1 of each year throughout the term of this Agreement, Coffeyville Resources shall provide the City a written forecast of estimated Transmission Capacity it intends to use in excess of 60 megawatts during the ensuing calendar year.

	4.6		Coffeyville Resources may not resell any of the Transmission Capacity made available to the Facility under this Agreement on the City’s Transmission Facilities or through the CSWS Transmission Service Agreement.

	4.7		Coffeyville Resources may not use any of the ninety (90) megawatts of Transmission Capacity made available to the Facility under this Agreement on the City’s Transmission Facilities or through the CSWS Transmission Service Agreement for any electric load or service except the Facility, without the written consent of the City as approved by the City’s Governing Body, which consent shall not be unreasonably withheld, and subject to the limitations set forth in the CSWS Transmission Service Agreement and the PSO Interconnection Agreement. In the future, if it becomes legally permissible for Coffeyville Resources to obtain power and energy for its Coffeyville Refinery through the ninety (90) megawatts of Transmission Capacity made available to the Facility on the City’s Transmission Facilities or through the CSWS Transmission Service Agreement, subject to City approval, which approval shall not be unreasonably withheld, and the limitations set forth in the CSWS Transmission Service Agreement and the PSO Interconnection Agreement, Coffeyville Resources shall be allowed to do so under Items 2 and 3 of the Rate Schedule and by payment of any additional cost incurred by the City, inclusive of but not limited to capital investments for additional Transmission and Distribution Facilities if necessary.

	4.8		The City shall not amend any Facility related provisions of the CSWS Transmission Service Agreement that are within the sole control of the City without written concurrence from Coffeyville Resources.

			requirements for the Facility for the time period beginning January 1, 2004 and ending December 31, 2007. Upon receipt of such forecast, the City will use its best efforts in good faith to secure such power and energy, subject to reasonable availability.

	5.2		Thereafter, no later than five (5) months prior to the expiration of any existing Power and Energy Supply Contract, Coffeyville Resources will deliver to the City a written forecast of its estimated monthly power and energy requirements for the Facility for the five (5) year period beginning with the expiration date of the existing Power and Energy Supply Contract.

	5.3		Coffeyville Resources understands and agrees that the cost and any other obligations associated with any Power and Energy Supply Contract for additional power and energy or any subsequent Power and Energy Supply Contract shall be billed to and paid for by Coffeyville Resources under the Rate Schedule.

	5.4		The City’s obligation is limited to the extent that such power and energy are available through a firm Power and Energy Supply Contract(s), which, as provided above, the City shall use its best efforts in good faith to secure following Coffeyville Resources’ delivery of the forecast of estimated power and energy requirements.

	5.5		The City shall use its best effort in good faith to obtain power and energy at the lowest price available delivered to the delivery point(s) on the SWEPCO or PSO systems of CSWS, consistent with the City’s best judgment as to the reliability of the supplier, and upon such other terms and conditions as the City may reasonably require Coffeyville Resources may reject any Power and Energy Supply Contract subsequent to such contract in effect on and as of the Effective Date hereunder, as proposed by the City However, if Coffeyville Resources rejects a Power and Energy Supply Contract as proposed by the City, the City is relieved of any and all obligations and responsibilities to provide power and energy to the Facility until such time that the City and Coffeyville Resources can obtain a Power and Energy Supply Contract agreeable to both parties Further, if Coffeyville Resources rejects a Power and Energy Supply Contract as proposed by the City, such action does not relieve Coffeyville Resources from its obligation and responsibility to pay any and all expenses or payments due or to become due in the future pursuant to this Agreement.

	5.6		The City shall not amend any Facility related provisions of the Power and Energy Supply Contract that are within the sole control of the City without written concurrence from Coffeyville Resources.

	7.1		The City’s electric meters shall normally be read at approximately monthly intervals and bills for electric service shall normally be submitted to Coffeyville Resources on monthly intervals. Whenever it is not possible with reasonable diligence to read a meter for a billing period, the City may submit an estimated bill based upon previous usage and other available information, with the amount of such bill to be subsequently adjusted as necessary when the next actual reading is obtained.

	7.2		The City will mail and fax on the billing date a bill for electric service to the Facility at the address and facsimile number of the Facility, or at such other address and facsimile number designated by Coffeyville Resources pursuant to Article II herein Failure to receive a bill in no way exempts Coffeyville Resources from liability for payment for electric service Each bill will separately set out the AEP Charges due for the month.

			Coffeyville Resources shall remit payment for the AEP Charges by wire transfer of immediately available rands in accordance with the billing instructions on the City’s monthly billing invoices.

	7.3		Charges for electric service shall be due and payable monthly within 15 days after the billing date, and each monthly bill shall have stamped thereon the due date In the event a monthly bill is not paid in full by the due date indicated thereon, an order shall be issued (subject to Section 7.7 hereof) causing the electric service to the Facility to be disconnected, for such nonpayment.

	7.4		Coffeyville Resources shall pay a flat ten (10%) percent of the balance due as a late charge on any delinquent payment.

	7.5		If electric service has been disconnected due to a breach of this Agreement by Coffeyville Resources, re-connection shall occur only upon total payment of the amount past due, any applicable late charge and payment of a reconnection service charge in the amount of Ten Thousand Dollars ($10,000).

	7.6		In the event Coffeyville Resources should offer payment for any monthly electric bill, or portion thereof, by means of a check or order which has not been honored on account of insufficient funds of the maker to pay same, or because the check or order was drawn on a closed account or on a non-existent account, or otherwise dishonored (unless wrongfully dishonored), a check service charge in the amount of Ten Thousand Dollars ($10,000) shall be charged and collected as a service

			charge for proper handling and administration. Provided, in the event two (2) such dishonored checks or orders are made to the City for electric service within any last preceding twelve (12) month period, payment of each monthly electric bill by Coffeyville Resources shall be made and acceptable only by certified or cashier’s check or wire transfer.

	7.7		The City may discontinue electric service to the Facility for any of the reasons set forth below, after written notice stating the reason or reasons for such discontinuance has been given to Coffeyville Resources by delivery in accordance with Section 19.11 and by delivery to the address of the Facility or to such other billing address requested by Coffeyville Resources as shown on the City’s records, and the reason or reasons for such proposed discontinuance have not been cured or corrected by Coffeyville Resources within 10 days after receipt of such notice:

	a)		Non-payment of a bill for electric service;

	b)		Refusal by Coffeyville Resources or its representatives to provide the City reasonable access to its equipment located at the Facility;

	c)		Violation by Coffeyville Resources of any applicable federal, state, city, or regulatory agency laws, rules or regulations covering electrical service or services to the Facility;

	d)		Potential adverse effect of the Facility’s equipment and/or appurtenances on service to other customers;

	e)		Violation of or non-compliance with any provision, of this Agreement for service;

	f)		Failure of Coffeyville Resources to maintain current Payment Security Instruments as required pursuant to these Terms and Conditions of Service, except to the extent payment obligations have been satisfied by realizing through payment from the surety of a Payment Security Instrument or otherwise;

	g)		Failure of Coffeyville Resources to increase the amount of the Payment Security Interest as provided in Article 3; or

	h)		Failure of Coffeyville Resources to either pay the aggregate unpaid balance of the amounts secured and owing or furnish a substitute Payment Security Instrument as provided in Section 3.4.

	a)		Existence of a dangerous or defective condition related to the wiring or equipment at the Facility;

	b)		When a defective condition of wiring or equipment at the Facility results, or is likely to result, in danger to life or property or interference with proper service to others;

	c)		Fraudulent use of electricity; or

	7.9		Coffeyville Resources shall be responsible for all damage to, misuse of, or loss of the City’s property located at the Facility, unless caused by an act of God or the negligence of the City and its agents. Coffeyville Resources shall not authorize anyone to change, remove, or tamper with the City’s property.

	7.10		No regulating or measuring equipment, or other property or equipment owned by the City, wherever situated, whether located at the Facility or elsewhere, shall be tampered with or interfered with for the purpose of adjustment, fraudulent adjustment or otherwise. In the event the City’s electrical equipment has been tampered with, the City will follow the same procedures as for fraudulent use of electricity as outlined in these Terms and Conditions of Service.

	7.11		For the purpose of these Terms and Conditions of Service, the term “Fraudulent Use of Electricity” shall include any unauthorized use of the City’s electric service and facilities by Coffeyville Resources.

	7.12		In the event fraudulent use of electricity or evidence of attempted fraudulent use of electricity is discovered, or where the City’s regulating or measuring equipment or other property has been tampered with, electric service may be discontinued by the City without advance notice to the Facility. Electric service to the Facility will not be resumed until Coffeyville Resources shall have paid all bills including:

	a)		The charge for the estimated amount of electricity fraudulently consumed;

	b)		The cost of replacement or repair of any damaged City equipment; and

	c)		A re-connection charge of Ten Thousand Dollars ($10,000).

	8.1		Service hereunder shall be at alternating current, 3-phase, 4-wire, 60 Hertz, 13.8Y/7.97 kV, 75 MVA with an allowable variation of 10% above or below nominal voltages.

	8.2		The City will use its best efforts in good faith to supply continuous electric service at the Facility Delivery Points. It shall be the responsibility of Coffeyville Resources to install and maintain protective devices, which will protect the Facility’s equipment or process during abnormal service conditions or the failure of part or all of the electric service. The provisions of the latest edition of the National Electrical Code and the National Electric Safety Code shall be considered as the minimum acceptable standard for the protection and safeguarding of persons, wiring and/or equipment of the Facility. In no event will the City be liable for any damages to Coffeyville Resources if the Facility

			equipment or process is not protected or safeguarded in conformity with such minimum code requirements, nor shall the City be liable for any service interruption, irregularities, or any other causes or abnormalities not caused by the sole negligence of the City.

	8.3		In order to make necessary repairs to or replacements in the City’s facilities for supplying electric service, the City reserves the right in accordance with prudent utility practices, without incurring any liability therefor, to suspend service without notice to Coffeyville Resources for such periods as may be reasonably necessary. When conditions permit an attempt will be made to notify Coffeyville Resources of such an outage Insofar as is practicable, any interruption shall be made at a time, which will cause least reasonable inconvenience to the Facility.

	8.4		The City also reserves the right to discontinue service to the Facility without advance notice, when a defective condition of wiring or equipment at the Facility results, or is likely to result, in danger to life or property or interference with proper service to others. Electric service to the Facility will not be resumed until the defective condition has “been remedied to the satisfaction of the City. If such defective condition is the result of tampering with City equipment, the provisions related to the fraudulent use of electricity shall also apply.

	8.5		The City will endeavor at all times to maintain and operate its electrical system with minimal interruption and voltage fluctuations consistent with economically realistic operations and with prudent utility standards of other electric utilities.

	8.6		Whenever high or low voltage problems are suspected the City will check the voltage. If necessary, corrective adjustment to the voltage will be made without delay.

	8.7		Electric service shall be provided to the Facility by two 13.8Y/7.97 kV, 75 MVA services.

	8.8		Coffeyville Resources hereby authorizes agents of the City to enter the Facility at all times for any purpose incidental to the supplying of electric service, including, but not limited to, inspecting the Facility’s equipment and connections; repairing, replacing or removing City property; or tree trimming and tree removal Refusal on the part of Coffeyville Resources to provide reasonable access for the above purposes shall be deemed to be sufficient cause for discontinuance of service.

	8.9		Any and all equipment, apparatus and devices placed or installed, or caused to be placed or installed by the City on or in the Facility’s premises shall be and remain the property of the City, regardless of the mode or manner of annexation or attachment to real property. Upon the termination of this Agreement, the City shall, within a reasonable time, remove such equipment, apparatus, or devices.

	9.1		All of the Facility’s electrical wiring and apparatus connected or to be connected to the City’s Electric Service shall be at Coffeyville Resources’ expense and shall be installed and maintained by Coffeyville Resources in accordance with the National Electrical Code and the National Electrical Safety Code. In the event of a conflict between the National Codes and an applicable municipal code, the latter shall govern. The City reserves the right to refuse to connect to any wiring or apparatus which does not meet these Code requirements and the City may, without advance notice, discontinue service to the Facility when a defective condition of wiring or equipment is discovered at the Facility.

	9.2		Facility electric power wiring, equipment and apparatus shall not produce harmonic currents and voltages which exceed the limitations set forth in IEEE Standard 519-1992 or the latest revision thereof, Recommended Practices and Requirements for Harmonic Control in Electrical Power Systems.

	9.3		If it is determined by the City that remedial action is required to correct an adverse condition produced by the Facility through use of any equipment causing such adverse condition, the City reserves the right, at Coffeyville Resources’ expense, to install any suitable or special equipment on City facilities, or the City may at its option, require Coffeyville Resources to install such equipment reasonably necessary to limit such adverse condition.