have to purchase CO₂ emission reduction credits to reduce our current emissions of CO₂ or to offset increases in CO₂ emissions associated with expansions of our operations.

Compliance with any future legislation or regulation of greenhouse gas emissions, if it occurs, may have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to strict laws and regulations regarding employee and process safety, and failure to comply with these laws and regulations could have a material adverse effect on our results of operations, financial condition and profitability.

We are subject to the requirements of the Occupational Safety and Health Administration, or OSHA, and comparable state statutes that regulate the protection of the health and safety of workers. In addition, OSHA requires that we maintain information about hazardous materials used or produced in our operations and that we provide this information to employees, state and local governmental authorities, and local residents. Failure to comply with OSHA requirements, including general industry standards, process safety standards and control of occupational exposure to regulated substances, could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions if we are subjected to significant fines or compliance costs.

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. We have been operating during a recent period of significant volatility in the refined products industry, and recent growth in the profitability of the nitrogen fertilizer products industry may not continue or could reverse. As a result, our results of operations may be lower than we currently expect and the price of the notes and our common stock may be volatile.

Because we have transferred our nitrogen fertilizer business to a newly formed limited partnership, we may be required in the future to share increasing portions of the cash flows of the nitrogen fertilizer business with third parties and we may in the future be required to deconsolidate the nitrogen fertilizer business from our consolidated financial statements.

In connection with our initial public offering in October 2007, we transferred our nitrogen fertilizer business to a newly formed limited partnership, whose managing general partner is a new entity owned by our controlling stockholders and senior management. Although we currently consolidate the Partnership in our financial statements, over time an increasing portion of the cash flow of the nitrogen fertilizer business will be distributed to our managing general partner if the Partnership increases its quarterly distributions above specified target distribution levels. In addition, if in the future the Partnership elects to pursue a public or private offering of limited partner interests to third parties, the new limited partners will also be entitled to receive cash distributions from the Partnership. This may require us to deconsolidate. Our historical financial statements do not reflect the new limited partnership structure prior to October 24, 2007 or any non-controlling interest that may be issued to the public in connection with a future initial offering of the Partnership and therefore our past financial performance may not be an accurate indicator of future performance.

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

The petroleum and nitrogen fertilizer businesses both have a high concentration of customers. Our four largest customers in the petroleum business represented 44.4%, 36.8% and ~~40.2%~~41.7% of our petroleum sales for the years ended December 31, 2006 and 2007 and the ~~three~~six months ended ~~March 31,~~June 30, 2008, respectively. Further, in the aggregate, the top five ammonia customers of the nitrogen fertilizer business represented 51.9%, 62.1% and ~~68.4%~~69.9% of its ammonia sales for the years ended

December 31, 2006 and 2007 and the ~~three~~six months ended ~~March 31,~~June 30, 2008, respectively, and the top five UAN customers of the nitrogen fertilizer business represented 30.0%, 38.7% and ~~42.4%~~39.9% of

its UAN sales, respectively, for the same periods. Several significant petroleum, ammonia and UAN customers each account for more than 10% of sales of petroleum, ammonia and UAN, respectively. Given the nature of our business, and consistent with industry practice, we do not have long-term minimum purchase contracts with any of our customers. The loss of one or several of these significant customers, or a significant reduction in purchase volume by any of them, could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions.

The petroleum and nitrogen fertilizer businesses may not be able to successfully implement their business strategies, which include completion of significant capital programs.

One of the business strategies of the petroleum and nitrogen fertilizer businesses is to implement a number of capital expenditure projects designed to increase productivity, efficiency and profitability. Many factors may prevent or hinder 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 few years and the large number of capital projects underway in the industry has led to shortages in skilled craftsmen, engineering services and equipment manufacturing. Failure to successfully implement these profit-enhancing strategies may materially adversely affect our business prospects and competitive position. In addition, we expect to execute turnarounds at our refinery every three to four years, which involve numerous risks and uncertainties. These risks include delays and incurrence of additional and unforeseen costs. The next scheduled refinery turnaround will be in 2010. In addition, development and implementation of business strategies for the Partnership will be primarily the responsibility of the managing general partner of the Partnership. The next scheduled turnaround of the nitrogen fertilizer facility is currently expected to occur in the fourth quarter of 2008.

The acquisition strategy of our petroleum business and the nitrogen fertilizer business involves significant risks.

Both our petroleum business and the nitrogen fertilizer business will consider pursuing acquisitions and expansion projects in order to continue to grow and increase profitability. However, acquisitions and expansions involve numerous risks and uncertainties, including intense competition for suitable acquisition targets; the potential unavailability of financial resources necessary to consummate acquisitions and expansions; difficulties in identifying suitable acquisition targets and expansion projects or in completing any transactions identified on sufficiently favorable terms; and the need to obtain regulatory or other governmental approvals that may be necessary to complete acquisitions and expansions. In addition, any future acquisitions may entail significant transaction costs and risks associated with entry into new markets and lines of business. In addition, even when acquisitions are completed, integration of acquired entities can involve significant difficulties, such as:


	•	unforeseen difficulties in the acquired operations and disruption of the ongoing operations of our petroleum business and the nitrogen fertilizer business;

	•	failure to achieve cost savings or other financial or operating objectives with respect to an acquisition;

	•	strain on the operational and managerial controls and procedures of our petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources;

	•	difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies;


	•	assumption of unknown material liabilities or regulatory non-compliance issues;

	•	amortization of acquired assets, which would reduce future reported earnings;


	•	possible adverse short-term effects on our cash flows or operating results; and

	•	diversion of management’s attention from the ongoing operations of our business.

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Failure to manage these acquisition and expansion growth risks could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions. There can be no assurance that we will be able to consummate any acquisitions or expansions, successfully integrate acquired entities, or generate positive cash flow at any acquired company or expansion project.

We are a holding company and depend upon our subsidiaries for our cash flow and cash to make payments on the notes.

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, including payments on the notes, 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, which is the primary obligor under our existing credit facility, is a holding company and its ability to meet its debt service obligations depends on the cash flow of its subsidiaries. The ability of our subsidiaries to make any payments to us will depend on their earnings, the terms of their indebtedness, including the terms of our credit facility, tax considerations and legal restrictions. In particular, our credit facility currently imposes significant limitations on the ability of our subsidiaries to make distributions to us and consequently our ability to pay dividends to our stockholders and make payments on the notes offered hereby. Distributions that we receive from the Partnership will be primarily reinvested in our business rather than distributed to our stockholders. See also “— Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the establishment of cash reserves” and ‘‘— Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time.”

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

As of June 30, 2008, we had total debt outstanding of $508.3 million, ~~$21.5~~$37.4 million in funded letters of credit outstanding and borrowing availability of $91.1 million under our credit facility. After giving effect to this notes offering, we would have had total debt outstanding of $633.3 million ($652.1 million if the underwriters exercise their over-allotment option). 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:


	•	making it more difficult to satisfy obligations to our creditors, including holders of the notes;

	•	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 existing 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, 2007 was $61.1 million. A 1% increase or decrease in the applicable interest rates under our credit facility, using average debt outstanding at ~~March 31,~~June 30, 2008, would correspondingly change our interest expense by approximately ~~$4.9~~$5.2 million per year.

If our credit ratings decline in the future, the interest rates we are charged on debt under our credit facility will increase by up to 0.75%.

In addition to our debt service obligations, our operations require substantial investments on a continuing basis. Our ability to make scheduled debt payments, including payments on the notes, to refinance our obligations with respect to our indebtedness and to fund capital and non-capital expenditures necessary to maintain the condition of our operating assets, properties and systems software, as well as to provide capacity for the growth of our business, depends on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and financial, business, competitive, legal and other factors. In addition, we are and will be subject to covenants contained in agreements governing our present and future indebtedness. These covenants include and will likely include restrictions on certain payments, the granting of liens, the incurrence of additional indebtedness, dividend restrictions affecting subsidiaries, asset sales, transactions with affiliates and mergers and consolidations. Any failure to comply with these covenants could result in a default under our credit facility and the indenture governing the notes. Upon a default, unless waived, the lenders under our credit facility would have all remedies available to a secured lender, and could elect to terminate their commitments, cease making further loans, institute foreclosure proceedings against our or our subsidiaries’ assets, and force us and our subsidiaries into bankruptcy or liquidation. In addition, any defaults under the credit facility, the indenture governing the notes 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 the managing general partner of the Partnership elects to pursue a public or private offering of Partnership interests, we will be required to use our commercially reasonable efforts to amend our credit facility to remove the Partnership as a guarantor. Any such amendment could result in increased fees to us or other onerous terms in our credit facility. In addition, we may not be able to obtain such an amendment on terms acceptable to us or at all.

If the managing general partner of the Partnership elects to pursue a public or private offering of the Partnership, we will be required to obtain amendments to our credit facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Such amendments could be very expensive to obtain. Moreover, any such amendments could result in significant changes to our credit facility’s pricing, mandatory repayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the

managing general partner elects to cause the Partnership to pursue a public or private offering and

gives us at least 90 days written notice. However, we may not be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend our credit facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us.

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 ~~March 31,~~June 30, 2008, approximately ~~42%~~40% of our employees, all of whom work in our petroleum business, 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.

We are subject to the reporting requirements of the Securities Exchange Act of 1934 (the “Exchange Act”) and the corporate governance standards of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”). These requirements may place a strain on our management, systems and resources. The Exchange Act requires that we file annual, quarterly and current reports with respect to our business and financial condition. The Sarbanes-Oxley Act requires that we maintain effective disclosure controls and procedures and internal control over financial reporting. 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 the notes and our common stock.

In April 2008, we concluded that our consolidated financial statements for the year ended December 31, 2007 and the related quarter ended September 30, 2007 contained errors principally related to the calculation of the cost of crude oil purchased by us and associated financial

transactions. As a result of these errors, management concluded that our internal controls were not

adequate to determine the cost of crude oil at September 30, 2007 and December 31, 2007. Specifically, the Company’s policies and procedures for estimating the cost of crude oil and reconciling these estimates to vendor invoices were not effective. Additionally, the Company’s supervision and review of this estimation and reconciliation process was not operating at a level of detail adequate to identify the deficiencies in the process. Management concluded that these deficiencies were material weaknesses in our internal control over financial reporting. Due to these material weaknesses, our management also concluded that we did not maintain effective disclosure controls and procedures as of December 31, 2007.

In order to remediate the material weaknesses described above, our management is in the process of designing, implementing and enhancing controls to ensure the proper accounting for the calculation of the cost of crude oil. These remedial actions include, among other things, (1) centralizing all crude oil cost accounting functions, (2) adding additional layers of accounting review with respect to our crude oil cost accounting and (3) adding additional layers of business review with respect to the computation of our crude oil costs.

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 control systems to allow management to report on, and our independent auditors to audit, our internal control 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 will be required to comply with Section 404 in our annual report for the year ended December 31, 2008 (subject to any change in applicable SEC rules). Furthermore, upon completion of this process, we may identify control deficiencies of varying degrees of severity under applicable SEC and Public Company Accounting Oversight Board (“PCAOB”) rules and regulations that remain unremediated. Although we produce our financial statements in accordance with GAAP, our internal accounting controls may not currently meet all standards applicable to companies with publicly traded securities. 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 control over financial reporting. A “material weakness” is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the annual or interim financial statements will not be prevented or detected on a timely basis.

If 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 control over financial reporting in a timely manner, our independent registered public accounting firm may not be able to certify as to the effectiveness of our internal control over financial reporting pursuant to an audit of our internal control 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 control over financial reporting could result in a decline in the price of the notes and 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 the price of the notes and our common stock may be adversely affected.

We are a “controlled company” within the meaning of the New York Stock Exchange rules and, as a result, qualify for, and are relying 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 New York Stock Exchange rules and may elect not to comply with certain corporate governance requirements of the New York Stock Exchange, 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.

We are relying on all of these exemptions as a controlled company. Accordingly, our stockholders do not have the same protections afforded to stockholders of companies that are subject to all of the corporate governance requirements of the New York Stock Exchange.

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

The costs of complying with regulations relating to the transportation of hazardous chemicals and security associated with the refining and nitrogen fertilizer facilities may have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions. Targets such as refining and chemical manufacturing facilities may be at greater risk of future terrorist attacks than other targets in the United States. As a result, the petroleum and chemical industries have responded to the issues that arose due to the terrorist attacks on September 11, 2001 by starting new initiatives relating to the security of petroleum and chemical industry facilities and the transportation of hazardous chemicals in the United States. Future terrorist attacks could lead to even stronger, more costly initiatives. Simultaneously, local, state and federal governments have begun a regulatory process that could lead to new regulations impacting the security of refinery and chemical plant locations and the transportation of petroleum and hazardous chemicals. Our business or our customers’ businesses could be materially adversely affected by the cost of complying with new regulations.

We may face third-party claims of intellectual property infringement, which if successful could result in significant costs for our business.

There are currently no claims pending against us relating to the infringement of any third-party intellectual property rights. However, in the future we may face claims of infringement that could interfere with our ability to use technology that is material to our business operations. Any litigation of this type, whether successful or unsuccessful, could result in substantial costs to us and diversions of our resources, either of which could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions. 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 could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions.

If licensed technology is no longer available, the refinery and nitrogen fertilizer businesses may be adversely affected.

We have licensed, and may in the future license, a combination of patent, trade secret and other intellectual property rights of third parties for use in our business. If any of these license agreements were to be terminated, licenses to alternative technology may not be available, or may only be available on terms that are not commercially reasonable or acceptable. In addition, any substitution of new technology for currently licensed technology may require substantial changes to manufacturing processes or equipment and may have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions.

Risks Related to the Notes

We may not be able to generate sufficient cash to service all of our indebtedness, including the notes, and may be forced to take other actions to satisfy our obligations under our indebtedness or we may experience a financial failure, which would hinder the receipt of payment on the notes.

Our ability to make scheduled payments or to refinance our debt obligations depends on our financial and operating performance, which is subject to prevailing economic and competitive conditions and to certain financial, business and other factors beyond our control. We cannot assure you that we will maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness, including the notes.

If our cash flows and capital resources are insufficient to fund our debt service obligations, we may be forced to reduce or delay capital expenditures, sell assets or operations, seek additional capital or restructure or refinance our indebtedness, including the notes. We cannot assure you that we would be able to take any of these actions, that these actions would be successful and permit us to meet our scheduled debt service obligations or that these actions would be permitted under the terms of our existing or future debt agreements including our credit agreement and the indenture for the notes. In the absence of such operating results and resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our credit facility restricts our ability to dispose of assets and use the proceeds from the disposition. We may not be able to consummate those dispositions or to obtain the proceeds which we could realize from them and these proceeds may not be adequate to meet any debt service obligations then due.

If we cannot make scheduled payments on our debt, we will be in default and, as a result:


	•	our debt holders could declare all outstanding principal and interest to be due and payable;

	•	the lenders under our credit agreement could terminate their commitments to loan us money and foreclose against the assets securing their borrowings; and

	•	we could be forced into bankruptcy or liquidation, which is likely to result in delays in the payment of the notes and in the exercise of enforcement remedies under the notes.

In addition, provisions under the bankruptcy code or general principles of equity that could result in the impairment of your rights include the automatic stay, avoidance of preferential transfers by a trustee or adebtor-in-possession, limitations of collectability of unmatured interest or attorneys’ fees and forced restructuring of the notes.

We will be dependent on dividends or other distributions from our subsidiaries to make future payments on the notes or to repurchase the notes for cash when required by the holders following a fundamental change.

A portion of the proceeds of this offering will be used to purchase government securities to be deposited into an escrow account for the benefit of the holders of the notes in an amount sufficient to pay the first six scheduled interest payments on the notes. However, our ability to pay the remainder of the interest payments and principal due on the notes or to repurchase the notes for cash when required by the holders following a fundamental change will depend on cash generated from our operating activities, available credit facility borrowings and other capital resources. We are a holding company, and will depend on dividends or other distributions from our subsidiaries to make these payments. Our subsidiaries are separate and distinct legal entities and none of our subsidiaries will guarantee our obligations under, or have any obligation to pay any amounts due on, the notes. Our indirect subsidiary, Coffeyville Resources, LLC, is the primary obligor under our credit facility which contains limitations on the ability of Coffeyville Resources to pay dividends or make other distributions to us. Future borrowings by our subsidiaries could contain additional restrictions or prohibitions on the payment of dividends or other distributions by our subsidiaries to us. ~~In addition, under~~Under applicable law, our subsidiaries could be limited in the amounts that they are permitted to pay us as dividends on their capital stock or otherwise. In addition, we are permitted by the terms of the indenture to spin off all or substantially all of our properties and assets, including our nitrogen fertilizer business, and the spin-off company to which our properties or assets are transferred is not required to become a party to the indenture.

Our obligations under the notes are effectively subordinate to any lenders who have a security interest in our assets and structurally subordinate to all existing and future claims of our subsidiaries’ creditors.

Our obligations under the notes are unsecured (except by the escrow account), but our subsidiaries’ obligations under our credit facility are secured by a security interest in substantially all of their tangible and intangible assets and the capital stock of their existing and future subsidiaries. If any of our subsidiary obligors or guarantors under our credit facilities is declared bankrupt or insolvent, or if there is an event of default under our credit facilities, the lenders could declare all of the funds borrowed thereunder, together with accrued interest, immediately due and payable. If we were unable to repay such indebtedness, the lenders could foreclose on the pledged assets described above to the exclusion of holders of the notes, even if an event of default exists under the indenture governing the notes at such time. Because the notes will not be secured by any of our assets (except for the escrow account) or the equity interests in our subsidiaries or guaranteed by any of our subsidiaries, holders of notes have no claim on any of our subsidiaries or any of their assets. The notes are thus structurally subordinate to all existing and future claims of our subsidiaries’ creditors.

Despite our current indebtedness levels, we and our subsidiaries can still incur substantially more debt, and this could further exacerbate the risks described in this offering memorandum.

We and our subsidiaries may incur substantial additional indebtedness in the future. We will not be restricted under the terms of the notes or the indenture pursuant to which the notes are to be issued from incurring additional indebtedness, including secured debt. In addition, the notes do not require us to achieve or maintain any minimum financial ratios relating to our financial condition or results of operations. Because we are not limited by the terms of the notes, we may recapitalize, incur additional debt and take a number of other actions that could have the effect of diminishing our ability to make payments on the notes when due. In addition, we are not restricted from repurchasing common stock or paying dividends to our stockholders by the terms of the notes.

Although a pledge of our interest in the escrow account will secure the initial six interest payments on the notes, the ability of holders of notes to enforce their security will be delayed if we become the subject of a case under the U.S. Bankruptcy Code.

The pledge of our interest in the escrow account is intended to secure the first six interest payments on the notes. If we become the subject of a case under the U.S. Bankruptcy Code, however, the ability of holders of the notes to enforce their security interest in the escrow account and receive payment in respect of the government securities would be delayed by the imposition of the automatic stay under Section 362 of the Bankruptcy Code. Any resulting delay could be for a substantial period of time.

We may be unable to repurchase the notes for cash when required by the holders following a fundamental change or to pay the cash amount upon conversion.

Holders of the notes have the right to require us to repurchase the notes for cash upon the occurrence of a fundamental change prior to maturity. In addition, upon conversion of the notes, we may elect, including by making an irrevocable net share settlement election, to settle a conversion, in full or in part, by paying cash. We may not have sufficient funds to make the required payments in cash at such time or the ability to arrange necessary financing on acceptable terms. We may also be prohibited from making cash payments under the terms of our then existing credit facilities. If we fail to repurchase the notes or make any payments due upon conversion when required by the indenture, it would constitute an event of default under the indenture governing the notes.

Any adjustment to the ~~base~~ conversion rate in connection with a make-whole fundamental change may not adequately compensate you for the lost option time value of your notes as a result of such transaction.

If any transaction that constitutes a make-whole fundamental change occurs, we will increase the ~~base~~ conversion rate, for the time period described herein, by a number of additional shares for any conversions of notes in connection with such transaction. The number of additional shares will be determined based on the earliest of the date on which such make-whole fundamental change is publicly announced, occurs, or becomes effective and based on the price paid per share of our common stock in connection with the make-whole fundamental change. See “Description of the Notes — Conversion Rights — Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change” for the definition of “make-whole fundamental change.” Although the number of additional shares is designed to compensate you for the lost option time value of your notes as a result of such transaction, the make whole amount is only an approximation of such lost value and may not adequately compensate you for such loss. In addition, if the price of our common stock on the conversion date is less than $ or greater than $ , the ~~base~~ conversion rate will not be increased. In addition, in no event will the total number of shares of common stock issuable upon conversion exceed per $1,000 principal amount of notes, as applicable, subject to adjustments in the same manner as to the ~~base~~ conversion rate as set forth under “Description of the Notes — Conversion Rights — ~~Base~~ Conversion Rate Adjustments.” Our obligation to increase the ~~base~~ conversion rate in connection with a make-whole fundamental change could be considered a penalty, in which case the enforceability thereof would be subject to general principles of equity as they relate to economic remedies.

Some significant restructuring transactions may not constitute a fundamental change, in which case we would not be obligated to offer to repurchase the notes.

Upon the occurrence of a fundamental change, you will have the right to convert your notes or require us to offer to repurchase the notes. However, the fundamental change provisions will not afford protection to holders of notes in the event of certain transactions. For example, transactions such as leveraged recapitalizations, refinancings, restructurings or acquisitions initiated by us would not constitute a fundamental change requiring us to repurchase the notes or enabling you to convert your notes. See “Description of the Notes — Fundamental Change Permits Holders to Require Us to

~~notes. See “Description of the Notes —~~

Repurchase ~~of Notes at Option of Holder upon Fundamental Change”~~Notes” for the definition of a “fundamental change.” In the event of any such transaction, the holders would not have the right to convert their notes or require us to repurchase their notes, even though each of these transactions could increase the amount of our debt, or otherwise adversely affect our capital structure or any credit ratings, thereby adversely affecting the holders of notes.

We are permitted by the terms of the indenture to spin off all or substantially all of our properties and assets.

We are permitted by the terms of the indenture to spin off all or substantially all of our properties and assets, including our nitrogen fertilizer business, provided that we make certain arrangements and take certain actions. See “Description of the Notes — Consolidation, Merger and Sale of Assets.” Such a spin-off transaction would constitute a fundamental change that permits holders of the notes to require us to repurchase notes. We may not have sufficient funds to repurchase notes tendered in cash at such time or the ability to arrange necessary financing on acceptable terms. In addition, such a spin-off transaction would constitute a conversion event and holders of the notes would be entitled to receive ownership units of the spin-off company to which our properties or assets were transferred that are freely tradable without restriction under the Securities Act. Under the indenture governing the notes, the spin-off company is not required to become a party to the indenture. As a result, if ownership units of the spin-off company were not delivered as required under the indenture or were not freely tradable under the securities laws, holders could seek to enforce the indenture against us but not against the spin-off company. We have no current plans to spin off all or substantially all of our properties and assets, including our nitrogen fertilizer business, but we may elect to do so during the life of the notes.

Provisions of the notes could discourage an acquisition of us by a third party.

Upon the occurrence of a fundamental change, holders of the notes will have the right, at their option, to require us to repurchase all or any portion of the principal amount of their notes. In addition, if a holder of notes elects to convert its notes in connection with a make-whole fundamental change, we may be required to increase the ~~base~~ conversion rate by a specified additional number of shares of common stock. These provisions may make it more difficult or more expensive for a third party to acquire us or delay or prevent a takeover of our company and the removal of incumbent management that might otherwise be beneficial to investors. If we are prohibited from repaying or repurchasing the notes by any future credit facilities or debt instruments we may enter into, we could try to obtain the consent of lenders under those credit facilities, or we could attempt to refinance the borrowings that contain the restrictions. If we do not obtain the necessary consents or refinance the borrowings, we will be unable to repay or repurchase the notes. Any such failure would constitute an event of default under the indenture which could, in turn, constitute a default under the terms of our indebtedness.

The conditional conversion feature of the notes could result in your receiving less than the value of the common stock into which a note is convertible.

Prior to , 2013, the notes are convertible into our common stock only if specified conditions are met. If these conditions are not met, you will not be able to convert your notes, and you may not be able to receive the value of the common stock into which the notes would otherwise be convertible.

We have made only limited covenants in the indenture for the notes, and these limited covenants may not protect your investment.

The indenture for the notes does not:


	•	require us to maintain any financial ratios or specific levels of net worth, revenues, income, cash flows or liquidity and, accordingly, does not protect holders of the notes in the event that we experience significant adverse changes in our financial condition or results of operations;

	•	limit our subsidiaries’ ability to incur indebtedness which would be structurally senior to the notes;


	•	limit our ability to incur secured indebtedness or indebtedness that is equal in right of payment to the notes;

	•	restrict our subsidiaries’ ability to issue securities that would be senior to the equity interests of our subsidiaries held by us;

	•	restrict our ability to repurchase our common securities or any other securities from time to time;

	•	restrict our ability to pledge our assets or those of our subsidiaries; or

	•	restrict our ability to make investments or to pay dividends or make other payments in respect of our common stock or other securities ranking junior to the notes.

The trading prices for the notes will be directly affected by the trading prices for our common stock, which are impossible to predict. Volatility in the market price of our common stock could result in a lower trading price than your conversion or purchase price and could adversely affect the trading price of the notes.

The stock market in recent years has experienced significant price and volume fluctuations that have often been unrelated to the operating performance of companies. The decrease in the market price of our common stock would likely adversely impact the trading price of the notes. The price of our common stock could be affected by possible sales of our common stock by investors who view the notes as a more attractive means of equity participation in us and by hedging or arbitrage trading activity that may develop involving our common stock. The hedging or arbitrage could, in turn, affect the trading prices of the notes.

If you hold notes, you will not be entitled to any rights with respect to our common stock, but you will be subject to all changes made with respect to our common stock.

If you hold notes, you will not be entitled to any rights with respect to our common stock (including, without limitation, voting rights and rights to receive any dividends or other distributions on our common stock), but you will be subject to all changes affecting our common stock. You will have rights with respect to our common stock only if you convert your notes, which you are permitted to do only in limited circumstances described herein. For example, in the event that an amendment is proposed to our amended and restated certificate of incorporation or bylaws requiring shareholder approval and the record date for determining the shareholders of record entitled to vote on the amendment occurs prior to delivery of our common stock to you, you will not be entitled to vote on the amendment, although you will nevertheless be subject to any changes in the powers, preferences or special rights of our common stock. In addition, because of the net share settlement feature of the notes, you may not receive any shares upon conversion.

The ~~base~~ conversion rate ~~and incremental share factor~~ may not be adjusted for all dilutive events, including third-party tender or exchange offers, that may adversely affect the trading price of the notes or the common stock issuable upon conversion of the notes.

The ~~base~~ conversion rate ~~and incremental share factor are~~is subject to adjustment upon certain events, including the issuance of stock dividends on our common stock, the issuance of certain rights or warrants, distributions of capital stock, debt or assets, cash dividends and certain tender or exchange offers by us or one of our subsidiaries as described under “Description of the Notes — Conversion Rights — ~~Base~~ Conversion Rate Adjustments.” The ~~base~~ conversion rate ~~and incremental share factor~~ will not be adjusted for certain other events, such as third-party tender or exchange offers or an issuance of common stock for cash, that may adversely affect the trading price of the notes or our common stock issuable upon conversion of the notes. There can be no assurance that an event that adversely affects the value of the notes, but does not result in an adjustment to the ~~base~~ conversion rate, ~~and incremental share factor,~~ will not occur.

Conversion of the notes will dilute the ownership interest of existing shareholders, including holders who had previously converted their notes.

To the extent we issue common stock upon conversion of the notes, the conversion of some or all of the notes will dilute the ownership interests of existing shareholders. Any sales in the public market of the common stock issuable upon such conversion could adversely affect prevailing market prices of our common stock. In addition, the existence of the notes may encourage short selling by market participants because the conversion of the notes could depress the price of our common stock.

Shares eligible for future sale, including shares issued upon the conversion of the notes offered hereby into shares of our common stock, may cause the price of our common stock, and therefore of the notes, 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, and therefore the market price of the notes offered hereby, which are convertible into common stock, to decline. This could also impair our ability to raise additional capital through the sale of our equity securities or additional convertible debt securities. Under our amended and restated certificate of incorporation, we are authorized to issue up to 350,000,000 shares of common stock, of which 86,141,291 shares of common stock were outstanding as of ~~the date of this prospectus.~~August 14, 2008. Of these shares, the 23,000,000 shares of common stock sold in our initial public offering and the 27,100 shares of common stock granted to our non-executive officer employees in connection with our initial public offering and registered pursuant to a Registration Statement onForm S-8 filed with the SEC on October 24, 2007 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. Further, shares of our common stock are reserved for issuance on the exercise of stock options and on conversion of the convertible notes offered hereby.

As of ~~the date of this prospectus,~~August 14, 2008, Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC own collectively 62,866,720 shares of our common stock. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC each have demand and piggyback registration rights with respect to these shares. In connection with the offering, our directors and executive officers will enter into lock up agreements, pursuant to which they will agree, subject to certain exceptions, not to sell or transfer, directly or indirectly, any shares of our common stock for a period of 90 days from the date of this prospectus, subject to extension in certain circumstances.

Upon conversion of the notes, unless we elect to deliver solely shares of our common stock in respect of our conversion obligation, we will pay cash in respect of a specified portion of our conversion obligation.

Unless we elect to deliver solely shares of our common stock in respect of our conversion obligation, we will satisfy our conversion obligation to holders by paying cash in respect of a specified portion of our conversion obligation. Accordingly, upon conversion of a note, you may not receive any shares of our common stock, or you may receive fewer shares of common stock relative to the conversion value of the note. As a result, upon conversion of the notes, you may receive less proceeds than expected because the value of our common stock may decline (or not appreciate as much as you may expect) between the day that you exercise your conversion right and the day the conversion value of your notes is finally determined. Even if we elect to settle conversions solely in shares of our common stock, there will be a delay between the time that you elect to convert and the time that we deliver such shares, and you may receive less value than you expected because the value of our common stock may decline (or fail to appreciate as much as you may expect) between the day that you exercise your conversion right and the day on which we settle our conversion obligation. See “Description of the Notes — Conversion Rights — Settlement upon Conversion.”

In the event of a default, we may have insufficient funds to make any payments due on the notes.

Our failure to convert the notes into cash, common stock or a combination of cash and common stock upon exercise of a holder’s conversion right in accordance with the provisions of the indenture

pursuant to which the notes are issued would constitute a default under such indenture. In addition, a default under the indenture could lead to a default under existing and future agreements governing our indebtedness. If, due to a default, the repayment of related indebtedness were to be accelerated after any applicable notice or grace periods, we may not have sufficient funds to repay such indebtedness and the notes.

The notes are not rated.

We do not intend to seek a rating on the notes. However, if one or more rating agencies rates the notes and assigns the notes a rating lower than the rating expected by investors, or reduces their rating in the future, the market price of the notes and our common stock could be harmed.

You should consider the U.S. federal income tax consequences of owning the notes.

The U.S. federal income tax treatment of the conversion of the notes into a combination of our common stock and cash is uncertain. You are urged to consult your tax advisors with respect to the U.S. federal income tax consequences resulting from the conversion of the notes into a combination of cash and common stock. A discussion of the U.S. federal income tax consequences of ownership of the notes is contained in this prospectus under the heading “Material United States Federal Income Tax Considerations.”

You may be subject to tax upon a change in the ~~applicable~~ conversion rate of the notes even though you do not receive a corresponding cash distribution.

The ~~base~~ conversion rate of the notes is subject to adjustment in certain circumstances, including the payment of certain cash dividends. If the ~~base~~ conversion rate is adjusted as a result of a distribution that is taxable to our common stockholders, such as in the case of a cash dividend, you will be deemed to have received a taxable dividend to the extent of our earnings and profits that will be subject to U.S. federal income tax without the actual receipt of any cash. If you are aNon-U.S. Holder (as that term is defined in “Material United States Federal Income Tax Considerations”), such deemed dividend may be subject to U.S. federal withholding tax at a 30% rate, or such lower rate as may be specified by an applicable treaty, which may be set off against subsequent payments on the notes. See “Description of the Notes — Conversion Rights — ~~Base~~ Conversion Rate Adjustments” and “Material United States Federal Income Tax Considerations.”

Any change in the applicable conversion rate as a result of the price of shares of our common stock exceeding the base conversion price may also be treated as a distribution subject to U.S. federal income tax as a dividend. In addition, ifIf a make-whole fundamental change occurs on or prior to the maturity date of the notes, under some circumstances, we will increase the ~~base~~ conversion rate for notes in connection with the make-whole fundamental change. Such increase may be treated as a distribution subject to U.S. federal income tax as a dividend. See “Material United States Federal Income Tax Considerations.”

The accounting for the convertible notes will result in our having to recognize interest expense significantly more than the stated interest rate of the convertible notes in our financial statements after the start of our fiscal year beginning on January 1, 2009.

Under the current accounting rules, for the purpose of calculating diluted earnings per share, a net share settled convertible security meeting certain requirements is accounted for in a manner similar to nonconvertible debt, with the stated coupon constituting interest expense and any shares issuable upon conversion of the security being accounted for in a manner similar to the treasury stock method. The effect is of this method is that the shares potentially issuable upon conversion of the securities are not included in the calculation of earnings per share until the conversion price is “in the money,” and the issuer is then assumed to issue the number of shares necessary to settle the conversion.

However, the Financial Accounting Standards Board (“FASB”) recently posted FASB Staff Position (“FSP”) No. APB14-1 “Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlements)” (previously FSP APB14-a), which will

change the accounting treatment for net share settled convertible securities. Under the final FSP, cash settled convertible securities will be separated into their debt and equity components. The value assigned to the debt component will be the estimated fair value, as of the issuance date, of a similar

debt instrument without the conversion feature, and the difference between the proceeds for the convertible debt and the amount reflected as a debt liability will be recorded as additional paid-in capital. As a result, the debt will be recorded at a discount reflecting its below market coupon interest rate. The debt will subsequently be accreted to its par value over its expected life, with the rate of interest that reflects the market rate at issuance being reflected on the income statement. This change in methodology will affect the calculations of net income and earnings per share for many issuers of cash settled convertible securities.

There is currently no trading market for the notes, and an active trading market for the notes may not develop or, if it develops, may not be maintained.

The notes are new securities for which there is currently no existing trading market. We do not intend to apply for listing of the notes on any securities exchange or for quotation of the notes on any automated dealer quotation system. An active trading market may not develop for the notes and, even if one develops, such market may not be maintained. If an active trading market for the notes does not develop or is not maintained, the market price and liquidity of the notes are likely to be adversely affected and holders may not be able to sell their notes at desired times and prices or at all. If any of the notes are traded after their purchase, they may trade at a discount from their purchase price.

The liquidity of the trading market, if any, and future trading prices of the notes will depend on many factors, including, among other things, the market price of our common stock, prevailing interest rates, our financial condition, results of operations, business, prospects and credit quality relative to our competitors, the market for similar securities and the overall securities market, and may be adversely affected by unfavorable changes in any of these factors, some of which are beyond our control and others of which would not affect debt that is not convertible into capital stock. Historically, the market for convertible debt has been volatile. Market volatility could materially and adversely affect the notes, regardless of our financial condition, results of operations, business, prospects or credit quality.

The notes have a number of features that may adversely affect their value and trading price, including conversion conditions and the lack of financial covenants. Furthermore, even if the conversion conditions are met, since the conversion value of the notes is dependent on the price of our common stock, volatile or depressed market prices for our common stock are likely to have a similar effect on the trading prices of the notes. We cannot assure you that the price of our common stock in the future will not have an adverse effect on the trading prices of the notes.

The notes will initially be held in book-entry form and, therefore, you must rely on the procedures and the relevant clearing systems to exercise your rights and remedies.

Unless and until certificated notes are issued in exchange for book-entry interests in the notes, owners of the book-entry interests will not be considered owners or holders of notes. Instead, DTC, or its nominee, will be the sole holder of the notes. Payments of principal, interest and other amounts owing on or in respect of the notes in global form will be made to the paying agent, which will make payments to DTC. Thereafter, such payments will be credited to DTC participants’ accounts that hold book-entry interests in the notes in global form and credited by such participants to indirect participants. Unlike holders of the notes themselves, owners of book-entry interests will not have the direct right to act upon our solicitations for consents or requests for waivers or other actions from holders of the notes. Instead, if you own a book-entry interest, you will be permitted to act only to the extent you have received appropriate proxies to do so from DTC or, if applicable, a participant. We cannot assure you that procedures implemented for the granting of such proxies will be sufficient to enable you to vote on any requested actions on a timely basis.

Risks Related to Our Common Stock

If our stock price fluctuates, investors could lose a significant part of their investment.

The market price of our common stock may be influenced by many factors including:


	•	the failure of securities analysts to cover our common stock 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 price at which they purchase our common stock. Investors in the notes offered hereby may not be able to resell the notes or common stock issuable upon conversion of the notes at expected prices. 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, and therefore of the notes, regardless of our operating performance.

The Goldman Sachs Funds and the Kelso Funds 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.

As of ~~the date of this prospectus,~~August 14, 2008, each of the Goldman Sachs Funds and the Kelso Funds controls 36.5% of our outstanding common stock (together, they control 73% of our outstanding common stock). Due to their equity ownership, the Goldman Sachs Funds and the Kelso Funds are 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 also have sufficient voting power to amend our organizational 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 entered into commodity derivative contracts (swap agreements) with J. Aron for the period from July 1, 2005 to June 30, 2010. In addition, Goldman Sachs Credit Partners, L.P. is the joint lead arranger for our credit facility. 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. Under the terms of our certificate of incorporation, the Goldman Sachs Funds and the Kelso Funds have no obligation to offer us corporate opportunities. See “Description of Capital Stock — Corporate Opportunities.”

Other conflicts of interest may arise between our principal stockholders and us because the Goldman Sachs Funds and the Kelso Funds control the managing general partner of the Partnership which holds the nitrogen fertilizer business. The managing general partner manages the operations of the Partnership (subject to our rights to participate in the appointment, termination and compensation of the chief executive officer and chief financial officer of the managing general partner and our other specified joint management rights) and also holds IDRs which, over time, entitle the managing general partner to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases the amount of distributions. Although the managing general partner has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and us (as a holder of special units in the Partnership), the fiduciary duty is limited by the terms of the partnership agreement and the directors and officers of the managing general partner also have a fiduciary duty to manage the managing general partner in a manner beneficial to the owners of the managing general partner. The interests of the owners of the managing general partner may differ significantly from, or conflict with, our interests and the interests of the noteholders and our stockholders.

Under the terms of the Partnership’s partnership agreement, the Goldman Sachs Funds and the Kelso Funds have no obligation to offer the Partnership business opportunities. The Goldman Sachs Funds and the Kelso Funds may pursue acquisition opportunities for themselves that would be otherwise beneficial to the nitrogen fertilizer business and, as a result, these acquisition opportunities would not be available to the Partnership. The partnership agreement provides that the owners of its managing general partner, which include the Goldman Sachs Funds and the Kelso Funds, are permitted to engage in separate businesses that directly compete with the nitrogen fertilizer business and are not required to share or communicate or offer any potential business opportunities to the Partnership even if the opportunity is one that the Partnership might reasonably have pursued. The agreement provides that the owners of our managing general partner will not be liable to the Partnership or any unitholder for breach of any fiduciary or other duty by reason of the fact that such person pursued or acquired for itself any business opportunity.

As a result of these conflicts, the managing general partner of the Partnership may favor its own interestsand/or the interests of its owners over our interests and the interests of our stockholders (and the interests of the Partnership). In particular, because the managing general partner owns the IDRs, it may be incentivized to maximize future cash flows by taking current actions which may be in its best interests over the long term. See “— Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “— Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our stockholders.” In addition, if the value of the managing general partner interest were to increase over time, this increase in value and any realization of such value upon a sale of the managing general partner interest would benefit the owners of the managing general partner, which are the Goldman Sachs Funds, the Kelso Funds and our senior management, rather than our company, the noteholders and our stockholders. Such increase in value could be significant if the Partnership performs well. See “The Nitrogen Fertilizer Limited Partnership.”

Further, decisions made by the Goldman Sachs Funds and the Kelso Funds with respect to their shares of common stock could trigger cash payments to be made by us to certain members of our senior management under the Phantom Unit Plans. Phantom points granted under the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), or the Phantom Unit Plan I, and phantom

points that we granted under the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II), or the Phantom Unit Plan II, represent a contractual right to receive a cash payment when payment is made in respect of certain profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Definitions of the terms phantom points, Phantom Unit Plan I and Phantom Unit Plan II are contained in the section of this prospectus entitled “Glossary of Selected Terms.” If either the Goldman Sachs Funds or the Kelso Funds sell any of the shares of common stock of CVR Energy which they beneficially own through Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, they may then cause Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, to make distributions to their members in respect of their profits interests. Because payments under the Phantom Unit Plans are triggered by payments in respect of profit interests under the Coffeyville Acquisition LLC Agreement and Coffeyville Acquisition II LLC Agreement, we would therefore be obligated to make cash payments under the Phantom Unit Plans. This could negatively affect our cash reserves, which could have a material adverse effect our results of operations, financial condition and cash flows. We estimate that any such cash payments should not exceed ~~$41~~$37 million, assuming all of the shares of our common stock held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at ~~$16.04~~$14.31 per share, which was the closing price of our common stock on ~~July 15,~~August 14, 2008.

In addition, one of the Goldman Sachs Funds and one of the Kelso Funds have each guaranteed 50% of our payment obligations under the Cash Flow ~~Swap in~~Swap. We entered into a letter agreement with J. Aron on July 29, 2008 to defer until December 15, 2008 the ~~amount~~payment of $87.5 million of the $123.7 million plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008) we owe to J. Aron. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at our option). ~~These payments under~~If we consummate this notes offering before December 15, 2008, the ~~Cash Flow Swap are due in August 2008. We are in the process of negotiating a deferral of~~ $87.5 million ~~of these amounts owed~~deferral will automatically extend to ~~J. Aron until~~ July 31, 2009. ~~We cannot assure you that the new deferral agreement will be consummated.~~ The guarantee provided by one of the Goldman Sachs Funds and one of the Kelso Funds will remain in effect until the expiration of this new ~~deferral, if it is consummated.~~deferral. As a result of these guarantees, the Goldman Sachs Funds and the Kelso Funds may have interests that conflict with those of the noteholders and our other shareholders.

Since June 24, 2005, we have made two cash distributions to the Goldman Sachs Funds and the Kelso Funds. One distribution, in the aggregate amount of $244.7 million, was made in December 2006. In addition, in October 2007, we made a special dividend to the Goldman Sachs Funds and the Kelso Funds in an aggregate amount of approximately $10.3 million, which they contributed to Coffeyville Acquisition III LLC in connection with the purchase of the managing general partner of the Partnership from us.

As a result of these relationships, including their ownership of the managing general partner of the Partnership, the interests of the Goldman Sachs Funds and the Kelso Funds may not coincide with the interests of our company, the noteholders 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. In addition, so long as the Goldman Sachs Funds and the Kelso Funds continue to control the managing general partner of the Partnership, they will be able to effectively control actions taken by the Partnership (subject to our specified joint management rights), which may not be in our interests or the interest of our stockholders. See “Certain Relationships and Related Party Transactions.”

Risks Related to the Limited Partnership Structure Through Which
We Hold Our Interest in the Nitrogen Fertilizer Business

Because we neither serve as, nor control, the managing general partner of the Partnership, the managing general partner may operate the Partnership in a manner with which we disagree or which is not in our interest.

CVR GP, LLC or Fertilizer GP, which is owned by our controlling stockholders and senior management, is the managing general partner of the Partnership which holds the nitrogen fertilizer business. The managing general partner is authorized to manage the operations of the nitrogen fertilizer business (subject to our specified joint management rights), and we do not control the managing general partner. Although our senior management also serves as the senior management of Fertilizer GP, in accordance with a services agreement among us, Fertilizer GP and the Partnership, our senior management operates the Partnership under the direction of the managing general partner’s board of directors and Fertilizer GP has the right to select different management at any time (subject to our joint right in relation to the chief executive officer and chief financial officer of the managing general partner). Accordingly, the managing general partner may operate the Partnership in a manner with which we disagree or which is not in the interests of our company and our noteholders or stockholders.

Our interest in the Partnership currently gives us defined rights to participate in the management and governance of the Partnership. These rights include the right to approve the appointment, termination of employment and compensation of the chief executive officer and chief financial officer of Fertilizer GP, not to be exercised unreasonably, and to approve specified major business transactions such as significant mergers and asset sales. We also have the right to appoint two directors to Fertilizer GP’s board of directors. However, we will lose the rights listed above if we fail to hold at least 15% of the units in the Partnership.

The amount of cash the nitrogen fertilizer business has available for distribution to us depends primarily on its cash flow and not solely on its profitability. If the nitrogen fertilizer business has insufficient cash to cover intended distribution payments, it would need to reduce or eliminate distributions to us or, to the extent permitted under agreements governing indebtedness that the nitrogen fertilizer business may incur in the future, fund a portion of its distributions with borrowings.

The amount of cash the nitrogen fertilizer business has available for distribution depends primarily on its cash flow, including working capital borrowings, and not solely on profitability, which will be affected by non-cash items. As a result, the nitrogen fertilizer business may make cash distributions during periods when it records losses and may not make cash distributions during periods when it records net income.

If the nitrogen fertilizer business does not have sufficient cash to cover intended distribution payments, it would either reduce or eliminate distributions or, to the extent permitted to do so under any revolving line of credit or other debt facility that the nitrogen fertilizer business may enter into in the future, fund a portion of its distributions with borrowings. If the nitrogen fertilizer business were to use borrowings under a revolving line of credit or other debt facility to fund distributions, its indebtedness levels would increase and its ongoing debt service requirements would increase and therefore it would have less cash available for future distributions and other purposes, including the funding of its ongoing expenses. This could negatively impact the nitrogen fertilizer business’ financial condition, results of operations, ability to pursue its business strategy and ability to make future distributions. We cannot assure you that borrowings would be available to the nitrogen fertilizer business under a revolving line of credit or other debt facility to fund distributions.

The Partnership may elect not to or may be unable to consummate an initial public offering or one or more private placements. This could negatively impact the value and liquidity of our investment in the Partnership, which could impact the value of the notes and our common stock.

The Partnership may elect not to or may be unable to consummate an initial public offering or an initial private offering. Any public or private offering of interests by the Partnership will be made at the discretion of the managing general partner of the Partnership and will be subject to market conditions and to achievement of a valuation which the Partnership finds acceptable. Although the Partnership filed a registration statement with the SEC in February 2008, the Partnership subsequently requested that the registration statement be withdrawn, and there can be no assurance that the Partnership will file a new registration statement with the SEC in the future. An initial public offering is subject to SEC review of a registration statement, compliance with applicable securities laws and the Partnership’s ability to list Partnership units on a national securities exchange. Similarly, any private placement to a third party would depend on the Partnership’s ability to reach agreement on price and enter into satisfactory documentation with a third party. Any such transaction would also require third party approvals, including consent of our lenders under our credit facility and the swap counterparty under our Cash Flow Swap, which would be very expensive. The Partnership may never consummate any of such transactions on terms favorable to us, or at all. If no offering by the Partnership is ever made, it could impact the value, and certainly the liquidity, of our investment in the Partnership.

If the Partnership does not consummate an initial public offering, the value of our investment in the Partnership could be negatively impacted because the Partnership would not be able to access public equity markets to fund capital projects and would not have a liquid currency with which to make acquisitions or consummate other potentially beneficial transactions. In addition, we would not have a liquid market in which to sell portions of our interest in the Partnership but rather would need to monetize our interest in a privately negotiated sale if we ever wished to create liquidity through a divestiture of our nitrogen fertilizer business. In addition, if the Partnership does not consummate an initial public offering by October 24, 2009, Fertilizer GP can require us to purchase its managing general partner in the Partnership. See “— If the Partnership does not consummate an initial offering by October 24, 2009, Fertilizer GP can require us to purchase its managing general partner interest in the Partnership. We may not have requisite funds to do so.”

We have agreed with the Partnership that we will not own or operate any fertilizer business in the United States or abroad (with limited exceptions).

We have entered into an omnibus agreement with the Partnership in order to clarify and structure the division of corporate opportunities between the Partnership and us. Under this agreement, we have agreed not to engage in the production, transportation or distribution, on a wholesale basis, of fertilizers in the contiguous United States, subject to limited exceptions (fertilizer restricted business). The Partnership has agreed not to engage in the ownership or operation within the United States of any refinery with processing capacity greater than 20,000 bpd whose primary business is producing transportation fuels or the ownership or operation outside the United States of any refinery, regardless of its processing capacity or primary business (refinery restricted business).

With respect to any business opportunity other than those covered by a fertilizer restricted business or a refinery restricted business, we and the Partnership have agreed that the Partnership will have a preferential right to pursue such opportunities before we may pursue them. If the Partnership’s managing general partner elects not to cause the Partnership to pursue the business opportunity, then we will be free to pursue such opportunity. This provision and the non-competition provisions described in the previous paragraph will continue so long as we and certain of our affiliates continue to own 50% or more of the outstanding units of the Partnership.

Our rights to receive distributions from the Partnership may be limited over time.

As a holder of 30,333,333 special units (which may convert into general partnerand/or subordinated general partner units if the Partnership consummates an initial public or private offering, and which we may sell from time to time), we are entitled to receive a quarterly distribution of $0.4313 per unit (or $13.1 million per quarter in the aggregate, assuming we do not sell any of our units) from the Partnership to the extent the Partnership has sufficient available cash after establishment of cash reserves and payment of fees and expenses before any distributions are made in respect of the IDRs. The Partnership is required to distribute all of its cash on hand at the end of each quarter, less reserves established by the managing general partner in its discretion. In addition, the managing general partner, Fertilizer GP, will have no right to receive distributions in respect of its IDRs (i) until the Partnership has distributed all aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 and (ii) for so long as the Partnership or its subsidiaries are guarantors under our credit facility.

However, distributions of amounts greater than the aggregate adjusted operating surplus (as defined under “The Nitrogen Fertilizer Limited Partnership — Cash Distributions by the Partnership — Definition of Adjusted Operating Surplus”) generated through December 31, 2009 will be allocated between us and Fertilizer GP (and the holders of any other interests in the Partnership), and in the future the allocation will grant Fertilizer GP a greater percentage of the Partnership’s cash distributions as more cash becomes available for distribution. After the Partnership has distributed all adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009, if quarterly distributions exceed the target of $0.4313 per unit, Fertilizer GP will be entitled to increasing percentages of the distributions, up to 48% of the distributions above the highest target level, in respect of its IDRs. Therefore, we will receive a smaller percentage of quarterly cash distributions from the Partnership if the Partnership increases its quarterly distributions above the target distribution levels. Because Fertilizer GP does not share in adjusted operating surplus generated prior to December 31, 2009, Fertilizer GP could be incentivized to cause the Partnership to make capital expenditures for maintenance prior to such date, which would reduce operating surplus, rather than for expansion, which would not, and, accordingly, affect the amount of operating surplus generated. Fertilizer GP could also be incentivized to cause the Partnership to make capital expenditures for maintenance prior to December 31, 2009 that it would otherwise make at a later date in order to reduce operating surplus generated prior to such date. In addition, Fertilizer GP’s discretion in determining the level of cash reserves may materially adversely affect the Partnership’s ability to make cash distributions to us.

Moreover, if the Partnership issues common units in a public or private offering, at least 40% (and potentially all) of our special units will become subordinated units. We will not be entitled to any distributions on our subordinated units until the common units issued in the public or private offering and our GP units have received the minimum quarterly distribution (“MQD”) of $0.375 per unit (which may be reduced without our consent in connection with the public or private offering, or could be increased with our consent), plus any accrued and unpaid arrearages in the minimum quarterly distribution from prior quarters. The managing general partner, and not CVR Energy, has authority to decide whether or not to pursue such an offering. As a result, our right to distributions will diminish if the managing general partner decides to pursue such an offering.

The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our noteholders and stockholders.

The managing general partner of the Partnership, Fertilizer GP, is responsible for the management of the Partnership (subject to our specified management rights). Although Fertilizer GP has a fiduciary duty to manage the Partnership in a manner beneficial to the Partnership and holders of interests in the Partnership (including us, in our capacity as holder of special units), the fiduciary duty is specifically limited by the express terms of the partnership agreement and the directors and officers

of Fertilizer GP also have a fiduciary duty to manage Fertilizer GP in a manner beneficial to the owners of Fertilizer GP. The interests of the owners of Fertilizer GP may differ from, or conflict with, our interests and the interests of our noteholders and stockholders. In resolving these conflicts, Fertilizer GP may favor its own interestsand/or the interests of its owners over our interests and the interests of our noteholders and stockholders (and the interests of the Partnership). In addition, while our directors and officers have a fiduciary duty to make decisions in our interests and the interests of our noteholders and stockholders, one of our wholly-owned subsidiaries is also a general partner of the Partnership and, therefore, in such capacity, has a fiduciary duty to exercise rights as general partner in a manner beneficial to the Partnership and its unitholders, subject to the limitations contained in the partnership agreement. As a result of these conflicts, our directors and officers may feel obligated to take actions that benefit the Partnership as opposed to us and our noteholders and stockholders.

The potential conflicts of interest include, among others, the following:


	•	Fertilizer GP, as managing general partner of the Partnership, holds all of the IDRs in the Partnership. IDRs give Fertilizer GP a right to increasing percentages of the Partnership’s quarterly distributions after the Partnership has distributed all adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009, assuming the Partnership and its subsidiaries are released from their guaranty of our credit facility and if the quarterly distributions exceed the target of $0.4313 per unit. Fertilizer GP may have an incentive to manage the Partnership in a manner which preserves or increases the possibility of these future cash flows rather than in a manner that preserves or increases current cash flows.

	•	Fertilizer GP may also have an incentive to engage in conduct with a high degree of risk in order to increase cash flows substantially and thereby increase the value of the IDRs instead of following a safer course of action.

	•	The owners of Fertilizer GP, who are also our controlling stockholders and senior management, are permitted to compete with us or the Partnership or to own businesses that compete with us or the Partnership. In addition, the owners of Fertilizer GP are not required to share business opportunities with us, and our owners are not required to share business opportunities with the Partnership or Fertilizer GP.

	•	Neither the partnership agreement nor any other agreement requires the owners of Fertilizer GP to pursue a business strategy that favors us or the Partnership. The owners of Fertilizer GP have fiduciary duties to make decisions in their own best interests, which may be contrary to our interests and the interests of the Partnership. In addition, Fertilizer GP is allowed to take into account the interests of parties other than us, such as its owners, or the Partnership in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us.

	•	Fertilizer GP has limited its liability and reduced its fiduciary duties under the partnership agreement and has also restricted the remedies available to the unitholders of the Partnership, including us, for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of our ownership interest in the Partnership, we may consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

	•	Fertilizer GP determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, issuances of additional partnership interests and cash reserves maintained by the Partnership (subject to our specified joint management rights), each of which can affect the amount of cash that is available for distribution to us in our capacity as a holder of special units and the amount of cash paid to Fertilizer GP in respect of its IDRs.


	•	Fertilizer GP will also able to determine the amount and timing of any capital expenditures and whether a capital expenditure is for maintenance, which reduces operating surplus, or expansion, which does not. Such determinations can affect the amount of cash that is available for distribution and the manner in which the cash is distributed.

	•	In some instances Fertilizer GP may cause the Partnership to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions, which may not be in our interests.

	•	The partnership agreement permits the Partnership to classify up to $60 million as operating surplus, even if this cash is generated from asset sales, borrowings other than working capital borrowings or other sources the distribution of which would otherwise constitute capital surplus. This cash may be used to fund distributions in respect of the IDRs.

	•	The partnership agreement does not restrict Fertilizer GP from causing the nitrogen fertilizer business to pay it or its affiliates for any services rendered to the Partnership or entering into additional contractual arrangements with any of these entities on behalf of the Partnership.

	•	Fertilizer GP may exercise its rights to call and purchase all of the Partnership’s equity securities of any class if at any time it and its affiliates (excluding us) own more than 80% of the outstanding securities of such class.

	•	Fertilizer GP controls the enforcement of obligations owed to the Partnership by it and its affiliates. In addition, Fertilizer GP decides whether to retain separate counsel or others to perform services for the Partnership.

	•	Fertilizer GP determines which costs incurred by it and its affiliates are reimbursable by the Partnership.

	•	The executive officers of Fertilizer GP, and the majority of the directors of Fertilizer GP, also serve as our directorsand/or executive officers. The executive officers who work for both us and Fertilizer GP, including our chief executive officer, chief operating officer, chief financial officer and general counsel, divide their time between our business and the business of the Partnership. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or the Partnership.

The partnership agreement limits the fiduciary duties of the managing general partner and restricts the remedies available to us for actions taken by the managing general partner that might otherwise constitute breaches of fiduciary duty.

The partnership agreement contains provisions that reduce the standards to which Fertilizer GP, as the managing general partner, would otherwise be held by state fiduciary duty law. For example:


	•	The partnership agreement permits Fertilizer GP to make a number of decisions in its individual capacity, as opposed to its capacity as managing general partner. This entitles Fertilizer GP to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or our affiliates. Decisions made by Fertilizer GP in its individual capacity will be made by the sole member of Fertilizer GP, and not by the board of directors of Fertilizer GP. Examples include the exercise of its limited call right, its voting rights, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to the partnership agreement.

	•	The partnership agreement provides that Fertilizer GP will not have any liability to the Partnership or to us for decisions made in its capacity as managing general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership.


	•	The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that Fertilizer GP or those persons acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal.

	•	The partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unitholders must be on terms no less favorable to the Partnership than those generally provided to or available from unrelated third parties or be “fair and reasonable.” In determining whether a transaction or resolution is “fair and reasonable,” Fertilizer GP may consider the totality of the relationship between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership.

The Partnership has a preferential right to pursue corporate opportunities before we can pursue them.

We have entered into an agreement with the Partnership in order to clarify and structure the division of corporate opportunities between us and the Partnership. Under this agreement, we have agreed not to engage in the production, transportation or distribution, on a wholesale basis, of fertilizers in the contiguous United States, subject to limited exceptions (fertilizer restricted business). In addition, the Partnership has agreed not to engage in the ownership or operation within the United States of any refinery with processing capacity greater than 20,000 barrels per day whose primary business is producing transportation fuels or the ownership or operation outside the United States of any refinery (refinery restricted business).

With respect to any business opportunity other than those covered by a fertilizer restricted business or a refinery restricted business, we have agreed that the Partnership will have a preferential right to pursue such opportunities before we may pursue them. If the managing general partner of the Partnership elects not to pursue the business opportunity, then we will be free to pursue such opportunity. This provision will continue so long as we continue to own 50% of the outstanding units of the Partnership. See “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements — Omnibus Agreement.”

If the Partnership elects to pursue and completes a public offering or private placement of limited partner interests, our voting power in the Partnership would be reduced and our rights to distributions from the Partnership could be materially adversely affected.

Fertilizer GP may, in its sole discretion, elect to pursue one or more public or private offerings of limited partner interests in the Partnership. Fertilizer GP will have the sole authority to determine the timing, size (subject to our joint management rights for any initial offering in excess of $200 million, exclusive of the underwriters’ option to purchase additional limited partner interests, if any), and underwriters or initial purchasers, if any, for such offerings, if any. Any public or private offering of limited partner interests could materially adversely affect us in several ways. For example, if such an offering occurs, our percentage interest in the Partnership would be diluted. Some of our voting rights in the Partnership could thus become less valuable, since we would not be able to take specified actions without support of other unitholders. For example, since the vote of 80% of unitholders is required to remove the managing general partner in specified circumstances, if the managing general partner sells more than 20% of the units to a third party we would not have the right, unilaterally, to remove the general partner under the specified circumstances.

In addition, if the Partnership completes an offering of limited partner interests, the distributions that we receive from the Partnership would decrease because the Partnership’s distributions will have

to be shared with the new limited partners, and the new limited partners’ right to distributions will be superior to ours because at least 40% (and potentially all) of our units will become subordinated units. Pursuant to the terms of the partnership agreement, the new limited partners and Fertilizer GP will have superior priority to distributions in some circumstances. Subordinated units will not be entitled to receive distributions unless and until all common units and any other units senior to the subordinated units have received the minimum quarterly distribution, plus any accrued and unpaid arrearages in the MQD from prior quarters. In addition, upon a liquidation of the Partnership, common unitholders will have a preference over subordinated unitholders in certain circumstances.

If the Partnership does not consummate an initial offering by October 24, 2009, Fertilizer GP can require us to purchase its managing general partner interest in the Partnership. We may not have requisite funds to do so.

If the Partnership does not consummate an initial private or public offering by October 24, 2009, Fertilizer GP can require us to purchase the managing general partner interest. This put right expires on the earlier of (1) October 24, 2012 and (2) the closing of the Partnership’s initial offering. The purchase price will be the fair market value of the managing general partner interest, as determined by an independent investment banking firm selected by us and Fertilizer GP. Fertilizer GP will determine in its discretion whether the Partnership will consummate an initial offering.

If Fertilizer GP elects to require us to purchase the managing general partner interest, we may not have available cash resources to pay the purchase price. In addition, any purchase of the managing general partner interest would divert our capital resources from other intended uses, including capital expenditures and growth capital. In addition, the instruments governing our indebtedness may limit our ability to acquire, or prohibit us from acquiring, the managing general partner interest.

Fertilizer GP can require us to be a selling unit holder in the Partnership’s initial offering at an undesirable time or price.

If Fertilizer GP elects to cause the Partnership to undertake an initial private or public offering, we have agreed that Fertilizer GP may structure the initial offering to include (1) a secondary offering of interests by us or (2) a primary offering of interests by the Partnership, possibly together with an incurrence of indebtedness by the Partnership, where a use of proceeds is to redeem units from us (with aper-unit redemption price equal to the price at which a unit is purchased from the Partnership, net of sales commissions or underwriting discounts) (a “special GP offering”), provided that in either case the number of units associated with the special GP offering is reasonably expected by Fertilizer GP to generate no more than $100 million in net proceeds to us. If Fertilizer GP elects to cause the Partnership to undertake an initial private or public offering, it may require us to sell (including by redemption) a portion, which could be a substantial portion, of our special units in the Partnership at a time or price we would not otherwise have chosen. A sale of special units would result in our receiving cash proceeds for the value of such units, net of sales commissions and underwriting discounts. Any such sale or redemption would likely result in taxable gain to us. See “— Use of the limited partnership structure involves tax risks. For example, the Partnership’s tax treatment depends on its status as a partnership for federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat the Partnership as a corporation for federal income tax purposes or if the Partnership were to become subject to additional amounts of entity-level taxation for state tax purposes, then its cash available for distribution to us would be substantially reduced.”

Our rights to remove Fertilizer GP as managing general partner of the Partnership are extremely limited.

Until October 24, 2012, Fertilizer GP may only be removed as managing general partner if at least 80% of the outstanding units of the Partnership vote for removal and there is a final, non-

appealable judicial determination that Fertilizer GP, as an entity, has materially breached a material provision of the partnership agreement or is liable for actual fraud or willful misconduct in its capacity as a general partner of the Partnership. Consequently, we will be unable to remove Fertilizer GP unless a court has made a final, non-appealable judicial determination in those limited circumstances as described above. Additionally, if there are other holders of partnership interests in the Partnership, these holders may have to vote for removal of Fertilizer GP as well if we desire to remove Fertilizer GP but do not hold at least 80% of the outstanding units of the Partnership at that time.

After October 24, 2012, Fertilizer GP may be removed with or without cause by a vote of the holders of at least 80% of the outstanding units of the Partnership, including any units owned by Fertilizer GP and its affiliates, voting together as a single class. Therefore, we may need to gain the support of other unitholders in the Partnership if we desire to remove Fertilizer GP as managing general partner, if we do not hold at least 80% of the outstanding units of the Partnership.

If the managing general partner is removed without cause, it will have the right to convert its managing general partner interest, including the IDRs, into units or to receive cash based on the fair market value of the interest at the time. If the managing general partner is removed for cause, a successor managing general partner will have the option to purchase the managing general partner interest, including the IDRs, of the departing managing general partner for a cash payment equal to the fair market value of the managing general partner interest. Under all other circumstances, the departing managing general partner will have the option to require the successor managing general partner to purchase the managing general partner interest of the departing managing general partner for its fair market value.

In addition to removal, we have a right to purchase Fertilizer GP’s general partner interest in the Partnership, and therefore remove Fertilizer GP as managing general partner, if the Partnership has not made an initial private offering or an initial public offering of limited partner interests by October 24, 2012.

The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the establishment of cash reserves.

The nitrogen fertilizer business may not have sufficient cash each quarter to enable it to pay the minimum quarterly distribution or any distributions to us. The amount of cash the nitrogen fertilizer business can distribute on its units principally depends on the amount of cash it generates from its operations, which is primarily dependent upon the nitrogen fertilizer business selling quantities of nitrogen fertilizer at margins that are high enough to cover its fixed and variable expenses. The nitrogen fertilizer business’ costs, the prices it charges its customers, its level of production and, accordingly, the cash it generates from operations, will fluctuate from quarter to quarter based on, among other things, overall demand for its nitrogen fertilizer products, the level of foreign and domestic production of nitrogen fertilizer products by others, the extent of government regulation and overall economic and local market conditions. In addition:


	•	The managing general partner of the nitrogen fertilizer business has broad discretion to establish reserves for the prudent conduct of the nitrogen fertilizer business. The establishment of those reserves could result in a reduction of the nitrogen fertilizer business’ distributions.

	•	The amount of distributions made by the nitrogen fertilizer business and the decision to make any distribution are determined by the managing general partner of the Partnership, whose interests may be different from ours. The managing general partner of the Partnership has limited fiduciary and contractual duties, which may permit it to favor its own interests to our detriment.

	•	Although the partnership agreement requires the nitrogen fertilizer business to distribute its available cash, the partnership agreement may be amended.


	•	Any credit facility that the nitrogen fertilizer business enters into may limit the distributions which the nitrogen fertilizer business can make. In addition, any credit facility may contain financial tests and covenants that the nitrogen fertilizer business must satisfy. Any failure to comply with these tests and covenants could result in the lenders prohibiting distributions by the nitrogen fertilizer business.

	•	The actual amount of cash available for distribution will depend on numerous factors, some of which are beyond the control of the nitrogen fertilizer business, including the level of capital expenditures made by the nitrogen fertilizer business, the nitrogen fertilizer business’ debt service requirements, the cost of acquisitions, if any, fluctuations in its working capital needs, its ability to borrow funds and access capital markets, the amount of fees and expenses incurred by the nitrogen fertilizer business, and restrictions on distributions and on the ability of the nitrogen fertilizer business to make working capital and other borrowings for distributions contained in its credit agreements.

If we were deemed an investment company under the Investment Company Act of 1940, applicable restrictions would make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business. We may in the future be required to sell some or all of our partnership interests in order to avoid being deemed an investment company, and such sales could result in gains taxable to the company.

In order not to be regulated as an investment company under the Investment Company Act of 1940, as amended (the “1940 Act”), unless we can qualify for an exemption, we must ensure that we are engaged primarily in a business other than investing, reinvesting, owning, holding or trading in securities (as defined in the 1940 Act) and that we do not own or acquire “investment securities” having a value exceeding 40% of the value of our total assets (exclusive of U.S. government securities and cash items) on an unconsolidated basis. We believe that we are not currently an investment company because our general partner interests in the Partnership should not be considered to be securities under the 1940 Act and, in any event, both our refinery business and the nitrogen fertilizer business are operated through majority-owned subsidiaries. In addition, even if our general partner interests in the Partnership were considered securities or investment securities, we believe that they do not currently have a value exceeding 40% of the fair market value of our total assets on an unconsolidated basis.

However, there is a risk that we could be deemed an investment company if the SEC or a court determines that our general partner interests in the Partnership are securities or investment securities under the 1940 Act and if our Partnership interests constituted more than 40% of the value of our total assets. Currently, our interests in the Partnership constitute less than 40% of our total assets on an unconsolidated basis, but they could constitute a higher percentage of the fair market value of our total assets in the future if the value of our Partnership interests increases, the value of our other assets decreases, or some combination thereof occurs.

We intend to conduct our operations so that we will not be deemed an investment company. However, if we were deemed an investment company, restrictions imposed by the 1940 Act, including limitations on our capital structure and our ability to transact with affiliates, could make it impractical for us to continue our business as contemplated and could have a material adverse effect on our business and the price of the notes and our common stock. In order to avoid registration as an investment company under the 1940 Act, we may have to sell some or all of our interests in the Partnership at a time or price we would not otherwise have chosen. The gain on such sale would be taxable to us. We may also choose to seek to acquire additional assets that may not be deemed investment securities, although such assets may not be available at favorable prices. Under the 1940 Act, we may have only up to one year to take any such actions.

Use of the limited partnership structure involves tax risks. For example, the Partnership’s tax treatment depends on its status as a partnership for federal income tax purposes, as well as it not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat the Partnership as a corporation for federal income tax purposes or if the Partnership were to become subject to additional amounts of entity-level taxation for state tax purposes, then its cash available for distribution to us would be substantially reduced.

The anticipated after-tax economic benefit of the Partnership’s master limited partnership structure depends largely on its being treated as a partnership for U.S. federal income tax purposes. Despite the fact that the Partnership is organized as a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as the Partnership to be treated as a corporation for U.S. federal income tax purposes. If the Partnership proceeds with an initial public offering, current law would require the Partnership to derive at least 90% of its annual gross income for the taxable year of such offering, and in each taxable year thereafter, from specific activities to continue to be treated as a partnership for U.S. federal income tax purposes. The Partnership may find it impossible to meet this 90% qualifying income requirement or may inadvertently fail to meet such income requirement.

To consummate an initial public offering, the Partnership will obtain an opinion of legal counsel that, based upon, among other things, customary representations by the Partnership, the Partnership will continue to be treated as a partnership for U.S. federal income tax purposes following such initial public offering. However, the ability of the Partnership to obtain such an opinion will depend upon a number of factors, including the state of the law at the time the Partnership seeks such an opinion and the specific facts and circumstances of the Partnership at such time. Therefore, there is no assurance that the Partnership will be able to obtain such an opinion and, thus, no assurance that we will be able to realize the anticipated benefits of the Partnership being a master limited partnership.

If the Partnership consummates an offering and we sell units, or our units are redeemed, in a special GP offering, or the Partnership makes a distribution to us of proceeds of the offering or debt financing, such sale, redemption or distribution would likely result in taxable gain to us. We will also recognize taxable gain to the extent that otherwise nontaxable distributions exceed our tax basis in the Partnership. The tax associated with any such taxable gain could be significant.

If an initial public offering is consummated, a subsequent change in the Partnership’s business could cause the Partnership to be treated as a corporation for federal income tax purposes or otherwise subject it to taxation as an entity. The Partnership is considering, and may consider in the future, expanding or entering into new activities or businesses. Gross income from any of these activities or businesses may not count toward satisfaction of the 90% qualifying income requirement for the Partnership to be treated as a partnership rather than as a corporation for U.S. federal income tax purposes.

If the Partnership were to be treated as a corporation for U.S. federal income tax purposes, it would pay U.S. federal income tax on its income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income taxes at varying rates. Because such a tax would be imposed upon the Partnership as a corporation, the cash available for distribution by the Partnership to its partners, including us, would be substantially reduced. In addition, distributions by the Partnership to us would also be taxable to us (subject to the 70% or 80% dividends received deduction, as applicable, depending on the degree of ownership we have in the Partnership) and we would not be able to use our share of any tax losses of the Partnership to reduce taxes otherwise payable by us. Thus, treatment of the Partnership as a corporation could result in a material reduction in our anticipated cash flow and the after-tax return to us.

In addition, if an initial public offering is consummated, the law in effect at that time could change so as to cause the Partnership to be treated as a corporation for U.S. federal income tax purposes or otherwise subject it to entity-level taxation. For example, currently, at the federal level, legislation has been proposed that would eliminate partnership tax treatment for certain publicly traded partnerships.

Although such legislation as currently proposed would not apply to the Partnership, it could be amended prior to enactment in a manner that does apply to the Partnership. At the state level, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Specifically, beginning in 2008, the Partnership is required to pay Texas franchise tax at a maximum effective rate of 0.7% of its gross income apportioned to Texas in the prior year. Imposition of this tax by Texas and, if applicable, by any other state will reduce the Partnership’s cash available for distribution by the Partnership. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could result in a material reduction in our anticipated cash flow and the after-tax return to us.

In addition, the sale of the managing general partner interest of the Partnership to an entity controlled by the Goldman Sachs Funds and the Kelso Funds was made at the fair market value of such general partner interest as of the date of transfer, as determined by our board of directors after consultation with management. Any gain on this sale by us is subject to tax. If the IRS or another taxing authority successfully asserted that the fair market value at the time of sale of the managing general partner interest exceeded the sale price, we would have additional deemed taxable income which could reduce our cash flow and adversely affect our financial results. For example, if the value of the managing general partner interest increases over time, possibly significantly because the Partnership performs well, then in hindsight the sale price might be challenged or viewed as insufficient by the IRS or another taxing authority.

Additionally, when the Partnership issues units to new unitholders or engages in certain other transactions, the Partnership will determine the fair market value of its assets and allocate any unrealized gain or loss attributable to those assets to the capital accounts of the existing partners. As a result of this revaluation and the Partnership’s adoption of the remedial allocation method under Section 704(c) of the Internal Revenue Code (i) new unitholders will be allocated deductions as if the tax basis of the Partnership’s property were equal to the fair market value thereof at the time of the offering, and (ii) we will be allocated “reverse Section 704(c) allocations” of income or loss over time consistent with our allocation of unrealized gain or loss.

Fertilizer GP’s interest in the Partnership and the control of Fertilizer GP may be transferred to a third party without our consent. The new owners of Fertilizer GP may have no interest in CVR Energy and may take actions that are not in our interest.

Fertilizer GP is currently controlled by the Goldman Sachs Funds and the Kelso Funds. The Goldman Sachs Funds and the Kelso Funds collectively beneficially own approximately 73% of our common stock. Fertilizer GP may transfer its managing general partner interest in the Partnership to a third party in a merger or in a sale of all or substantially all of its assets without our consent. Furthermore, there is no restriction in the partnership agreement on the ability of the current owners of Fertilizer GP to transfer their equity interest in Fertilizer GP to a third party. The new equity owner of Fertilizer GP would then be in a position to replace the board of directors (other than the two directors appointed by us) and the officers of Fertilizer GP (subject to our joint rights in relation to the chief executive officer and chief financial officer) with its own choices and to influence the decisions taken by the board of directors and officers of Fertilizer GP. These new equity owners, directors and executive officers may take actions, subject to the specified joint management rights we have as a holder of special GP rights, which are not in our interests or the interests of our noteholders or stockholders. In particular, the new owners may have no economic interest in us (unlike the current owners of Fertilizer GP), which may make it more likely that they would take actions to benefit Fertilizer GP and its managing general partner interest over us and our interests in the Partnership.

CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus contains forward-looking statements. We claim the protection of the safe harbor for forward-looking statements provided in the Private Securities Litigation Reform Act of 1995, Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act. 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;

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

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

	•	losses due to the Cash Flow Swap;

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

	•	losses, damages and lawsuits related to the flood and crude oil discharge;

	•	the failure of our new and redesigned equipment in our facilities to perform according to expectations;

	•	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 potential decline in the price of natural gas, which historically has correlated with the market price for nitrogen fertilizer products;

	•	the cyclical nature of the nitrogen fertilizer business;

	•	adverse weather conditions, including potential floods;

	•	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 propertyand/or injury to the environment and human health and potential increased costs relating to transport of ammonia;

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

	•	the reliance of the nitrogen fertilizer business on third-party providers of transportation services and equipment;

	•	environmental laws and regulations affecting the end-use and application of fertilizers;


	•	a decrease in ethanol production;

	•	the potential loss of the nitrogen fertilizer business’ transportation cost advantage over its competitors;

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

	•	our commodity derivative activities;

	•	uncertainty regarding our ability to recover costs and losses resulting from the flood and crude oil discharge;


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


	•	our dependence on significant customers;

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

	•	the success of our acquisition and expansion strategies;

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

	•	our significant indebtedness;

	•	whether we will be able to amend our credit facility on acceptable terms if the Partnership seeks to consummate a public or private offering;

	•	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;

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

	•	the Partnership’s ability to make distributions equal to the minimum quarterly distribution or any distributions at all;

	•	the possibility that Partnership distributions to us will decrease if the Partnership issues additional equity interests and that our rights to receive distributions will be subordinated to the rights of third party investors;

	•	the possibility that we will be required to deconsolidate the Partnership from our financial statements in the future;

	•	the Partnership’s preferential right to pursue certain business opportunities before we pursue them;

	•	reduction of our voting power in the Partnership if the Partnership completes a public offering or private placement;


	•	whether we will be required to purchase the managing general partner interest in the Partnership, and whether we will have the requisite funds to do so;

	•	the possibility that we will be required to sell a portion of our interests in the Partnership in the Partnership’s initial offering at an undesirable time or price;

	•	the ability of the Partnership to manage the nitrogen fertilizer business in a manner adverse to our interests;

	•	the conflicts of interest faced by our senior management, which operates both our company and the Partnership, and our controlling stockholders, who control our company and the managing general partner of the Partnership;

	•	limitations on the fiduciary duties owed by the managing general partner which are included in the partnership agreement;

	•	whether we are ever deemed to be an investment company under the 1940 Act or will need to take actions to sell interests in the Partnership or buy assets to refrain from being deemed an investment company;

	•	changes in the treatment of the Partnership as a partnership for U.S. income tax purposes;

	•	transfer of control of the managing general partner of the Partnership to a third party that may have no economic interest in us; and

	•	the risk that the Partnership will not consummate a public offering or private placement.

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.

RATIO OF EARNINGS TO FIXED CHARGES

The following table presents our historical ratio of earnings to fixed charges for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and for each accounting period during the five year period ended December 31, 2007. We have not presented a ratio of earnings to combined fixed charges and preferred stock dividends because we did not have preferred stock outstanding during any such period. Therefore, our ratio of earnings to combined fixed charges and preferred dividends for any given period is equivalent to our ratio of earnings to fixed charges.

For purposes of this table, earnings consist ofpre-tax income (loss) from continuing operations before adjustments for minority interest in consolidated subsidiary, plus fixed charges (excluding capitalized interest, but including amortization of amounts previously capitalized). Fixed charges consist of interest (including capitalized interest) on all debt, amortization of debt expenses incurred on issuance, loss or extinguishment of debt and an estimate of the interest within rental expense.

Original Predecessor Immediate Predecessor Successor
Year
62 Days
304 Days
174 Days
233 Days
Year
Year
Three Months

Ended
Ended
Ended
Ended
Ended
Ended
Ended
Ended

December 31, March 2, December 31, June 23, December 31, December 31, December 31, March 31,
2003 2004 2004 2005 2005 2006 2007 2008
(unaudited)
(in millions)
Ratio of Earnings to Fixed Charges(1) 12.1x 57.0x 5.6x 6.3x — 4.7x — 3.2x

Original Predecessor

Immediate Predecessor

Successor

Year

62 Days

304 Days

174 Days

233 Days

Year

Six Months

Ended

December 31,

March 2,

December 31,

June 23,

December 31,

June 30,

2003

2004

2005

2006

2007

2008

(unaudited)

(in millions)

Ratio of Earnings to Fixed Charges(1)

12.1x

57.0x

5.6x

6.3x

—

4.7x

—

3.8x


(1)	Earnings were insufficient to cover fixed charges by $183.0 million and $167.8 million for the 233 days ended December 31, 2005 and the year ended December 31, 2007, respectively.

USE OF PROCEEDS

We estimate that the net proceeds from this offering, after deducting estimated fees and expenses and the underwriters’ discounts and commissions, will be approximately $ million. If the underwriters exercise in full their over-allotment option to purchase additional notes from us, we estimate that the net proceeds from this offering, after deducting estimated fees and expenses and the underwriters’ discounts and commissions, will be approximately $ million.

Approximately $ million (approximately $ million if the underwriters exercise in full their over-allotment option to purchase additional notes from us) of the net proceeds of this offering will be used to purchase government securities to be deposited in the escrow account and pledged to the trustee as security for our obligations under the notes and the indenture. See “Description of the Notes — Interest Escrow.” We intend to use the balance of the net proceeds (including any proceeds we receive if the underwriters exercise their over-allotment option to purchase additional notes from us) for general corporate purposes, which may include using a portion of the proceeds ~~to pay amounts owed to J. Aron under the Cash Flow Swap and~~ for future capital investments. Under the terms of the ~~proposed~~ deferral of $87.5 million of the amounts owed to J. Aron, an affiliate of Goldman, Sachs & Co., we ~~will be~~are required to use the substantial majority of any gross proceeds from any indebtedness we incur during the deferral period in excess of $125.0 million, including ~~this offering,~~all of the gross proceeds received from the sale of notes issued in connection with the exercise by the underwriters of theover-allotment option net of fees, to prepay a portion of the deferred ~~amounts. We cannot assure you that the new deferral agreement will be consummated.~~

amounts owed to J. Aron.

DIVIDEND POLICY

We do not anticipate paying any cash dividends on shares of our common stock in the foreseeable future. We currently intend to retain future earnings from our refinery business, if any, together with any cash distributions we receive from the Partnership, 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 our credit facility limit the ability of our subsidiaries to pay dividends to us, which limits our ability to pay dividends to our stockholders, including any amounts received from the Partnership in the form of quarterly distributions. Our ability to pay dividends also may be limited by covenants in other instruments governing future indebtedness that we or our subsidiaries may incur in the future. See “Description of Our Indebtedness and the Cash Flow Swap.”

In addition, the partnership agreement which governs the Partnership includes restrictions on the Partnership’s ability to make distributions to us. If the Partnership issues limited partner interests to third party investors, these investors will have rights to receive distributions which, in some cases, will be senior to our rights to receive distributions. In addition, the managing general partner of the Partnership has incentive distribution rights which, over time, will give it rights to receive distributions. These provisions will limit the amount of distributions which the Partnership can make to us which will, in turn, limit our ability to make distributions to our stockholders. In addition, since the Partnership will make its distributions to Coffeyville Resources, LLC, a subsidiary of ours, our credit facility will limit the ability of Coffeyville Resources, LLC to distribute these distributions to us. In addition, the Partnership may also enter into its own credit facility or other contracts that limit its ability to make distributions to us.

In October 2007, the directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively, approved a special dividend of $10.6 million to their members, including approximately $5.2 million to the Goldman Sachs Funds, approximately $5.1 million to the Kelso Funds and approximately $0.3 million to certain members of our senior management team, a director and an unrelated member. The common unit holders receiving this special dividend contributed $10.6 million collectively to Coffeyville Acquisition III LLC, which used such amounts to purchase the managing general partner of the Partnership.

MARKET PRICE OF OUR COMMON STOCK

Our common stock has been listed on the New York Stock Exchange under the symbol “CVI” since October 23, 2007. Prior to that time, there was no public market for our common stock. The following table sets forth for the periods indicated the high and low reported sale prices per share of our common stock on the New York Stock Exchange. These prices do not include retail markups, markdowns or commissions.


	High		Low		High		Low

Year Ended December 31, 2007:
Fourth Quarter (from October 23, 2007)	$	26.25	$	19.80	$	26.25	$	19.80
Year Ending December 31, 2008:
First Quarter		30.94		20.71		30.94		20.71
Second Quarter		28.88		18.17		28.88		18.17
Third Quarter (through July 23, 2008)		19.75		14.75
Third Quarter (through August 21, 2008)						19.75		11.15

A recent reported closing price for our common stock is set forth on the cover page of this prospectus. American Stock Transfer & Trust Company is the registrar and transfer agent for our common stock. We estimate that there were approximately ~~449~~448 holders of record of our common stock as of ~~July 15,~~August 14, 2008. Because many of our shares of common stock are held by brokers and other institutions on behalf of stockholders, we are unable to estimate the total number of stockholders represented by these record holders.

CAPITALIZATION

The following table sets forth our consolidated cash and cash equivalents and capitalization as of ~~March 31,~~June 30, 2008:


	•	on an actual basis; and


	•	on an adjusted basis to give effect to this offering of $125.0 million aggregate principal amount of our Convertible Senior Notes due 2013 (assuming the underwriters’ over-allotment option is not exercised) and certain expenses associated with this offering, as if this offering had occurred and the expenses had been paid on ~~March 31,~~June 30, 2008.

You should read this table in conjunction with “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 March 31, 2008						As of June 30, 2008
				As					As
	Actual			Adjusted			Actual		Adjusted
	(unaudited)						(unaudited)
	(in thousands)						(in thousands)

Cash and cash equivalents	$	25,179		$	145,279	(1)(2)	$	20,616	$	140,287	(1)(2)

Debt (including current portion):
Note payable and capital lease obligations(3)	$	11,209		$	11,209		$	14,683	$	14,683
Revolving credit facility(4)		—			—			21,500		21,500
Term loan facility		487,979			487,979			486,759		486,759
Convertible senior notes due 2013		—			125,000			—		125,000

Total debt		499,188			624,188			522,942		647,942

Minority interest in subsidiaries(5)		10,600			10,600			10,600		10,600
Stockholders’ equity:
Common stock, $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding		861			861			861		861
Preferred stock, $0.01 par value per share, 50,000,000 shares authorized; no shares issued and outstanding		—			—			—		—
Additionalpaid-in-capital		458,523			458,523			450,492		450,492
Retained earning (deficit)		(4,279	)		(4,279	)		26,709		26,709

Total stockholders’ equity		455,105			455,105			478,062		478,062

Total capitalization	$	964,893		$	1,089,893		$	1,011,604	$	1,136,604


(1)		Does not reflect the payment of $36.2 million plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008) we will make to J. Aron on or before August 31, 2008 ~~assuming~~in connection with the $87.5 million J. Aron deferral agreement (which deferral amount has been excluded from the table) ~~is consummated.~~.


(2)		Includes restricted cash in the form of government securities to be held in escrow by a financial institution to fund the first six scheduled interest payments on the notes. See “Description of the Notes — Interest Escrow”.


(3)		~~Note payable represents the balance due to Cananwill, Inc. related to the financing of insurance premiums.~~ Capital lease obligations is the obligation associated with leasing platinum for the ~~refinery.~~refinery and a capital lease for real property. Note payable and capital lease obligations does not include amounts deferred under the J. Aron deferral agreement.


(4)		As of ~~July 15,~~August 14, 2008, we had availability of ~~$109.4~~$112.6 million under our revolving credit facility.


(5)		Represents the managing general partner’s interest in the Partnership held by Coffeyville Acquisition III LLC.

SELECTED HISTORICAL CONSOLIDATED FINANCIAL DATA

The historical data presented below has been derived from financial statements that have been prepared using GAAP and that are included elsewhere in this prospectus. 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 the174-day period ended June 23, 2005, the233-day period ended December 31, 2005 and the years ended December 31, 2006 and 2007 and the selected consolidated financial information presented below under the caption Balance Sheet Data as of December 31, 2006 and 2007 has 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 year ended December 31, 2003, the62-day period ended March 2, 2004 and the 304 days ended December 31, 2004, and the consolidated financial information presented below under the caption Balance Sheet Data at December 31, 2003, 2004 and 2005, 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 ~~three~~six month period ended ~~March 31,~~June 30, 2007 and the ~~three~~six month period ended ~~March 31,~~June 30, 2008, and the selected unaudited interim consolidated financial information presented below under the caption Balance Sheet Data as of ~~March 31,~~June 30, 2008, 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 ~~three~~six month period ended ~~March 31,~~June 30, 2008 are not necessarily indicative of the results that may be expected for the year ending December 31, 2008.

Prior to March 3, 2004, our assets were operated as a component of Farmland. We refer to our operations as part of Farmland during this period as “Original Predecessor.” 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 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, and we refer to our post-Farmland operations run by Coffeyville Group Holdings, LLC as Immediate Predecessor. Our business was operated by the Immediate Predecessor for the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005. 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 periods when we were operated as part of Farmland, which include the fiscal year ended December 31, 2003 and the 62 days ended March 2, 2004, 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 the years ended December 31, 2006 and 2007 and the ~~three~~six month period ended ~~March 31,~~June 30, 2007 on a pro forma basis, assuming our post-IPO capital structure had been in place for the entire year for each of 2006 and 2007. For the year ended December 31, 2007, 17,500 non-vested common shares and 18,900 common stock options have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive. We have

omitted earnings per share data for Immediate Predecessor because we operated

under a different capital structure than our current capital structure 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. We refer to this acquisition as the Subsequent Acquisition, and we refer to our post-June 24, 2005 operations as Successor. As a result of certain adjustments made in connection with the Subsequent 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. 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.

On April 23, 2008, the audit committee of our board of directors and management concluded that our previously issued consolidated financial statements for the year ended December 31, 2007 and the related quarter ended September 30, 2007 contained errors. See footnote 2 to our consolidated financial statements for the year ended December 31, 2007 included elsewhere in this prospectus and “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Restatement of Year Ended December 31, 2007 and Quarter Ended September 30, 2007 Financial Statements.” All information presented in this prospectus reflects our restated financial results.

Successor
Three Months
Three Months

Ended
Ended

March 31,
March 31,

2007

2008

(unaudited)

(in millions, unless

otherwise indicated)

Statement of Operations Data:

Net sales $ 390.5 $ 1,223.0
Cost of product sold (exclusive of depreciation and amortization) 303.7 1,036.2
Direct operating expenses (exclusive of depreciation and amortization) 113.4 60.6
Selling, general and administrative expenses (exclusive of depreciation and amortization) 13.2 13.4
Net costs associated with flood(1) — 5.8
Depreciation and amortization(2) 14.2 19.6
Operating income (loss)
(54.0 ) 87.4
Other income, net 0.5 0.9
Interest expense and other financing costs (11.9 ) (11.3 )
Loss on derivatives, net (137.0 ) (47.9 )
Income (loss) before income taxes and minority interests in subsidiaries (202.4 ) 29.1
Income tax (expense) benefit (47.3 ) (6.9 )
Minority interest in (income) loss of subsidiaries 0.7 —
Net income (loss)(3) (154.4 ) 22.2
Pro forma earnings (loss) per share, basic (1.79 )
Pro forma earnings (loss) per share, diluted (1.79 )
Pro forma weighted average shares, basic 86,141,291
Pro forma weighted average shares, diluted 86,141,291
Earnings per share, basic 0.26
Earnings per share, diluted 0.26
Weighted average shares, basic 86,141,291
Weighted average shares, diluted 86,158,791
Balance Sheet Data:

Cash and cash equivalents 25.2
Working capital 21.5
Total assets 1,923.6
Total debt, including current portion 499.2
Minority interest in subsidiaries 10.6
Stockholders’ equity 455.1
Other Financial Data:

Depreciation and amortization(2) 14.2 19.6
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) (82.4 ) 30.6
Cash flows provided by operating activities 44.1 24.2
Cash flows (used in) investing activities (107.4 ) (26.2 )
Cash flows provided by (used in) financing activities 29.0 (3.4 )
Capital expenditures for property, plant and equipment 107.4 26.2
Key Operating Statistics:

Petroleum Business

Production (barrels per day)(5) 53,689 125,614
Crude oil throughput (barrels per day)(5) 47,267 106,530
Refining margin per crude oil throughput barrel (dollars)(6) $ 12.69 $ 13.76
NYMEX 2-1-1 crack spread (dollars)(7) $ 12.17 $ 11.81
Direct operating expenses (exclusive of depreciation and amortization)
per crude oil throughput barrel (dollars)(8) $ 22.73 $ 4.16
Gross profit (loss) per crude oil throughput barrel (dollars)(8) $ (12.34 ) $ 7.50
Nitrogen Fertilizer Business

Production Volume:
Ammonia (tons in thousands) 86.2 83.7
UAN (tons in thousands) 165.7 150.1
On-stream factors:
Gasification 91.8 % 91.8 %
Ammonia 86.3 % 90.7 %
UAN 89.4 % 85.9 %


	Successor
	Six Months			Six Months
	Ended			Ended
	June 30,			June 30,
	2007			2008
	(unaudited)
	(in millions, unless
	otherwise indicated)

Statement of Operations Data:
Net sales	$	1,233.9		$	2,735.5
Cost of product sold (exclusive of depreciation and amortization)		873.3			2,323.6
Direct operating expenses (exclusive of depreciation and amortization)		174.4			122.9
Selling, general and administrative expenses (exclusive of depreciation and amortization)		28.1			28.3
Net costs associated with flood(1)		2.1			9.7
Depreciation and amortization(2)		32.2			40.7

Operating income (loss)		123.8			210.3
Other income, net		0.7			1.8
Interest expense and other financing costs		(27.6	)		(20.8	)
Loss on derivatives, net		(292.4	)		(127.2	)

Income (loss) before income taxes and minority interests in subsidiaries		(195.5	)		64.1
Income tax (expense) benefit		141.0			(10.9	)
Minority interest in loss of subsidiaries		0.2			—

Net income (loss)(3)		(54.3	)		53.2
Pro forma (loss) per share, basic		(0.63	)
Pro forma (loss) per share, diluted		(0.63	)
Pro forma weighted average shares, basic		86,141,291
Pro forma weighted average shares, diluted		86,141,291
Earnings per share, basic					0.62
Earnings per share, diluted					0.62
Weighted average shares, basic					86,141,291
Weighted average shares, diluted					86,158,791
Balance Sheet Data:
Cash and cash equivalents					20.6
Working capital					(35.5	)
Total assets					1,979.2
Total debt, including current portion					522.9
Minority interest in subsidiaries					10.6
Stockholders’ equity					478.1
Other Financial Data:
Depreciation and amortization(2)		32.2			40.7
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4)		59.0			71.2
Cash flows provided by operating activities		160.7			23.3
Cash flows (used in) investing activities		(214.1	)		(49.6	)
Cash flows provided by (used in) financing activities		34.5			16.4
Capital expenditures for property, plant and equipment		214.1			49.6
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)		78,098			122,573
Crude oil throughput (barrels per day)(5)		71,098			105,544
Refining margin per crude oil throughput barrel (dollars)(6)	$	22.71		$	15.98
NYMEX 2-1-1 crack spread (dollars)(7)	$	17.13		$	14.48
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8)	$	10.96		$	4.32
Gross profit per crude oil throughput barrel (dollars)(8)	$	9.80		$	9.57
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)		169.0			163.2
UAN (tons in thousands)		304.6			289.2
On-stream factors:
Gasification		90.6	%		87.3	%
Ammonia		86.8	%		85.4	%
UAN		81.9	%		82.1	%

Original Predecessor Immediate Predecessor Successor
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

2006

2007

(in millions, unless otherwise indicated)

Statement of Operations Data:

Net sales $ 1,262.2 $ 261.1 $ 1,479.9 $ 980.7 $ 1,454.3 $ 3,037.6 $ 2,966.9
Cost of product sold (exclusive of depreciation and amortization) 1,061.9 221.4 1,244.2 768.0 1,168.1 2,443.4 2,308.8
Direct operating expenses (exclusive of depreciation and amortization) 133.1 23.4 117.0 80.9 85.3 199.0 276.1
Selling, general and administrative expenses (exclusive of depreciation and amortization) 23.6 4.7 16.3 18.4 18.4 62.6 93.1
Net costs associated with flood(1) — — — — — — 41.5
Depreciation and amortization(2) 3.3 0.4 2.4 1.1 24.0 51.0 60.8
Impairment, earnings (losses) in joint ventures, and other charges(9) 10.9 — — — — — —

Operating income
$ 29.4 $ 11.2 $ 100.0 $ 112.3 $ 158.5 $ 281.6 $ 186.6
Other income (expense)(10) (0.5 ) — (6.9 ) (8.4 ) 0.4 (20.8 ) 0.2
Interest (expense) (1.3 ) — (10.1 ) (7.8 ) (25.0 ) (43.9 ) (61.1 )
Gain (loss) on derivatives 0.3 — 0.5 (7.6 ) (316.1 ) 94.5 (282.0 )

Income (loss) before income taxes $ 27.9 $ 11.2 $ 83.5 $ 88.5 $ (182.2 ) $ 311.4 $ (156.3 )
Income tax (expense) benefit — — (33.8 ) (36.1 ) 63.0 (119.8 ) 88.5
Minority interest in (income) loss of subsidiaries — — — — — — 0.2

Net income (loss)(3) $ 27.9 $ 11.2 $ 49.7 $ 52.4 $ (119.2 ) $ 191.6 $ (67.6 )
Pro forma earnings per share, basic $ 2.22 $ (0.78 )
Pro forma earnings per share, diluted $ 2.22 $ (0.78 )
Pro forma weighted average shares, basic 86,141,291 86,141,291
Pro forma weighted average shares, diluted 86,158,791 86,141,291
Historical dividends:
Preferred per unit(11) $ 1.50 $ 0.70
Common per unit(11) $ 0.48 $ 0.70
Management common units subject to redemption $ 3.1
Common units $ 246.9
Balance Sheet Data:

Cash and cash equivalents $ 0.0 $ 52.7 $ 64.7 $ 41.9 $ 30.5
Working capital(12) 150.5 106.6 108.0 112.3 10.7
Total assets 199.0 229.2 1,221.5 1,449.5 1,868.4
Liabilities subject to compromise(13) 105.2 — — — —
Total debt, including current portion — 148.9 499.4 775.0 500.8
Minority interest in subsidiaries(14) — — — 4.3 10.6
Management units subject to redemption — — 3.7 7.0 —
Divisional/members’/stockholders’ equity 58.2 14.1 115.8 76.4 432.7
Other Financial Data:

Depreciation and amortization $ 3.3 $ 0.4 $ 2.4 $ 1.1 $ 24.0 $ 51.0 $ 68.4
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) 27.9 11.2 49.7 52.4 23.6 115.4 (5.6 )
Cash flows provided by operating activities 20.3 53.2 89.8 12.7 82.5 186.6 145.9
Cash flows (used in) investing activities (0.8 ) — (130.8 ) (12.3 ) (730.3 ) (240.2 ) (268.6 )
Cash flows provided by (used in) financing activities (19.5 ) (53.2 ) 93.6 (52.4 ) 712.5 30.8 111.3
Capital expenditures for property, plant and equipment 0.8 — 14.2 12.3 45.2 240.2 268.6
Key Operating Statistics:

Petroleum Business

Production (barrels per day)(5)(15) 95,701 106,645 102,046 99,171 107,177 108,031 86,201
Crude oil throughput (barrels per day)(5)(15) 85,501 92,596 90,418 88,012 93,908 94,524 76,285
Refining margin per crude oil throughput barrel (dollars)(6) $ 3.89 $ 4.23 $ 5.92 $ 9.28 $ 11.55 $ 13.27 $ 18.17
NYMEX 2-1-1 crack spread (dollars)(7) $ 5.53 $ 6.80 $ 7.55 $ 9.60 $ 13.47 $ 10.84 $ 13.95
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8) $ 2.57 $ 2.60 $ 2.66 $ 3.44 $ 3.13 $ 3.92 $ 7.52
Gross profit (loss) per crude oil throughput barrel (dollars)(8) $ 1.25 $ 1.57 $ 3.20 $ 5.79 $ 7.55 $ 8.39 $ 7.79
Nitrogen Fertilizer Business

Production Volume:
Ammonia (tons in thousands)(15) 335.7 56.4 252.8 193.2 220.0 369.3 326.7
UAN (tons in thousands)(15) 510.6 93.4 439.2 309.9 353.4 633.1 576.9
On-steam factors(16):
Gasifier 90.1 % 93.5 % 92.2 % 97.4 % 98.7 % 92.5 % 90.0 %
Ammonia 89.6 % 80.9 % 79.7 % 95.0 % 98.3 % 89.3 % 87.7 %
UAN 81.6 % 88.7 % 82.2 % 93.9 % 94.8 % 88.9 % 78.7 %


	Original Predecessor						Immediate Predecessor						Successor
	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			2006			2007
	(in millions, unless otherwise indicated)

Statement of Operations Data:
Net sales	$	1,262.2		$	261.1		$	1,479.9		$	980.7		$	1,454.3		$	3,037.6		$	2,966.9
Cost of product sold (exclusive of depreciation and amortization)		1,061.9			221.4			1,244.2			768.0			1,168.1			2,443.4			2,308.8
Direct operating expenses (exclusive of depreciation and amortization)		133.1			23.4			117.0			80.9			85.3			199.0			276.1
Selling, general and administrative expenses (exclusive of depreciation and amortization)		23.6			4.7			16.3			18.4			18.4			62.6			93.1
Net costs associated with flood(1)		—			—			—			—			—			—			41.5
Depreciation and amortization(2)		3.3			0.4			2.4			1.1			24.0			51.0			60.8
Impairment, earnings (losses) in joint ventures, and other charges(9)		10.9			—			—			—			—			—			—

Operating income	$	29.4		$	11.2		$	100.0		$	112.3		$	158.5		$	281.6		$	186.6
Other income (expense)(10)		(0.5	)		—			(6.9	)		(8.4	)		0.4			(20.8	)		0.2
Interest (expense)		(1.3	)		—			(10.1	)		(7.8	)		(25.0	)		(43.9	)		(61.1	)
Gain (loss) on derivatives, net		0.3			—			0.5			(7.6	)		(316.1	)		94.5			(282.0	)

Income (loss) before income taxes	$	27.9		$	11.2		$	83.5		$	88.5		$	(182.2	)	$	311.4		$	(156.3	)
Income tax (expense) benefit		—			—			(33.8	)		(36.1	)		63.0			(119.8	)		88.5
Minority interest in (income) loss of subsidiaries		—			—			—			—			—			—			0.2

Net income (loss)(3)	$	27.9		$	11.2		$	49.7		$	52.4		$	(119.2	)	$	191.6		$	(67.6	)
Pro forma earnings per share, basic																$	2.22		$	(0.78	)
Pro forma earnings per share, diluted																$	2.22		$	(0.78	)
Pro forma weighted average shares, basic																	86,141,291			86,141,291
Pro forma weighted average shares, diluted																	86,158,791			86,141,291
Historical dividends:
Preferred per unit(11)							$	1.50		$	0.70
Common per unit(11)							$	0.48		$	0.70
Management common units subject to redemption																$	3.1
Common units																$	246.9
Balance Sheet Data:
Cash and cash equivalents	$	0.0					$	52.7					$	64.7		$	41.9		$	30.5
Working capital(12)		150.5						106.6						108.0			112.3			10.7
Total assets		199.0						229.2						1,221.5			1,449.5			1,868.4
Liabilities subject to compromise(13)		105.2						—						—			—			—
Total debt, including current portion		—						148.9						499.4			775.0			500.8
Minority interest in subsidiaries(14)		—						—						—			4.3			10.6
Management units subject to redemption		—						—						3.7			7.0			—
Divisional/members’/stockholders’ equity		58.2						14.1						115.8			76.4			432.7
Other Financial Data:
Depreciation and amortization	$	3.3		$	0.4		$	2.4		$	1.1		$	24.0		$	51.0		$	68.4
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4)		27.9			11.2			49.7			52.4			23.6			115.4			(5.6	)
Cash flows provided by operating activities		20.3			53.2			89.8			12.7			82.5			186.6			145.9
Cash flows (used in) investing activities		(0.8	)		—			(130.8	)		(12.3	)		(730.3	)		(240.2	)		(268.6	)
Cash flows provided by (used in) financing activities		(19.5	)		(53.2	)		93.6			(52.4	)		712.5			30.8			111.3
Capital expenditures for property, plant and equipment		0.8			—			14.2			12.3			45.2			240.2			268.6
Key Operating Statistics:
Petroleum Business
Production (barrels per day)(5)(15)		95,701			106,645			102,046			99,171			107,177			108,031			86,201
Crude oil throughput (barrels per day)(5)(15)		85,501			92,596			90,418			88,012			93,908			94,524			76,285
Refining margin per crude oil throughput barrel (dollars)(6)	$	3.89		$	4.23		$	5.92		$	9.28		$	11.55		$	13.27		$	18.17
NYMEX 2-1-1 crack spread (dollars)(7)	$	5.53		$	6.80		$	7.55		$	9.60		$	13.47		$	10.84		$	13.95
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8)	$	2.57		$	2.60		$	2.66		$	3.44		$	3.13		$	3.92		$	7.52
Gross profit (loss) per crude oil throughput barrel (dollars)(8)	$	1.25		$	1.57		$	3.20		$	5.79		$	7.55		$	8.39		$	7.79
Nitrogen Fertilizer Business
Production Volume:
Ammonia (tons in thousands)(15)		335.7			56.4			252.8			193.2			220.0			369.3			326.7
UAN (tons in thousands)(15)		510.6			93.4			439.2			309.9			353.4			633.1			576.9
On-steam factors(16):
Gasifier		90.1	%		93.5	%		92.2	%		97.4	%		98.7	%		92.5	%		90.0	%
Ammonia		89.6	%		80.9	%		79.7	%		95.0	%		98.3	%		89.3	%		87.7	%
UAN		81.6	%		88.7	%		82.2	%		93.9	%		94.8	%		88.9	%		78.7	%


(1)		Represents the write-off of approximate net costs associated with the flood and crude oil spill that are not probable of recovery. See “Flood and Crude Oil Discharge.”


(2)		Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general and administrative expenses:


	Original Predecessor				Immediate Predecessor				Successor										Original Predecessor				Immediate Predecessor				Successor
	Year		62 Days		304 Days		174 Days		233 Days		Year				Three Months				Year		62 Days		304 Days		174 Days		233 Days		Year				Six Months
	Ended		Ended		Ended		Ended		Ended		Ended				Ended				Ended		Ended		Ended		Ended		Ended		Ended				Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,				March 31,				December 31,		March 2,		December 31,		June 23,		December 31,		December 31,				June 30,
	2003		2004		2004		2005		2005		2006		2007		2007		2008		2003		2004		2004		2005		2005		2006		2007		2007		2008
															(unaudited)		(unaudited)																(unaudited)
	(in millions)																		(in millions)
Depreciation and amortization included in cost of product sold	$	—	$	—	$	0.2	$	0.1	$	1.1	$	2.2	$	2.4	$	0.6	$	0.6	$	—	$	—	$	0.2	$	0.1	$	1.1	$	2.2	$	2.4	$	1.2	$	1.2
Depreciation and amortization included in direct operating expense		3.3		0.4		2.0		0.9		22.7		47.7		57.4		13.5		18.7		3.3		0.4		2.0		0.9		22.7		47.7		57.4		30.6		38.8
Depreciation and amortization included in selling, general and administrative expense		—		—		0.2		0.1		0.2		1.1		1.0		0.1		0.3		—		—		0.2		0.1		0.2		1.1		1.0		0.4		0.7
Depreciation and amortization included in net costs associated with flood		—		—		—		—		—		—		7.6		—		—		—		—		—		—		—		—		7.6		—		—
Total depreciation and amortization	$	3.3	$	0.4	$	2.4	$	1.1	$	24.0	$	51.0	$	68.4	$	14.2	$	19.6	$	3.3	$	0.4	$	2.4	$	1.1	$	24.0	$	51.0	$	68.4	$	32.2	$	40.7


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

Original Predecessor Immediate Predecessor Successor
Year
62 Days
304 Days
174 Days
233 Days
Year
Three Months

Ended
Ended
Ended
Ended
Ended
Ended
Ended

December 31,

March 2,

December 31,

June 23,

December 31,
December 31, March 31,

2003

2004

2004

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)
Impairment of property, plant and equipment(a) $ 9.6 $ — $ — $ — $ — $ — $ — $ — $ —
Loss on extinguishment of debt(b) — — 7.2 8.1 — 23.4 1.3 — —
Inventory fair market value adjustment(c) — — 3.0 — 16.6 — — — —
Funded letter of credit expense and interest rate swap not included in interest expense(d) — — — — 2.3 — 1.8 — 0.9
Major scheduled turnaround expense(e) — — 1.8 — — 6.6 76.4 66.0 —
Loss on termination of swap(f) — — — — 25.0 — — — —
Unrealized (gain) loss from Cash Flow Swap — — — — 235.9 (126.8 ) 103.2 119.7 13.9


	Original Predecessor				Immediate Predecessor				Successor
	Year		62 Days		304 Days		174 Days		233 Days		Year					Six Months
	Ended		Ended		Ended		Ended		Ended		Ended					Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,					June 30,
	2003		2004		2004		2005		2005		2006			2007		2007		2008
																(unaudited)
	(in millions)
Impairment of property, plant and equipment(a)	$	9.6	$	—	$	—	$	—	$	—	$	—		$	—	$	—	$	—
Loss on extinguishment of debt(b)		—		—		7.2		8.1		—		23.4			1.3		—		—
Inventory fair market value adjustment(c)		—		—		3.0		—		16.6		—			—		—		—
Funded letter of credit expense and interest rate swap not included in interest expense(d)		—		—		—		—		2.3		—			1.8		0.2		3.3
Major scheduled turnaround expense(e)		—		—		1.8		—		—		6.6			76.4		76.8		—
Loss on termination of swap(f)		—		—		—		—		25.0		—			—		—		—
Unrealized (gain) loss from Cash Flow Swap		—		—		—		—		235.9		(126.8	)		103.2		188.5		29.9


(a)		During the year ended December 31, 2003, we recorded a 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: (i) $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004, (ii) $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005, (iii) $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006 and (iv) $1.3 million in connection with the repayment and termination of three credit facilities on October 26, 2007.

(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 credit facility.

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

(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.


(4)		Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the unrealized portion of the derivative transaction that was executed in conjunction with the acquisition of Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC on June 24,


		2005. 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. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not as a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude


		oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, ~~so long as~~ at which time the ~~time of reduction or termination, we pay the amount of~~ unrealized ~~losses associated with the amount reduced or terminated.~~loss would become a fixed obligation. 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 absolute 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 absolute 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 (loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business and assessing its growth and profitability from a strategic and financial planning perspective, management and our board of directors considers our GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.


		Net income (loss) 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 financial performance or liquidity in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark to market adjustments, the measure does not reflect the fair market value of our Cash Flow Swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. 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 (loss) adjusted for unrealized gain or loss from Cash Flow Swap to Net income (loss):

Original Predecessor Immediate Predecessor Successor
Year
62 Days
304 Days
174 Days
233 Days
Year
Three

Ended
Ended
Ended
Ended
Ended
Ended
Months Ended

December 31,

March 2,

December 31,

June 23,

December 31,
December 31, March 31,

2003

2004

2004

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)
Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap $ 27.9 $ 11.2 $ 49.7 $ 52.4 $ 23.6 $ 115.4 $ (5.6 ) $ (82.4 ) $ 30.6
Plus:
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit — — — — (142.8 ) 76.2 (62.0 ) (72.0 ) (8.4 )

Net income (loss) $ 27.9 $ 11.2 $ 49.7 $ 52.4 $ (119.2 ) $ 191.6 $ (67.6 ) $ (154.4 ) $ 22.2


	Original Predecessor				Immediate Predecessor				Successor
	Year		62 Days		304 Days		174 Days		233 Days			Year					Six
	Ended		Ended		Ended		Ended		Ended			Ended					Months Ended
	December 31,		March 2,		December 31,		June 23,		December 31,			December 31,					June 30,
	2003		2004		2004		2005		2005			2006		2007			2007			2008
																	(unaudited)
	(in millions)
Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap	$	27.9	$	11.2	$	49.7	$	52.4	$	23.6		$	115.4	$	(5.6	)	$	59.0		$	71.2
Plus:
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit		—		—		—		—		(142.8	)		76.2		(62.0	)		(113.3	)		(18.0	)

Net income (loss)	$	27.9	$	11.2	$	49.7	$	52.4	$	(119.2	)	$	191.6	$	(67.6	)	$	(54.3	)	$	53.2


(5)		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.

(6)		Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) divided by the refinery’s crude oil throughput volumes for the respective periods presented. Refining margin per crude oil throughput barrel is a non-GAAP measure that should not be substituted for gross profit or operating income and that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Our calculation of refining margin per crude oil throughput barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. We use refining margin per crude oil throughput barrel as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability.

		The table included in footnote 8 reconciles refining margin per crude oil throughput barrel to gross profit for the period presented.

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

(8)		Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel is calculated by dividing direct operating expenses (exclusive of depreciation and amortization) by total crude oil throughput volumes for the respective periods presented. Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel includes costs associated with the actual operations of the refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance and labor and environmental compliance costs but does not include depreciation or amortization. We use direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel as a measure of operating efficiency within the plant and as a control metric for expenditures.


		Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel is a non-GAAP measure. Our calculations of direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel may differ from similar calculations of other


		companies in our industry, thereby limiting its usefulness as a comparative measure. The following table reflects direct operating expenses (exclusive of depreciation and amortization) and the related calculation of direct operating expenses per crude oil throughput barrel:

Historical
Original Predecessor Immediate Predecessor Successor
Three
Three

Year
62 Days
304 Days
174 Days
233 Days
Year
Year
Months
Months

Ended
Ended
Ended
Ended
Ended
Ended
Ended
Ended
Ended

December 31, March 2, December 31, June 23, December 31, December 31, December 31, March 31, March 31,

2003

2004

2004

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions, except as otherwise indicated)
Petroleum Business:

Net Sales
$ 1,161.3 $ 241.6 $ 1,390.8 $ 903.8 $ 1,363.4 $ 2,880.4 $ 2,806.2 $ 352.5 $ 1,168.5
Cost of product sold (exclusive of depreciation and amortization) 1,040.0 217.4 1,228.1 761.7 1,156.2 2,422.7 2,300.2 298.5 1,035.1
Direct operating expenses (exclusive of depreciation and amortization) 80.1 14.9 73.2 52.6 56.2 135.3 209.5 96.7 40.3
Net costs associated with flood — — — — — — 36.7 — 5.5
Depreciation and amortization 2.1 0.3 1.5 0.8 15.6 33.0 43.0 9.8 14.9

Gross profit (loss) $ 39.1 $ 9.0 $ 88.0 $ 88.7 $ 135.4 $ 289.4 $ 216.8 $ (52.5 ) $ 72.7
Plus direct operating expenses (exclusive of depreciation and amortization) 80.1 14.9 73.2 52.6 56.2 135.3 209.5 96.7 40.3
Plus net costs associated with flood — — — — — — 36.7 — 5.5
Plus depreciation and amortization 2.1 0.3 1.5 0.8 15.6 33.0 43.0 9.8 14.9

Refining margin $ 121.3 $ 24.2 $ 162.7 $ 142.1 $ 207.2 $ 457.7 $ 506.0 $ 54.0 $ 133.4
Refining margin per crude oil throughput barrel (dollars) $ 3.89 $ 4.23 $ 5.92 $ 9.28 $ 11.55 $ 13.27 $ 18.17 $ 12.69 $ 13.76
Gross profit (loss) per crude oil throughput barrel (dollars) $ 1.25 $ 1.57 $ 3.20 $ 5.79 $ 7.55 $ 8.39 $ 7.79 $ (12.34 ) $ 7.50
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars) $ 2.57 $ 2.60 $ 2.66 $ 3.44 $ 3.13 $ 3.92 $ 7.52 $ 22.73 $ 4.16
Operating income (loss) 21.5 7.7 77.1 76.7 123.0 245.6 144.9 (63.5 ) 63.6


	Historical
	Original Predecessor				Immediate Predecessor				Successor
															Six		Six
	Year		62 Days		304 Days		174 Days		233 Days		Year		Year		Months		Months
	Ended		Ended		Ended		Ended		Ended		Ended		Ended		Ended		Ended
	December 31,		March 2,		December 31,		June 23,		December 31,		December 31,		December 31,		June 30,		June 30,
	2003		2004		2004		2005		2005		2006		2007		2007		2008
															(unaudited)
	(in millions, except as otherwise indicated)
Petroleum Business:
Net Sales	$	1,161.3	$	241.6	$	1,390.8	$	903.8	$	1,363.4	$	2,880.4	$	2,806.2	$	1,161.4	$	2,627.6
Cost of product sold (exclusive of depreciation and amortization)		1,040.0		217.4		1,228.1		761.7		1,156.2		2,422.7		2,300.2		869.1		2,320.6
Direct operating expenses (exclusive of depreciation and amortization)		80.1		14.9		73.2		52.6		56.2		135.3		209.5		141.1		83.0
Net costs associated with flood		—		—		—		—		—		—		36.7		2.0		8.9
Depreciation and amortization		2.1		0.3		1.5		0.8		15.6		33.0		43.0		23.1		31.2

Gross profit	$	39.1	$	9.0	$	88.0	$	88.7	$	135.4	$	289.4	$	216.8	$	126.1	$	183.9
Plus direct operating expenses (exclusive of depreciation and amortization)		80.1		14.9		73.2		52.6		56.2		135.3		209.5		141.1		83.0
Plus net costs associated with flood		—		—		—		—		—		—		36.7		2.0		8.9
Plus depreciation and amortization		2.1		0.3		1.5		0.8		15.6		33.0		43.0		23.1		31.2

Refining margin	$	121.3	$	24.2	$	162.7	$	142.1	$	207.2	$	457.7	$	506.0	$	292.3	$	307.0
Refining margin per crude oil throughput barrel (dollars)	$	3.89	$	4.23	$	5.92	$	9.28	$	11.55	$	13.27	$	18.17	$	22.71	$	15.98
Gross profit per crude oil throughput barrel (dollars)	$	1.25	$	1.57	$	3.20	$	5.79	$	7.55	$	8.39	$	7.79	$	9.80	$	9.57
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)	$	2.57	$	2.60	$	2.66	$	3.44	$	3.13	$	3.92	$	7.52	$	10.96	$	4.32
Operating income		21.5		7.7		77.1		76.7		123.0		245.6		144.9		102.9		165.5


(9)		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 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.

(10)		During the 304 days ended December 31, 2004, the 174 days ended June 23, 2005, the year ended December 31, 2006 and the year ended December 31, 2007, we recognized a loss of $7.2 million, $8.1 million, $23.4 million and $1.3 million, respectively, on early extinguishment of debt.

(11)		Historical dividends per unit for the304-day period ended December 31, 2004 and the174-day period ended June 23, 2005 are calculated based on the ownership structure of Immediate Predecessor.

(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 withSOP 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code.”SOP 90-7 requires that pre-petition liabilities be segregated in the balance sheet.

(14)		Minority interest reflects common stock in two of our subsidiaries owned by John J. Lipinski (which were exchanged for shares of our common stock with an equivalent value prior to the consummation of our initial public offering). Minority interest at December 31, 2007 reflects Coffeyville Acquisition III LLC’s ownership of the managing general partner interest and IDRs of the Partnership.

(15)		Operational information reflected for the233-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 the42-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.

(16)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the nitrogen fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors for the year ended December 31, 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN and (ii) the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN.

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,” “Cautionary Note Regarding Forward-Looking Statements” and elsewhere in this prospectus.

Overview and Executive Summary

We are an independent refiner and marketer of high value transportation fuels. In addition, we currently own all of the interests (other than the managing general partner interest and associated IDRs) in a limited partnership which produces the nitrogen fertilizers ammonia and UAN. At current natural gas and pet coke prices, the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America.

We operate under two business segments: petroleum and nitrogen fertilizer. For the fiscal years ended December 31, 2005, 2006 and 2007, we generated combined net sales of $2.4 billion, $3.0 billion and $3.0 billion, respectively. Our petroleum business generated $2.3 billion, $2.9 billion and $2.8 billion of our combined net sales, respectively, over these periods, with the nitrogen fertilizer business generating substantially all of the remainder. In addition, during these periods, our petroleum business contributed 74%, 87% and 78% of our combined operating income, respectively, with the nitrogen fertilizer business contributing substantially all of the remainder. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, we generated combined net sales of ~~$1.22~~$2.74 billion, with the petroleum business generating ~~$1.17~~$2.63 billion of our combined net sales, and the nitrogen fertilizer business generating substantially all of the remainder. For the same period, the petroleum business contributed ~~73%~~79% of our combined operating income and the nitrogen fertilizer business generated substantially all of the remainder.

Petroleum Business. Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system serving central Kansas, northern Oklahoma and southwestern Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of approximately 1.2 million barrels and (4) 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’s refined products distribution systems. In addition to rack sales (sales which are made at terminals into third-party tanker trucks), we make bulk sales (sales through third-party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs in the United States. Cushing is supplied by numerous pipelines from locations including the U.S. Gulf Coast and Canada, providing us with access to virtually any crude 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 refinery operated at an average crude throughput rate of less than 90,000 bpd. The plant averaged over 102,000 bpd of crude throughput in the second quarter of 2006, over 94,500 bpd for all 2006 and over 110,000 in the fourth quarter of 2007 with maximum daily rates in excess of

120,000 bpd for the fourth quarter of 2007. 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 70% 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 have also committed to additional pipeline capacity on the proposed Keystone pipeline project currently under development. 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 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. As a result of the crude slate optimization, we have improved the crude consumed cost discount to WTI from $3.45 per barrel in 2005 to ~~$4.57 per barrel in 2006, $5.04 per barrel in 2007 and $5.31~~$4.89 per barrel in the first ~~quarter~~half of 2008.

Nitrogen Fertilizer Business. The nitrogen fertilizer segment consists of our interest in CVR Partners, LP, a limited partnership controlled by our affiliates. The nitrogen fertilizer business consists of a nitrogen fertilizer manufacturing facility, including (1) a 1,225ton-per-day ammonia unit, (2) a 2,025ton-per-day UAN unit and (3) an 84 million standard cubic foot per day gasifier complex, which consumes approximately 1,500 tons per day of pet coke to produce hydrogen. In 2007, the nitrogen fertilizer business produced approximately 326,662 tons of ammonia, of which approximately 72% was upgraded into approximately 576,888 tons of UAN. At current natural gas and pet coke prices, the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. The nitrogen fertilizer business generated net sales of $173.0 million, $162.5 million and $165.9 million, and operating income of $71.0 million, $36.8 million and $46.6 million, for the years ended December 31, 2005, 2006 and 2007, respectively. The nitrogen fertilizer business generated net sales of ~~$62.6~~$121.4 million and operating income of ~~$26.0~~$49.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008.

The nitrogen fertilizer plant in Coffeyville, Kansas includes a pet coke gasifier that produces high purity hydrogen which in turn is converted to ammonia at a related ammonia synthesis plant. Ammonia is further upgraded into UAN solution in a related UAN unit. Pet coke is a low value by-product of the refinery coking process. On average during the last four years, more than 75% of the pet coke consumed by the nitrogen fertilizer plant was produced by our refinery. The nitrogen fertilizer business obtains most of its pet coke via a long-term coke supply agreement with us. As such, the nitrogen fertilizer business benefits from high natural gas prices, as fertilizer prices generally increase with natural gas prices, without a directly related change in cost (because pet coke is used as a primary raw material rather than natural gas).

The nitrogen fertilizer plant is the only commercial facility in North America utilizing a pet coke gasification process to produce nitrogen fertilizers. The use of low cost by-product pet coke from the adjacent oil refinery (rather than natural gas) to produce hydrogen provides the facility with a significant competitive advantage given the currently high and volatile natural gas prices. The nitrogen fertilizer business’ competition utilizes natural gas to produce ammonia. Historically, pet coke has been a less expensive feedstock than natural gas on a per-ton of fertilizer produced basis.

Capital Projects. Management has identified, developed and substantially completed several significant capital projects since June 2005 with a total cost of approximately $522 million (including $170 million in expenditures for our refinery expansion project, excluding $3.7 million in related capitalized interest). 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. 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.

The spare gasifier at the nitrogen fertilizer plant was expanded in 2006, increasing ammonia production by 6,500 tons per year. In addition, the nitrogen fertilizer plant is moving forward with an approximately $120 million fertilizer plant expansion, of which approximately ~~$11~~$14.5 million was incurred as of ~~March 31,~~June 30, 2008. We estimate this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium-priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010. This project is also expected to improve the nitrogen fertilizer business’ cost structure by eliminating the need for rail shipments of ammonia, thereby reducing the risks associated with such rail shipments and avoiding anticipated cost increases in such transport.

Recent Developments

During the second quarter of 2008, we enjoyed unprecedented fertilizer prices which contributed favorably to our earnings. Strong industry fundamentals have led current demand for nitrogen fertilizers to all time highs. U.S. corn inventories at the end of the 2008-2009 fertilizer year are projected to be at 673 million bushels, which is the lowest level since 1995-1996. Corn prices are at record high levels, and corn planting for 2008-2009 is projected to be higher than 2007-2008. Nitrogen fertilizer prices are at record high levels due to increased demand and increasing worldwide natural gas prices. In addition, nitrogen fertilizer prices, which historically showed a positive correlation with natural gas prices, have been decoupled from, and increased substantially more than, natural gas prices in 2007 and 2008. In addition to demand driven by biofuel fuel production, the quest for healthier lives and better diets in developing countries is a primary driving factor behind the increased global demand for fertilizers.

As of ~~July 22,~~August 14, 2008, our order book for all orders received prior to such date included ~~378,473~~333,561 tons of UAN at ~~an average netback price of $358.16~~$361.73 per ton and ~~30,216~~32,202 tons of ammonia at an average netback price of ~~$692.53~~$767.40 per ton. There has been a significant increase in nitrogen fertilizer prices in the last few months. As of July 22, 2008, our order book for orders received solely during the month of July 2008 is 76,502 tons of UAN at an average netback price of $483.31 per ton and 3,411 tons of ammonia at an average netback price of $857.17 per ton.

At the same time ~~however,~~as our nitrogen outlook has improved, crude oil prices ~~have~~ reached record levels in recent months, and while crack spreads have increased to historically high absolute values, they are below historical levels as a percentage of crude oil prices. Because crack spreads as a percentage of crude oil prices have not kept pace with increasing crude oil prices, our earnings ~~will be~~were materially negatively impacted in the second quarter of 2008. The Cash Flow Swap ~~will~~ also ~~have~~had a material negative impact on our earnings (which effect will continue through at least June ~~2009~~2009) due to the fact that losses on the Cash Flow Swap increase as crack spreads in absolute terms increase. In addition, our second quarter ~~has been~~earnings were negatively impacted by a catalyst changeout and unplanned downtime at the main and spare gasifiers of the fertilizer plant and unplanned downtime for the ~~refinery.~~refinery’s continuous catalytic reformer.

In addition to the registration statement for the notes offered hereby, on June 19, 2008, we filed a registration statement for a secondary offering of our common stock by certain of our selling stockholders. Due to current market conditions, the selling stockholders have elected not to proceed with the secondary offering at this time, but may elect to do so in the future. The registration statement for the secondary common stock offering remains on file with the SEC.

Restatement of Year Ended December 31, 2007 and
Quarter Ended September 30, 2007 Financial Statements

during the course of our closing process and review for the quarter ended March 31, 2008. As a result of these errors, management concluded that our internal control over financial reporting was not

adequate to determine the cost of crude oil at period end. Specifically, the Company’s policies and procedures for estimating the cost of crude oil and reconciling these estimates to vendor invoices were not effective. Additionally, the Company’s supervision and review of this estimation and reconciliation process was not operating at a level of detail adequate to identify the deficiencies in the process. Management concluded that these deficiencies were material weaknesses in our internal control over financial reporting. A material weakness is a deficiency, or a combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of the Company’s annual or interim financial statements will not be prevented or detected on a timely basis. Due to these material weaknesses, our management also concluded that we did not maintain effective disclosure controls and procedures as of December 31, 2007.

Our restated financial results were filed with the SEC with aForm 10-K/A on May 8, 2008. See footnote 2 to our consolidated financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. All information presented in this prospectus reflects our restated financial results.

~~All of the information presented in this prospectus reflects our restated financial results.~~

CVR Energy’s Initial Public Offering

On October 26, 2007, we completed an initial public offering of 23,000,000 shares of our common stock. The initial public offering price was $19.00 per share. The net proceeds to us from the sale of our common stock were approximately $408.5 million, after deducting underwriting discounts and commissions, but before deduction of offering expenses. We also incurred approximately $11.4 million of other costs related to the initial public offering.

The net proceeds from the offering were used to repay $280.0 million of our outstanding term loan debt and to repay in full our $25.0 million secured credit facility and $25.0 million unsecured credit facility. We also repaid $50.0 million of indebtedness under our revolving credit facility. The balance of the net proceeds received were used for general corporate purposes.

In connection with the initial public offering, we also became the indirect owner of Coffeyville Resources, LLC and all of its refinery assets. This was accomplished by the issuance of 62,866,720 shares of our common stock to certain entities controlled by our majority stockholders pursuant to a stock split in exchange for the interests in certain subsidiaries of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding any restricted shares issued.

CVR Partners’ Proposed Initial Public Offering

On February 28, 2008, the Partnership filed a registration statement with the SEC to effect an initial public offering of 5,250,000 common units representing limited partner interests. On June 13, 2008, we announced that the managing general partner of the Partnership had decided to postpone, indefinitely, the Partnership’s initial public offering due to then-existing market conditions for master limited partnerships. The Partnership subsequently withdrew the registration statement.

CVR Energy’s Proposed Secondary Offering

We filed a registration statement with the SEC on June 19, 2008 in which our majority stockholders and chairman proposed to offer 10 million shares of our common stock. We announced on July 30, 2008 that the majority stockholders elected not to proceed with the proposed secondary offering at that time due to then-existing market conditions. The registration statement remains on file with the SEC, and the selling stockholders may elect to proceed with the equity offering in the future.

Major Influences on Results of Operations

Petroleum Business

Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of, and demand for, crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political

affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we applyfirst-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.

Crude oil costs are at historic highs. West Texas Intermediate crude oil averaged $97.82 per barrel for the three months ended March 31, 2008, as compared to $58.27 per barrel during the comparable period in 2007. WTI crude oil prices averaged over $105 per barrel in March 2008. Crude oil costs continued to rise during the second quarter of 2008. WTI crude oil prices averaged over $134 per barrel in June 2008 and spiked to $140 per barrel on June 30, 2008. There are a number of reasons why high crude oil costs and current crack spreads have a negative impact on our business. First, as crack spreads increase in absolute terms in connection with higher crude oil prices, we realize increasing losses on the Cash Flow Swap. We expect the Cash Flow Swap will continue to have a material negative effect on our earnings through at least June 2009. Second, every barrel of crude oil that we process yields approximately 88% high performance transportation fuels and approximately 12% less valuable byproducts such as pet coke, slurry and sulfur and volumetric losses (lost volume resulting from the change from liquid form to solid). Whereas crude oil costs have increased, sales prices for many byproducts have not increased in the same proportions. As a result, we lose money on byproduct sales (and from the inherent lost volume in shifting from liquid to solid form), resulting in a reduction to our earnings. Refined product sales prices have also failed to keep pace with crude oil costs.

In order to assess our operating performance, we compare our refining margin, calculated as the difference between net sales ~~less~~and cost of product sold ~~(refining margin)~~(exclusive of depreciation and amortization), against an industry refining margin benchmark. The industry refining margin is calculated by assuming that two barrels of benchmark light sweet crude oil is converted into one barrel of conventional gasoline and one barrel of distillate. This benchmark is referred to as the 2-1-1 crack spread. Because we calculate the benchmark margin using the market value of New York Mercantile Exchange (NYMEX) gasoline and heating oil against the market value of NYMEX WTI (WTI) crude oil, 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 gasoline and heating oil. ~~The~~

Crude oil costs are at historic highs. West Texas Intermediate crude oil averaged $111 per barrel for the six months ended June 30, 2008, as compared to $62 per barrel during the comparable period in 2007. Crude oil costs continued to rise during the second quarter of 2008. WTI crude oil prices averaged over $134 per barrel in June 2008 and spiked to $140 per barrel on June 30, 2008. Every barrel of crude oil that we process yields approximately 88% high performance transportation fuels and approximately 12% less valuable byproducts such as pet coke, slurry and sulfur and volumetric

losses (lost volume resulting from the change from liquid form to solid). Whereas crude oil costs have increased, sales prices for many byproducts have not increased in the same proportions, resulting in lower earnings. Refined product prices have also failed to keep pace with crude oil costs.

In the event refined product sales prices increase proportionally with crude oil prices, the loss on byproduct sales and volumetric loss on crude oil processed are more than offset by refined fuel margins but in the recent crude price run up refined fuels have failed to keep pace with crude oil costs as evidenced by the narrowed 2-1-1 crack ~~spreads were significantly narrower in the first quarter of 2008~~spread as a percentage of crude oil ~~prices when~~prices. For the second quarter of 2007 the 2-1-1 crack spread as percentage of crude oil price was approximately 33.8% compared to only 13.7% in the ~~first~~second quarter of ~~2007. As~~2008.

Although crack spreads are relatively low compared to historical levels as a percentage of crude oil ~~prices,~~price, the absolute value of the NYMEX 2-1-1 crack spread for the second quarter of 2008 was $17.02 per barrel, which is well above the fixed value of Cash Flow Swap for the quarter of $8.45 per barrel. Because the actual NYMEX 2-1-1 crack spread was greater than the Cash Flow Swap fixed value, we incurred a realized loss of $52.4 million for the quarter on 6.1 million hedged barrels. The absolute value NYMEX 2-1-1 crack spread will continue to have a significant impact on our financial results due to the Cash Flow Swap until June 30, 2009, when the number of barrels subject to the Cash Flow Swap decreases from approximately ~~21% in the first~~6.2 million barrels per quarter ~~of 2007 but only 12% in the first quarter of 2008.~~to 1.5 million barrels per quarter.

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costsand/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 West Texas Sour (WTS) differential to WTI and the ~~West~~Western Canadian Select (WCS) differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The WCS-WTI differential for the second quarter of 2008 was $22.94 a barrel as compared to $17.99 a barrel in the second quarter of 2007. The differential for the first quarter of 2008 was $19.84 a ~~barrel as~~barrel. As a percentage of WTI, however, this metric averaged 72% of WTI in the 2007 period compared to ~~$14.80 a barrel~~82% in the ~~first~~second quarter of ~~2007. The differential for the fourth quarter of 2007 was $32.60 a barrel.~~2008. 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 than the heavier and more sour the crude oil slate.

Our petroleum business has been impacted by lower refining margins, reduced demand and our Cash Flow Swap. While improving somewhat from their recent lows, midcontinent refining margins remain below historical metrics when factoring in the high cost of crude. Increased throughput at our recently expanded refinery provides some offset of these factors. Historically, the strongest refining margins occur during the second and third quarters based on gasoline and diesel demand, and while crude oil prices have declined sharply from recent highs, crack spreads have not yet improved in line with the crude price declines due to continuing gasoline demand weakness.

We produce a high volume of high value products, such as gasoline and distillates. Approximately ~~39%~~40% of our product slate is ultra low sulfur diesel, which provides us with income tax credits and is currently selling at higher margins than ~~gasoline (which represents 48%~~gasoline. Gasoline production was approximately 44% of our ~~refined products).~~second quarter production, down from 48% in the first quarter of 2008. We continue to maximize distillate production, which comprised 40% of our production in the second quarter of 2008 compared to 39% in the first quarter of 2008. The balance of our production is devoted to other products, including the petroleum coke used by the nitrogen fertilizer business. 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 the 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 PADD II, Group 3 vs. NYMEX basis, or gasoline basis, and heating oil PADD II, Group 3 vs. NYMEX basis, or heating oil basis. The Group 3 basis differential averaged $0.28 a barrel in the second quarter of 2008, compared to $7.83 a barrel in the comparable period of 2007. The Group 3 basis has returned to positive territory after being negative recently, and was $4.15 per barrel on August 12, 2008, which is in line with the3-year basis average.

Our direct operating expense structure is also important to our profitability. Major direct operating expenses include energy, employee labor, maintenance, contract labor, and environmental compliance. Our predominant variable cost is energy which is comprised primarily of electrical cost and natural gas. We are therefore sensitive to the movements of natural gas prices.

Consistent, safe, and reliable operations at our refinery are key to our financial performance and results of operations. Unplanned downtime at our refinery may result in lost margin opportunity, increased maintenance expense and a temporary increase in working capital investment and related inventory position. We seek to mitigate the financial impact of planned downtime, such as major turnaround maintenance, through a diligent planning process that takes into account the margin environment, the availability of resources to perform needed maintenance, feedstocks and other factors.

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 the 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 its competitors, the nitrogen fertilizer business uses minimal natural gas as feedstock and, as a result, is not directly impacted in terms of cost by high or volatile swings in natural gas prices. Instead, our

adjacent oil refinery supplies ~~most~~the majority of the pet coke feedstock needed by the nitrogen fertilizer ~~business pursuant to a long-term pet coke supply agreement.~~business. 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 net sales of the nitrogen fertilizer business could fluctuate significantly with movements in natural gas prices during periods when fertilizer markets are weak and nitrogen fertilizer products sell at the low prices, high natural gas prices do not force the nitrogen fertilizer business to shut down its operations because it employs pet coke as a feedstock to produce ammonia and UAN rather than natural gas.

Second quarter 2008 NYMEX natural gas prices averaged $11.47 per million Btus compared with $7.66 per million Btus for the comparable period in 2007. This rise in natural gas prices implies a minimum increase of $120 per ton in production costs for North American producers in an environment where our production cost is substantially unchanged.

Nitrogen fertilizer prices are also affected by other factors, such as local market conditions and the operating levels of competing facilities. Natural gas costs and the price of nitrogen fertilizer products have historically been subject to wide fluctuations. An expansion or upgrade of competitors’ facilities, price volatility, international political and economic developments and other factors are likely to continue to play an important role in nitrogen fertilizer industry economics. These factors can impact, among other things, the level of inventories in the market, resulting in price volatility and a reduction in product margins. Moreover, the industry typically experiences seasonal fluctuations in demand for nitrogen fertilizer products.

The demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like crop prices, their current liquidity, soil conditions, weather patterns and the types of crops planted.

The value of nitrogen fertilizer products is also an important consideration in understanding our results. The nitrogen fertilizer business generally upgrades approximately two-thirds of its ammonia production into UAN, a product that presently generates a greater value than ammonia. It takes approximately .41 tons of ammonia to produce 1 ton of 32% UAN. UAN production is a major contributor to our profitability. We continue with plans for full conversion of our ammonia product line to UAN and for expansion of total UAN capacity from 2,000 to 3,000 tons per day. In order to assess the value of nitrogen fertilizer products, we calculate netbacks, also referred to as plant gate price. Netbacks refer to the unit price of fertilizer, in dollars per ton, offered on a delivered basis, ~~excluding shipment costs.~~less the costs to ship.

Prices for both ammonia and UAN for the ~~quarter~~six months ended ~~March 31,~~June 30, 2008 reflect strong current demand for these products. Ammonia plant gate prices averaged ~~$494~~$509 per ton for the ~~quarter~~six months ended ~~March 31,~~June 30, 2008, compared to ~~$347~~$354 per ton during the comparable period in 2007. UAN prices averaged ~~$262~~$281 per ton for the ~~quarter~~six months ended ~~March 31,~~June 30, 2008, compared to ~~$169~~$190 per ton during the comparable 2007 period. The prices ~~for~~of both ammonia and UAN continue to rise. Our order book as of ~~July 22,~~August 14, 2008 contains an average netback prices for ammonia and UAN of ~~$358.16~~$767 and ~~$692.53~~$362 per ton, respectively. As of mid-August 2008, ammonia prices exceeded $800 per ton for prompt shipment and $1,000 per ton for spring delivery, and UAN prices have exceeded $500 per ton. Industry forecasts for the second half of 2008 and the first half of 2009 for ammonia are in the $1,075 per ton range and for UAN are in the $540 per ton range. Actual future prices will depend on supply and demand and other factors described herein.

The direct operating expense structure of the nitrogen fertilizer business is also important to its profitability. Using a pet coke gasification process, the nitrogen fertilizer business has 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 nitrogen fertilizer plant have averaged approximately 1.2% of direct operating expenses over the last 24 months ended December 31, 2007. The average annual operating costs over the 24 months ended December 31, 2007 have approximated $65 million, of which substantially all are fixed in nature.

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

The nitrogen fertilizer business generally undergoes a facility turnaround every two years. The turnaround typically lasts15-20 days ~~each turnaround year~~ and requires approximately $2-3 million in direct costs per turnaround. The next facility turnaround is currently scheduled for the fourth quarter of 2008.

Agreements Between CVR Energy and the Partnership

In connection with our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership in October 2007, we entered into a number of agreements with the Partnership that govern the business relations between the parties. These include the coke supply agreement, under which we sell pet coke to the nitrogen fertilizer business; a services agreement, in which our management operates the nitrogen fertilizer business; a feedstock and shared services agreement, which governs the provision of feedstocks, including hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas; an omnibus agreement, which governs the division of future business opportunities between the two businesses; a raw water and facilities sharing agreement, which allocates raw water resources between the two businesses; an easement agreement; an environmental agreement; and a lease agreement pursuant to which we lease office space, storage and laboratory space to the Partnership.

The price paid by the nitrogen fertilizer business pursuant to the coke supply agreement is based on the lesser of a coke price derived from the price received by the Partnership for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet coke. For periods prior to our initial public offering and the transfer of the nitrogen fertilizer business to the Partnership, the cost of product sold (exclusive of depreciation and amortization) in the nitrogen fertilizer business on our financial statements was based on a coke price of $15 per ton beginning in March 2004. This is reflected in the segment data in our historical financial statements as a cost for the nitrogen fertilizer business and as revenue for the petroleum business. If the terms of the coke supply agreement had been in place over each of the past three years, the coke supply agreement would have resulted in an increase (or decrease) in cost of product sold (exclusive of depreciation and amortization) for the nitrogen fertilizer business (and an increase (or decrease) in revenue for the petroleum business) of $(1.6) million, $(0.7) million, $(3.5) million and $2.5 million for the174-day period ended June 24, 2005, the233-day period ended December 31, 2005, the year ended December 31, 2006 and the year ended December 31, 2007. There would have been no impact to the consolidated financial statements as intercompany transactions are eliminated upon consolidation.

In addition, based on management’s current estimates, the services agreement will result in an annual charge of approximately $11.5 million (excluding share based compensation) to the nitrogen fertilizer business for its portion of expenses which have been historically reflected in selling, general

and administrative expenses (exclusive of depreciation and amortization) in our consolidated statement of operations. Historical nitrogen fertilizer segment operating income would increase $0.8 million, decrease $0.1 million, increase $7.4 million and increase $8.9 million for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, the year ended December 31, 2006

and the year ended December 31, 2007, respectively, assuming an annualized $11.5 million charge for the management services in lieu of the historical allocations of selling, general and administrative expenses. The petroleum segment’s operating income would have had offsetting increases or decreases, as applicable, for these periods.

The total change to operating income for the nitrogen fertilizer segment as a result of both the20-year coke supply agreement (which affects cost of product sold (exclusive of depreciation and amortization)) and the services agreement (which affects selling, general and administrative expense (exclusive of depreciation and amortization)), if both agreements had been in effect over the last three years, would be an increase of $2.4 million, an increase of $0.6 million, an increase of $10.9 million and an increase of $6.4 million for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, the year ended December 31, 2006 and the year ended December 31, 2007, respectively.

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

Factors Affecting Comparability of Our Financial Results

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

2007 Flood and Crude Oil Discharge

During the weekend of June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. Our refinery and nitrogen fertilizer plant, which are located in close proximity to the Verdigris River, were severely flooded, sustained major damage and required extensive repairs. ~~Total gross costs incurred~~

As a result of the flooding, our refinery and ~~recorded as of March 31, 2008 related~~nitrogen fertilizer facilities stopped operating on June 30, 2007. The refinery started operating its reformer on August 6, 2007 and began to charge crude oil to the ~~third party costs to repair~~facility on August 9, 2007. Substantially all of the ~~refinery and~~refinery’s units were in operation by August 20, 2007. The nitrogen fertilizer ~~facilities were approximately $82.5 million and $4.0 million, respectively. Additionally, other corporate overhead and miscellaneous costs incurred and recorded in connection with~~facility, situated on slightly higher ground, sustained less damage than the ~~flood as of March 31, 2008 were approximately $19.3 million. We currently estimate that approximately $2.1 million in third party costs related~~refinery. The nitrogen fertilizer facility initiated startup at its production facility on July 13, 2007. Due to the ~~repair of flood damaged property will be recorded in future periods. In addition to the cost of repairing the facilities,~~down time, we experienced a significant revenue loss attributable to the property damage during the period when the facilities were not in operation. Total gross costs incurred and recorded as of June 30, 2008 related to the third party costs to repair the refinery and fertilizer facilities were approximately $76.9 million and $4.3 million, respectively.

~~Despite~~In addition, despite our efforts to secure the refinery prior to its evacuation as a result of the flood, we estimate that 1,919 barrels (80,600 gallons) of crude oil and 226 barrels of crude oil fractions were discharged from our refinery into the Verdigris River flood waters beginning on or about July 1, 2007. We ~~have~~ substantially completed remediation of the contamination caused by the crude oil discharge

in July 2008 and expect any remaining minor remedial actions to be completed by

December 31, 2008. ~~Total net~~In 2007, we had received insurance proceeds of $10.0 million under our property insurance policy, and $10.0 million under our environmental policies related to recovery of certain costs ~~recorded as of March 31, 2008~~ associated with ~~remediation efforts and third party property damage incurred by~~ the crude oil ~~discharge are~~discharge. In the first quarter of 2008, we received $1.5 million under our Builders Risk Insurance Policy. In July 2008 we received $13.0 million under our property insurance policy.

We also recently received sixteen notices of claims under the Oil Pollution Act from private claimants in an aggregate amount of approximately ~~$27.3~~$4.4 million. ~~This amount is net of anticipated insurance recoveries of $21.4 million.~~No lawsuits related to these claims have yet been filed.

As of ~~March 31,~~June 30, 2008, we have recorded total gross costs associated with the repair of, and other matters relating to the damage to, our facilities and with third party and property damage remediation incurred due to the crude oil discharge of approximately ~~$154.5~~$153.6 million. Total anticipated insurance recoveries of approximately ~~$107.2~~$102.4 million have been recorded as of ~~March 31,~~June 30, 2008 (of which $21.5 million ~~has~~had already been received from insurance carriers by ~~us), resulting~~us as of the end of the second quarter of 2008). At June 30, 2008, total accounts receivable from insurance were $80.9 million. The receivable balance is segregated between current and long-term in our Consolidated Balance Sheet in relation to the nature and classification of the items to be settled. As of June 30, 2008, $58.7 million of the amounts receivable from insurers were not anticipated to be collected in the next twelve months, and therefore has been classified as a ~~net cost of approximately $47.3 million.~~non-current asset. See “Flood and Crude Oil Discharge — Insurance” for a discussion of two lawsuits we filed against certain of our insurance carriers on July 10, 2008. We have not estimated any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from lawsuits related to the flood.

Refinancing and Prior Indebtedness

Effective May 10, 2004, Immediate Predecessor entered into a term loan of $150.0 million and a $75.0 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 our 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 our 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.

Effective June 24, 2005, Coffeyville Resources, LLC entered into a first lien credit facility and a second lien credit facility. The first lien credit facility was in an aggregate amount not to exceed $525.0 million, consisting of $225.0 million tranche B term loans; $50.0 million of delayed draw term loans available for the first 18 months of the agreement and subject to accelerated payment terms; a $100.0 million revolving loan facility; and a funded letter of credit facility (funded facility) of $150.0 million for the benefit of the Cash Flow Swap provider. The first lien credit facility was secured by substantially all of Coffeyville Resources, LLC’s assets. In June 2006 the first lien credit facility was amended and restated and the $225.0 million of tranche B term loans were refinanced with $225.0 million of tranche C term loans. The second lien credit facility was a $275.0 million term loan facility secured by substantially all of Coffeyville Resources, LLC’s assets on a second priority basis.

On December 28, 2006, Coffeyville Resources, LLC entered into a new credit facility and used the proceeds thereof to repay its then existing first lien credit facility and second lien credit facility, and to pay a dividend to the members of Coffeyville Acquisition LLC. The credit facility provides financing of up to $1.075 billion, consisting of $775.0 million of tranche D term loans, a $150.0 million revolving credit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow

Swap. The credit facility is secured by substantially all of Coffeyville Resources, LLC’s assets. See “Description of Our Indebtedness and the Cash Flow Swap.” As a result, interest expense for the year ended December 31, 2007 was significantly higher than interest expense for the year ended December 31, 2006. Consolidated interest expense for the year ended December 31, 2007 was $61.1 million as compared to interest expense of $43.9 million for the year ended December 31, 2006. At December 31, 2006, we had a balance of $775.0 million on our term loan facility.

The 2007 flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. As a result, in August 2007, our subsidiaries entered into a $25.0 million secured facility, a $25.0 million unsecured facility and a $75.0 million unsecured facility. Our statement of operations

for the year ended December 31, 2007 includes $0.9 million in interest expense related to these facilities with no comparable amount for the same period in the prior year.

In October 2007, we paid down $280.0 million of outstanding long-term debt with initial public offering proceeds. In addition, proceeds of our initial public offering were used to repay in full our $25.0 million secured credit facility, our $25.0 million unsecured credit facility and $50.0 million of indebtedness under our revolving credit facility. No amounts were drawn under the $75.0 million unsecured facility, and it terminated upon consummation of our initial public offering.

Our statements of operations for the ~~three~~six months ended ~~March 31,~~June 30, 2008 includes interest expense of ~~$11.3~~$20.8 million on the term debt of ~~$488.0~~$486.8 million. Interest expense associated with the term debt for the ~~three~~six months ended ~~March 31,~~June 30, 2007 totaled ~~$11.9~~$27.6 million on term debt of $773.1 million. ~~Term debt as of March 31, 2007 totaled $775.0 million.~~

J. Aron Deferrals

As a result of the flood and the temporary cessation of our operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap, which is a series of commodity derivative arrangements whereby if crack spreads in absolute terms fall below a fixed level, J. Aron agreed to pay the difference to us, and if crack spreads in absolute terms rise above a fixed level, we agreed to pay the difference to J. Aron. These deferral agreements deferred to August 31, 2008 the payment of approximately $123.7 million plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008) which we owed to J. Aron. We ~~are required to use 37.5% of our consolidated excess cash flow for any quarter after January 31,~~entered into a letter agreement with J. Aron on July 29, 2008 to ~~prepay~~defer until December 15, 2008 the ~~deferred amounts, but as of March 31, 2008, we were not required to prepay any portion of the deferred amount. We are in the process of negotiating a deferral~~payment of $87.5 million of ~~these amounts owed~~the $123.7 million plus accrued interest we owe to J. ~~Aron until~~Aron. Interest will accrue on the deferred amounts from August 31, 2008 to the date of payment at a rate of LIBOR plus 2.75%, and we are required to prepay the deferral amount each quarter with the greater of 50% of the Company’s free cash flow or $5.0 million. The remaining $36.2 million plus accrued interest will be due on August 31, 2008 (or earlier at our option). If we consummate this notes offering before December 15, 2008, the deferral will automatically extend to July 31, 2009. Under the terms of the ~~proposed deferral of~~ $87.5 million ~~of the amounts owed to J. Aron,~~deferral, we ~~will be~~are required to use the substantial majority of any gross proceeds from any indebtedness we incur during the deferral period in excess of $125.0 million, including all of the gross proceeds received from the sale of ~~this offering,~~notes issued in connection with the exercise by the underwriters of the over-allotment option net of fees, to prepay a portion of the deferred ~~amounts. We cannot assure you that the new deferral agreement will be consummated.~~amounts owed to J. Aron.

Change in Reporting Entity as a Result of the Initial Public Offering

Prior to our initial public offering in October 2007, our operations were conducted by an operating partnership, Coffeyville Resources, LLC. The reporting entity of the organization was also a partnership. Immediately prior to the closing of our initial public offering, Coffeyville Resources, LLC became an indirect, wholly-owned subsidiary of CVR Energy. As a result, for periods ending after October 2007, we report our results of operations and financial condition as a corporation on a consolidated basis rather than as an operating partnership.

Public Company Expenses

We believe 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 the initial implementation of our Sarbanes-Oxley Section 404 internal controls review and testing. Our financial statements following the initial public offering reflect the impact of these expenses, whereas our financial statements for periods prior to the initial public offering do not reflect these expenses.

2007 Turnaround

In April 2007, we completed a planned turnaround of our refining plant at a total cost approximating $80.4 million, which included ~~$66.0~~$76.8 million recorded in the ~~first quarter of~~six months ended June 30, 2007. The refinery processed crude until February 11, 2007 at which time a staged shutdown of the refinery began. The refinery recommenced operations on March 22, 2007 and continually increased crude oil charge rates

until all of the key units were restarted by April 23, 2007. The turnaround significantly impacted our financial results for 2007 and had no impact on our 2008 results.

2005 Acquisition

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. We refer to this acquisition as the Subsequent Acquisition, and we refer to our post-June 24, 2005 operations as Successor. 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.

Cash Flow Swap

In connection with the Subsequent Acquisition in June 2005, Coffeyville Resources, LLC entered into a series of commodity derivative contracts, the Cash Flow Swap, in the form of three long-term swap agreements. Based on crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, ~~so long as~~ at which time the ~~time of reduction or termination, we pay the amount of~~ unrealized ~~losses associated with the amount reduced or terminated.~~loss would become a fixed obligation. 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, 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 the233-day period ending December 31, 2005, we recorded realized and unrealized losses of $59.3 million and $235.9 million, respectively. For the year ending December 31, 2006, we recorded net realized losses of $46.8 million and net unrealized gains of $126.8 million. For the year ended December 31, 2007, we recorded net realized losses of $157.2 million and net unrealized losses of $103.2 million. The current environment of high and rising crude oil prices has led to higher crack spreads in absolute terms but significantly narrower crack spreads as a percentage of crude oil prices. As a result, the Cash Flow Swap, under which payments are calculated based on crack spreads in absolute terms, has had and continues to have a material negative impact on our earnings. ~~Due to~~As a result of our position in the Cash Flow Swap, we paid J. Aron $52.4 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2008. For the six months ended June 30, 2008 the Company recognized Loss on derivatives, net, of $127.2 million in the Statements of Operations, including realized and unrealized loss on the Cash Flow Swap of $103.8 million in the six months ended June 30, 2008. As of June 30, 2008, the Company’s Consolidated Balance Sheet reflects a payable to swap counterparty of $418.3 million compared to $350.6 million as of December 31, 2007.

100

Share-Based Compensation

We account for awards under the Phantom Unit Appreciation Plans as liability based awards. In accordance with FAS 123(R), the expense associated with these awards is based on the current fair value of the awards which is derived from our stock price as remeasured at each reporting date until the awards are settled.

Also, in conjunction with the initial public offering in October 2007, the override units of Coffeyville Acquisition LLC were modified and split evenly into override units of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. As a result of the modification, the awards were no longer accounted for as employee awards and became subject to the accounting guidance inEITF 00-12 andEITF 96-18. In accordance with that accounting guidance, the expense associated with the awards is based on the current fair value of the awards which is derived from our stock price as remeasured at each reporting date until the awards vest. Prior to October 2007, the expense associated with the override units was based on the original grant date fair value of the awards. For the six months ended June 30, 2008 we reduced compensation expense by $11.1 million. For the six months ended June 30, 2007 we increased compensation expense by $6.8 million.

Income Taxes

On an interim basis, income taxes are calculated based upon an estimated annual effective tax rate for the annual period. The estimated annual effective tax rate changes primarily due to changes in projected annual pre-tax income (loss) as estimated at each interim period and due to the significant federal and state income tax credits projected to be generated. Federal income tax credits were generated related to the production of ultra-low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program (HPIP) in 2007 and 2008. The projected income tax credits accompanied by increasing projected pre-tax loss for 2007 significantly impacted the estimated annual effective tax rate for 2007 and generated a significant increase to the income tax benefit recorded for the three months ended June 30, 2007. While significant income tax credits of approximately $59 million are estimated to be generated for 2008, the estimated annual effective tax rate for 2008 is determined based upon projected pre-tax income rather than projected pre-tax loss.

Property Tax Assessments

Our results of operations for the twelve months ending December 31, 2005 and 2006 reflect no property tax for our fertilizer facility (due to a tax abatement) and only a small property tax for our refinery. Our results of operations for the year ended December 31, 2007 reflect a substantially increased property tax for our refinery, and our results of operations for the ~~three~~six months ended ~~March 31,~~June 30, 2008 reflect a substantially increased property tax for our fertilizer facility, as a result of new tax assessments by Montgomery County, Kansas and the end of the tax abatement. We have appealed both assessments. The refinery was again reappraised effective January 1, 2008. We have also appealed this new assessment, and believe that tax exemptions should apply to any incremental tax which would be owed as a result of the new assessment.

Consolidation of Nitrogen Fertilizer Limited Partnership

Prior to the consummation of our initial public offering, we transferred our nitrogen fertilizer business to the Partnership and sold the managing general partner interest in the Partnership to a

new entity owned by our controlling stockholders and senior management. As of the date of this prospectus, we own all of the interests in the Partnership (other than the managing general partner interest and associated IDRs) and are entitled to all cash that is distributed by the Partnership. The Partnership is operated by our senior management pursuant to a services agreement among us, the managing general partner and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, us, as special general partner. As special general partner

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of the Partnership, we have joint management rights regarding the appointment, termination and compensation of the chief executive officer and chief financial officer of the managing general partner, have the right to designate two members to the board of directors of the managing general partner and have joint management rights regarding specified major business decisions relating to the Partnership. As of June 30, 2008, the Partnership had distributed $50.0 million to us from its Adjusted Operating Surplus.

We consolidate the Partnership for financial reporting purposes. We have determined that following the sale of the managing general partner interest to an entity owned by our controlling stockholders and senior management, the Partnership is a variable interest entity (“VIE”) under the provisions of FASB Interpretation No. 46R — Consolidation of Variable Interest Entities (“FIN No. 46R”).

Using criteria in FIN No. 46R, management has determined that we are the primary beneficiary of the Partnership, although 100% of the managing general partner interest is owned by a new entity owned by our controlling stockholders and senior management outside our reporting structure. Since we are the primary beneficiary, the financial statements of the Partnership remain consolidated in our financial statements. The managing general partner’s interest is reflected as a minority interest on our balance sheet.

The conclusion that we are the primary beneficiary of the Partnership and required to consolidate the Partnership as a variable interest entity is based upon the fact that substantially all of the expected losses are absorbed by the special general partner, which we own. Additionally, substantially all of the equity investment at risk was contributed on behalf of the special general partner, with nominal amounts contributed by the managing general partner. The special general partner is also expected to receive the majority, if not substantially all, of the expected returns of the Partnership through the Partnership’s cash distribution provisions.

We will need to reassess from time to time whether we remain the primary beneficiary of the Partnership in order to determine if consolidation of the Partnership remains appropriate on a going forward basis. Should we determine that we are no longer the primary beneficiary of the Partnership, we will be required to deconsolidate the Partnership in our financial statements for accounting purposes on a going-forward basis. In that event, we would be required to account for our investment in the Partnership under the equity method of accounting, which would affect our reported amounts of consolidated revenues, expenses and other income statement items.

The principal events that would require the reassessment of our accounting treatment related to our interest in the Partnership include:


	•	a sale of some or all of our partnership interests to an unrelated party;

	•	a sale of the managing general partner interest to a third party;

	•	the issuance by the Partnership of partnership interests to parties other than us or our related parties; and

	•	the acquisition by us of additional partnership interests (either new interests issued by the Partnership or interests acquired from unrelated interest holders).

In addition, we would need to reassess our consolidation of the Partnership if the Partnership’s governing documents or contractual arrangements are changed in a manner that reallocates between us and other unrelated parties either (1) the obligation to absorb the expected losses of the Partnership or (2) the right to receive the expected residual returns of the Partnership.

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Industry Factors

Petroleum Business

Earnings for our petroleum business depend largely on our refining margins, which have been and continue to be volatile. Crude oil and refined product prices depend on factors beyond our control.

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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 periods prior to 2003. Growth in demand for refined 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 affected the extent to which product importation to the United States can relieve domestic supply deficits. Our marketing region continues to be undersupplied and is a net importer of transportation fuels.

Crude oil costs are at historic highs. West Texas Intermediate crude oil averaged ~~$97.82~~$111 per barrel for the ~~three~~six months ended ~~March 31,~~June 30, 2008, as compared to ~~$58.27~~$62 per barrel during the comparable period in 2007 and ~~$123.80~~$123 per barrel for the three months ended June 30, 2008 as compared to ~~$65.02~~$65 during the comparable period in 2007. WTI crude oil prices averaged ~~over $105 per barrel in March 2008,~~ over $134 per barrel in June 2008 and spiked to $140 per barrel on June 30, 2008. These high crude oil costs and current crack spreads have had a negative impact on our business.

Crude oil discounts also contribute to our petroleum business earnings. Discounts for sour and heavy sour crude oils compared to sweet crudes continue to fluctuate widely. The worldwide production of sour and heavy sour crude oil, continuing demand for light sweet crude oil, and the increasing volumes of Canadian sours to the mid-continent continue to cause wide swings in discounts. As a result of our expansion project, we continue to increase volumes of heavy sour Canadian crudes and reduce our dependence on more expensive light sweet crudes.

Nitrogen Fertilizer Business

Currently, the nitrogen fertilizer market is driven by an almost unprecedented increase in demand. According to the United States Department of Agriculture (“USDA”), U.S. farmers planted 92.9 million acres of corn in 2007, exceeding the 2006 planted area by 19%. The actual planted acreage is the highest on record since 1944, when farmers planted 95.5 million acres of corn. The USDA ~~is forecasting as of March 2008 that~~June Acreage Report showed a decline in the total U.S. planted corn acreage in 2008 ~~will decline~~ to 8687.3 million acres. Despite this decrease, Blue Johnson estimates that nitrogen fertilizer consumption by farm users will increase by one million tons due to the need to correct for under fertilization of corn in 2007, a forecasted increase in total planted wheat acreage and very strong crop prices. This estimated increase in nitrogen usage translates into an annual increase of 3.3 million tons of UAN, or approximately five times our total 2008 estimated UAN production.

Total worldwide ammonia capacity has been growing. A large portion of the net growth has been in China and is attributable to China maintaining its self-sufficiency with regards to ammonia. Excluding China and the former Soviet Union, the trend in net ammonia capacity has been essentially

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flat since the late 1990s, as new plant construction has been offset by plant closures in countries with high-cost feedstocks. The high cost of capital is also limiting capacity increase. Today’s strong market growth appears to be readily absorbing the latest capacity additions.

Earnings for the 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. In addition, nitrogen fertilizer prices have been decoupled from their

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historical correlation with natural gas prices in recent years and increased substantially more than natural gas prices in 2007 and 2008 (based on data provided by Blue Johnson).

Results of Operations

In this “Results of Operations” section, we first review our business on a consolidated basis, and then separately review the results of operations of each of our petroleum and nitrogen fertilizer businesses on a standalone basis.

Consolidated Results of Operations

The period-to-period comparisons of our results of operations have been prepared using the historical periods included in our financial statements. As discussed in Note 1 to our consolidated financial statements for the year ended December 31, 2007, effective June 24, 2005, Successor acquired the net assets of Immediate Predecessor in a business combination accounted for as a purchase. As a result of this acquisition, the consolidated financial statements for the periods after the acquisition are presented on a different cost basis than that for the period before the acquisition and, therefore, are not comparable. Accordingly, in this “Results of Operations” section, after comparing the ~~three~~six months ended ~~March 31,~~June 30, 2008 with the ~~three~~six months ended ~~March 31,~~June 30, 2007 and the year ended December 31, 2007 with the year ended December 31, 2006, we compare the year ended December 31, 2006 with the174-day period ended June 23, 2005 and the233-day period ended December 31, 2005.

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

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

Our consolidated results of operations include certain other unallocated corporate activities and the elimination of intercompany transactions and therefore are not a sum of only the operating results of the petroleum and nitrogen fertilizer businesses.

In order to effectively review and assess our historical financial information below, we have also included supplemental operating measures and industry measures which we believe are material to understanding our business. For the year ended December 31, 2005, we have provided this supplemental information on a combined basis in order to provide a comparative basis for similar periods of time. As discussed above, due to the acquisition that occurred, there were two financial statement periods in the 2005 calendar year of less than 12 months. We believe that the most meaningful way to present this supplemental data for the 2005 calendar year is to compare the sum of the combined operating results for the year ended December 31, 2005 with the year ended December 31, 2006. Accordingly, for purposes of displaying supplemental operating data for the year ended December 31, 2005, we have combined the174-day period ended June 23, 2005 and the

~~102~~

233-day period ended December 31, 2005 to provide a comparative year ended December 31, 2005 to the year ended December 31, 2006.

We changed our method of allocating corporate selling, general and administrative expense to the operating segments in 2007. The effect of the change on operating income for174-day period ended June 23, 2005, the233-day period ended December 31, 2005 and the year ended December 31, 2006 would have been a decrease of $1.0 million, $1.4 million and $6.0 million, respectively,

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to the petroleum segment, an increase of $1.2 million, $1.4 million and $6.0 million, respectively, to the nitrogen fertilizer segment and a decrease of $0.2 million, $0.0 million and $0.0 million, respectively, to the other segment.

The following table provides an overview of our results of operations during the past three fiscal years and the ~~three~~six months ended ~~March 31,~~June 30, 2007 and ~~March 31,~~June 30, 2008:

Immediate

Predecessor Successor
174 Days
233 Days

Ended
Ended
Year Ended
Year Ended
Three Months

June 23, December 31, December 31, December 31, Ended March 31,
Consolidated Financial Results

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)

Net sales $ 980.7 $ 1,454.3 $ 3,037.6 $ 2,966.9 $ 390.5 $ 1,223.0
Cost of product sold (exclusive of depreciation and amortization) 768.0 1,168.1 2,443.4 2,308.8 303.7 1,036.2
Direct operating expenses (exclusive of depreciation and amortization) 80.9 85.3 199.0 276.1 113.4 60.6
Selling, general and administrative expense (exclusive of depreciation and amortization) 18.4 18.4 62.6 93.1 13.2 13.4
Net costs associated with flood(1) — — — 41.5 — 5.8
Depreciation and amortization(2) 1.1 24.0 51.0 60.8 14.2 19.6

Operating income $ 112.3 $ 158.5 $ 281.6 $ 186.6 $ (54.0 ) $ 87.4
Net income (loss)(3) 52.4 (119.2 ) 191.6 (67.6 ) (154.4 ) 22.2
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) 52.4 23.6 115.4 (5.6 ) (137.0 ) (47.9 )


	Immediate
	Predecessor		Successor
	174 Days		233 Days
	Ended		Ended			Year Ended		Year Ended			Six Months
	June 23,		December 31,			December 31,		December 31,			Ended June 30,
Consolidated Financial Results	2005		2005			2006		2007			2007			2008
											(unaudited)
	(in millions)

Net sales	$	980.7	$	1,454.3		$	3,037.6	$	2,966.9		$	1,233.9		$	2,735.5
Cost of product sold (exclusive of depreciation and amortization)		768.0		1,168.1			2,443.4		2,308.8			873.3			2,323.6
Direct operating expenses (exclusive of depreciation and amortization)		80.9		85.3			199.0		276.1			174.4			122.9
Selling, general and administrative expense (exclusive of depreciation and amortization)		18.4		18.4			62.6		93.1			28.1			28.3
Net costs associated with flood(1)		—		—			—		41.5			2.1			9.7
Depreciation and amortization(2)		1.1		24.0			51.0		60.8			32.2			40.7

Operating income	$	112.3	$	158.5		$	281.6	$	186.6			123.8			210.3
Net income (loss)(3)		52.4		(119.2	)		191.6		(67.6	)		(54.3	)		53.2
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4)		52.4		23.6			115.4		(5.6	)		59.0			71.2


(1)		Represents the write-off of approximate net costs associated with the flood and crude oil discharge that are not probable of recovery. See “Flood and Crude Oil Discharge.”

(2)		Depreciation and amortization is comprised of the following components as excluded from cost of products sold, direct operating expense and selling, general and administrative expense:


	Immediate
	Predecessor		Successor
	174 Days		233 Days		Year
	Ended		Ended		Ended				Six Months
	June 23,		December 31,		December 31,				Ended June 30,
Consolidated Financial Results	2005		2005		2006		2007		2007		2008
									(unaudited)
	(in millions)

Depreciation and amortization excluded from cost of product sold	$	0.1	$	1.1	$	2.2	$	2.4	$	1.2	$	1.2
Depreciation and amortization excluded from direct operating expenses		0.9		22.7		47.7		57.4		30.6		38.8
Depreciation and amortization excluded from selling, general and administrative expense		0.1		0.2		1.1		1.0		0.4		0.7
Depreciation included in net costs associated with flood		—		—		—		7.6		—		—

Total depreciation and amortization	$	1.1	$	24.0	$	51.0	$	68.4	$	32.2	$	40.7

~~103~~105

Immediate

Predecessor Successor
174 Days
233 Days
Year

Ended
Ended
Ended
Three Months
June 23, December 31, December 31, Ended March 31,
Consolidated Financial Results

2005

2005

2006

2007

2007

2008
(unaudited) (unaudited)
(in millions)

Depreciation and amortization excluded from cost of product sold $ 0.1 $ 1.1 $ 2.2 $ 2.4 $ 0.6 $ 0.6
Depreciation and amortization excluded from direct operating expenses 0.9 22.7 47.7 57.4 13.5 18.7
Depreciation and amortization excluded from selling, general and administrative expense 0.1 0.2 1.1 1.0 0.1 0.3
Depreciation included in net costs associated with flood — — — 7.6 — —

Total depreciation and amortization $ 1.1 $ 24.0 $ 51.0 $ 68.4 $ 14.2 $ 19.6


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

Immediate

Predecessor Successor
174 Days
233 Days
Year

Ended
Ended
Ended
Three Months
June 23, December 31, December 31, Ended March 31,
Consolidated Financial Results

2005

2005

2006

2007

2007

2008
(unaudited) (unaudited)
(in millions)

Loss of extinguishment of debt(a) $ 8.1 $ — $ 23.4 $ 1.3 $ — $ —
Inventory fair market value adjustment(b) — 16.6 — — — —
Funded letter of credit expense & interest rate swap not included in interest expense(c) — 2.3 — 1.8 — 0.9
Major scheduled turnaround expense(d) — — 6.6 76.4 66.0 —
Loss on termination of swap(e) — 25.0 — — — —
Unrealized (gain) loss from Cash Flow Swap — 235.9 (126.8 ) 103.2 119.7 13.9


	Immediate
	Predecessor		Successor
	174 Days		233 Days		Year
	Ended		Ended		Ended					Six Months
	June 23,		December 31,		December 31,					Ended June 30,
Consolidated Financial Results	2005		2005		2006			2007		2007		2008
										(unaudited)
	(in millions)

Loss of extinguishment of debt(a)	$	8.1	$	—	$	23.4		$	1.3	$	—	$	—
Inventory fair market value adjustment(b)		—		16.6		—			—		—		—
Funded letter of credit expense & interest rate swap not included in interest expense(c)		—		2.3		—			1.8		0.2		3.3
Major scheduled turnaround expense(d)		—		—		6.6			76.4		76.8		—
Loss on termination of swap(e)		—		25.0		—			—		—		—
Unrealized (gain) loss from Cash Flow Swap		—		235.9		(126.8	)		103.2		188.5		29.9


(a)		Represents 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, the write-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006 and the write-off of $1.3 million in connection with the repayment and termination of three credit facilities on October 26, 2007.

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

(c)		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 credit facility.

(d)		Represents expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery.

(e)		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.


(4)		Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the unrealized portion of 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

~~104~~


		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. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not as a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. The Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, ~~so long as~~ at which time the ~~time of reduction or termination, we pay the amount of~~ unrealized ~~losses associated with the amount reduced or terminated.~~loss would become a fixed obligation.

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 absolute 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 absolute 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 (loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business and assessing its growth and

106


		profitability from a strategic and financial planning perspective, management and our board of directors considers our GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit.

Net income (loss) 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 financial performance or liquidity but instead should be utilized as a supplemental measure of performance in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark to market adjustments, the measure does not reflect the fair market value of our cash flow swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies.

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

Immediate

Predecessor Successor
174 Days
233 Days
Year

Ended
Ended
Ended
Three Months

June 23, December 31, December 31, Ended March 31,
Consolidated Financial Results

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)

Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap $ 52.4 $ 23.6 $ 115.4 $ (5.6 ) $ (82.4 ) $ 30.6
Plus:
Unrealized gain or (loss) from Cash Flow Swap, net of taxes — (142.8 ) 76.2 (62.0 ) (72.0 ) (8.4 )

Net income (loss) $ 52.4 $ (119.2 ) $ 191.6 $ (67.6 ) $ (154.4 ) $ 22.2


	Immediate
	Predecessor		Successor
	174 Days		233 Days			Year
	Ended		Ended			Ended					Six Months
	June 23,		December 31,			December 31,					Ended June 30,
Consolidated Financial Results	2005		2005			2006		2007			2007			2008
											(unaudited)
	(in millions)

Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap	$	52.4	$	23.6		$	115.4	$	(5.6	)	$	59.0		$	71.2
Plus:
Unrealized gain or (loss) from Cash Flow Swap, net of taxes		—		(142.8	)		76.2		(62.0	)		(113.3	)		(18.0	)

Net income (loss)	$	52.4	$	(119.2	)	$	191.6	$	(67.6	)	$	(54.3	)	$	53.2

~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 Compared to the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007 (Consolidated)

Net Sales. Consolidated net sales were ~~$1,223.0~~$2,735.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to ~~$390.5~~$1,233.9 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$832.5~~$1,501.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily due to an increase in petroleum net sales of ~~$816.0~~$1,466.2 million that resulted from higher sales volumes ($~~592.1~~874.7 million) ~~primarily resulting from the refinery turnaround which began in February 2007 and was completed in April 2007 and~~, coupled with higher product prices ($~~223.9~~591.5 million). ~~Nitrogen~~In addition, nitrogen fertilizer net sales increased ~~$24.0~~$47.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 ~~primarily~~ due to higher sales volumes ($13.7 million), together with higher plant gate prices ~~partially offset by reductions in overall sales volume.~~($33.4 million).

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold ~~exclusive~~(exclusive of depreciation and ~~amortization~~amortization) was ~~$1,036.2~~$2,323.7 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$303.7~~$873.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$732.5~~$1,450.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily ~~resulted from a significant increase in refined fuel production volumes over the comparable period~~ due to the refinery turnaround ~~which~~that began in February 2007 and was completed in April 2007. In addition to the impact of the turnaround, higher crude oil prices, increased sales volumes and the impact of FIFO accounting impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil for the six months ended June 30, 2008 was $105.87, compared to $57.14 for the comparable period of 2007, an increase of 85%. Sales volume of refined fuels increased 54% for the six months ended June 30, 2008 as compared to the six months ended June 30, 2007 principally due to the turnaround.

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Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses ~~exclusive~~(exclusive of depreciation and ~~amortization~~amortization) were ~~$60.6~~$122.9 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$113.4~~$174.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This decrease of ~~$52.8~~$51.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was due to a decrease in petroleum direct operating expenses of ~~$56.4~~$58.1 million, primarily related to ~~decreases in expenses associated with~~ the refinery turnaround, and ~~labor, partially offset by increases~~an increase in ~~expenses associated with utilities and energy, repairs and maintenance, production chemicals, taxes and environmental. Nitrogen~~nitrogen fertilizer direct operating expenses increased during the comparable period by $3.6 million, primarily due to increases in expenses associated with taxes, repairs and maintenance, labor, catalysts and outsides services, partially offset by decreases in expenses associated with utilities, royalties and other and equipmentof $6.7 million.

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rental. The nitrogen fertilizer facility was subject to a property tax abatement which expired beginning in 2008. We have estimated our accrued property tax liability based upon the assessment value received by the county.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses were ~~$13.4~~$28.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$13.2~~$28.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This variance was primarily the result of ~~decreases in administrative labor ($3.0 million) primarily related to deferred compensation which was more than offset by~~ increases in expenses ~~related to~~associated with outside services ($~~2.2~~4.6 million), bad debt reserve ($~~0.4~~3.9 million), ~~insurance~~the write-off of deferred CVR Partners, LP initial public offering costs ($~~0.3~~2.6 million), ~~bank charges ($0.2 million), public relations ($0.1 million) and~~ other selling, general and administrative costs ($~~0.1~~1.1 million)., asset write-off ($1.0 million) and insurance ($0.7 million) partially offset by a reduction in expenses associated with administrative labor ($14.1 million) primarily related to share-based compensation.

Net Costs Associated with Flood. Consolidated net costs associated with the flood for the ~~three~~six months ended ~~March 31,~~June 30, 2008 approximated ~~$5.8~~$9.7 million as compared to ~~none~~$2.1 for the ~~three~~six months ended ~~March 31,~~June 30, 2007. As the flood occurred in the second and third quarter of 2007 there was no financial statement impact in the first quarter of 2007. Total gross costs recorded for the three months ended March 31, 2008 were approximately $7.6 million. Of these gross costs, approximately $3.8 million were associated with repair and other matters as a result of the damage to the Company’s facilities. Included in this cost was $0.3 million of professional fees and $3.5 million for other repair and related costs. There were also approximately $3.8 million of costs recorded with respect to environmental remediation and property damage. Total accounts receivable from insurers approximated $85.7 million at March 31, 2008, for which we believe collection is probable.

Depreciation and Amortization. Consolidated depreciation and amortization was ~~$19.6~~$40.7 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$14.2~~$32.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase ~~in depreciation and amortization~~of $8.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of the ~~completion of several large~~expansion completed in April 2007 and a significant capital ~~projects.~~project completed in February 2008 in the petroleum business.

Operating Income. Consolidated operating income was ~~$87.4~~$210.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to an operating ~~loss~~income of ~~$54.0~~$123.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. For the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007, petroleum operating income increased ~~$127.1~~by $62.6 million and nitrogen fertilizer operating income increased by ~~$16.7~~$28.2 million.

Interest Expense. Consolidated interest expense for the ~~three~~six months ended ~~March 31,~~June 30, 2008 was ~~$11.3~~$20.8 million as compared to interest expense of ~~$11.9~~$27.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This 5%25% decrease for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 primarily resulted from an overall decrease in the index rates (primarily LIBOR) and a decrease in average borrowings outstanding during the six months ended June 30, 2008. Partially offsetting these positive impacts on consolidated interest expense was a $5.1 million decrease in capitalized interest over the comparable ~~periods.~~period due to the decrease of capital projects in progress during the six months ended June 30, 2008. Additionally, consolidated interest expense during the six months ended June 30, 2008 benefited from decreases in the applicable margins under our Credit Facility dated December 28, 2006 as compared to our borrowing facility completed in association with the Subsequent Acquisition that was in effect during the six months ended June 30, 2007. See “— Liquidity and Capital Resources — Debt.”

Interest Income. Interest income was ~~$0.7~~$1.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$0.5~~$0.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007.

Loss on Derivatives, ~~Net.~~net. We have 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~~Activities.. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, we incurred ~~$47.9~~a $127.2 million ~~in losses~~net loss on ~~derivatives. This compares~~derivatives as compared to a ~~$137.0~~$292.4 million loss on derivatives for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This significant decrease in loss on derivatives, net for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily attributable to the realized and unrealized losses on our Cash Flow Swap. Realized losses

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on the Cash Flow Swap for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and the ~~three~~six months ended ~~March 31,~~June 30, 2007 were ~~$21.5~~$74.0 million and ~~$8.5~~$97.2 million, respectively. The ~~increase~~decrease in realized losses over the comparable periods was primarily the result of ~~higher net barrels hedged~~lower average crack spreads for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007.

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Unrealized losses represent the change in the mark-to-market value on the unrealized portion of the Cash Flow Swap based on changes in the forward NYMEX crack spread that is the basis for the Cash Flow Swap. ~~Unrealized losses on our Cash Flow Swap for~~In addition to the ~~three months ended March 31, 2008 and the three months ended March 31, 2007 were $13.9 million and $119.7 million, respectively. This change in the unrealized loss~~mark-to-market value of the Cash Flow Swap, ~~over the comparable periods reflect decreases in the crack spread values on the unrealized positions comprising the Cash Flow Swap. In addition to the change in the NYMEX crack spread,~~ the outstanding term of the Cash Flow Swap at the end of each period also affects the impact that the changes ofin the ~~underlying~~forward NYMEX crack spread may have on the unrealized gain or loss. As of ~~March 31,~~June 30, 2008, the Cash Flow Swap had a remaining term of approximately two years ~~and three months~~ whereas as of ~~March 31,~~June 30, 2007, the remaining term ~~on the Cash Flow Swap~~ was approximately three ~~years and three months.~~years. As a result of ~~the~~those shorter remaining term as of ~~March 31,~~June 30, 2008, a similar change in the forward NYMEX crack spread will have a smaller impact on the unrealized ~~gains~~gain or ~~losses.~~loss. Unrealized losses on our Cash Flow Swap for the six months ended June 30, 2008 and the six months ended June 30, 2007 were $29.9 million and $188.5 million, respectively.

Provision for Income Taxes. Income tax expense for the ~~three~~six months ended ~~March 31,~~June 30, 2008 was ~~$6.9~~approximately $10.9 million, or ~~23.6%~~17% of ~~income~~earnings before income taxes, as compared to income tax benefit of ~~$(47.3)~~approximately $141.0 million ~~or 23.4% of~~for the six months ended June 30, 2007. The annualized effective tax rate for 2008, which was applied to earnings before income taxes for the ~~three months~~six month period ended ~~March 31,~~June 30, 2008, is lower than the comparable annualized effective tax rate for 2007, which was applied to loss before income taxes for the six month period ended June 30, 2007, primarily due to the correlation between the amount of income tax credits which were projected to be generated in 2007 in comparison with the projected pre-tax loss for 2007.

Minority Interest in ~~(Income) Loss~~(income) loss of Subsidiaries. Minority interest in (income) loss of subsidiaries for the ~~three~~six months ended ~~March 31,~~June 30, 2007 was ~~$0.7 million compared to none during the three months ended March 31, 2008.~~$0.2 million. Minority interest ~~for~~in the 2007 period related to common stock in two of our subsidiaries owned by our chief executive officer. ~~In October 2007, in connection with our initial public offering, our chief executive officer exchanged his common stock in our subsidiaries for common stock of CVR Energy.~~

Net ~~Income.~~Income (Loss). For the ~~three~~six months ended ~~March 31,~~June 30, 2008, net income ~~increased to $22.2~~was $53.2 million as compared to a net loss of ~~$(154.4)~~$54.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. Net income increased $176.6 million compared to the first quarter of 2007 primarily due to the planned turnaround that commenced in February 2007. For the three months ended March 31, 2007 the Company incurred costs of $66.0 million associated with the refinery turnaround. In addition the Company’s net income was favorably impacted by a significant change in the fair value of the Cash Flow Swap over the comparable periods.

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006 (Consolidated).

Net Sales. Consolidated net sales were $2,966.9 million for the year ended December 31, 2007 compared to $3,037.6 million for the year ended December 31, 2006. The decrease of $70.7 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily due to a decrease in petroleum net sales of $74.2 million that resulted from lower sales volumes ($576.9 million), partially offset by higher product prices ($502.7 million). Nitrogen fertilizer net sales increased $3.4 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 as reductions in overall sales volumes ($31.0 million) were more than offset by higher plant gate prices ($34.4 million). The sales volume decrease for the refinery primarily resulted from a significant reduction in refined fuel production volumes over the comparable periods due to the refinery turnaround which began in February 2007 and was completed in April 2007 and the refinery downtime resulting from the flood. The flood was also a major contributor to lower nitrogen fertilizer sales volume.

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold exclusive of depreciation and amortization was $2,308.8 million for the year ended December 31, 2007 as compared to $2,443.4 million for the year ended December 31, 2006. The decrease of $134.6 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 primarily resulted from a significant reduction in refined fuel production volumes

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over the comparable periods due to the refinery turnaround which began in February 2007 and was completed in April 2007 and the refinery downtime resulting from the flood.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses exclusive of depreciation and amortization were $276.1 million for the year

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ended December 31, 2007 as compared to $199.0 million for the year ended December 31, 2006. This increase of $77.1 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was due to an increase in petroleum direct operating expenses of $74.2 million, primarily related to the refinery turnaround, and an increase in nitrogen fertilizer direct operating expenses of $3.0 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses exclusive of depreciation and amortization were $93.1 million for the year ended December 31, 2007 as compared to $62.6 million for the year ended December 31, 2006. This variance was primarily the result of increases in administrative labor primarily related to deferred compensation and share-based compensation ($19.1 million), other costs primarily related to the termination of the management agreements with Goldman Sachs Funds and Kelso Funds ($10.6 million), bank charges ($1.3 million) and office costs ($0.3 million).

Net Costs Associated with Flood. Consolidated net costs associated with flood for the year ended December 31, 2007 approximated $41.5 million as compared to none for the year ended December 31, 2006. Total gross costs associated with the flood for the year ended December 31, 2007 were approximately $146.8 million. Of these gross costs, approximately $101.9 million were associated with repair and other matters as a result of the physical damage to the Company’s facilities and approximately $44.9 million were associated with the environmental remediation and property damage. Included in the gross costs associated with the flood were certain costs that are excluded from the accounts receivable from insurers of $85.3 million at December 31, 2007, for which we believe collection is probable. The costs excluded from the accounts receivable from insurers were $7.6 million of depreciation for the temporarily idled facilities, $3.6 million of uninsured losses within the Company’s insurance deductibles, $6.8 million of uninsured expenses and $23.5 million recorded with respect to environmental remediation and property damage. As of December 31, 2007, $20.0 million of insurance recoveries recorded in 2007 had been collected and are not reflected in the accounts receivable from insurers balance at December 31, 2007.

Depreciation and Amortization. Consolidated depreciation and amortization was $60.8 million for the year ended December 31, 2007 as compared to $51.0 million for the year ended December 31, 2006. During the restoration period for the refinery and our nitrogen fertilizer operations due to the flood, $7.6 million of depreciation and amortization was reclassified into net costs associated with flood. Adjusting for this $7.6 million reclassification, the increase in consolidated depreciation and amortization for the year ended December 31, 2007 compared to the year ended December 31, 2006 would have been approximately $17.4 million. This adjusted increase in consolidated depreciation and amortization for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of the completion of the several large capital projects in late 2006 and during the year ended December 31, 2007 in our Petroleum business.

Operating Income. Consolidated operating income was $186.6 million for the year ended December 31, 2007 as compared to operating income of $281.6 million for the year ended December 31, 2006. For the year ended December 31, 2007 as compared to the year ended December 31, 2006, petroleum operating income decreased $100.7 million primarily as a result of the refinery turnaround which began in February 2007 and was completed in April 2007 and the refinery downtime associated with the flood. For the year ended December 31, 2007 as compared to the year ended December 31, 2006, nitrogen fertilizer operating income increased by $9.8 million as downtime and expenses associated with the flood and increases in direct operating expenses were more than offset by a reduction in cost of product sold and higher plant gate prices.

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Interest Expense. Consolidated interest expense for the year ended December 31, 2007 was $61.1 million as compared to interest expense of $43.9 million for the year ended December 31, 2006. This 39% increase for the year ended December 31, 2007 as compared to the year ended December 31, 2006 primarily resulted from an overall increase in the index rates (primarily LIBOR) and an increase in average borrowings outstanding during the comparable periods. Partially offsetting

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these negative impacts on consolidated interest expense was a $0.4 million increase in capitalized interest over the comparable periods. Additionally, consolidated interest expense over the comparable periods was partially offset by decreases in the applicable margins under our credit facility dated December 28, 2006 as compared to our prior borrowing facility in effect for substantially all of the year ended December 31, 2006.

Interest Income. Interest income was $1.1 million for the year ended December 31, 2007 as compared to $3.5 million for the year ended December 31, 2006.

Gain (loss) on Derivatives. We have 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. For the year ended December 31, 2007, we incurred $282.0 million in losses on derivatives. This compares to a $94.5 million gain on derivatives for the year ended December 31, 2006. This significant change in gain (loss) on derivatives for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily attributable to the realized and unrealized gains (losses) on our Cash Flow Swap. Realized losses on the Cash Flow Swap for the year ended December 31, 2007 and the year ended December 31, 2006 were $157.2 million and $46.8 million, respectively. The increase in realized losses over the comparable periods was primarily the result of higher average absolute crack spreads for the year ended December 31, 2007 as compared to the year ended December 31, 2006. Unrealized gains or losses represent the change in the mark-to-market value on the unrealized portion of the Cash Flow Swap based on changes in the NYMEX crack spread that is the basis for the Cash Flow Swap. Unrealized losses on our Cash Flow Swap for the year ended December 31, 2007 were $103.2 million and reflect an increase in the crack spread values on the unrealized positions comprising the Cash Flow Swap. In contrast, the unrealized portion of the Cash Flow Swap for the year ended December 31, 2006 reported mark-to-market gains of $126.8 million and reflect a decrease in the crack spread values on the unrealized positions comprising the Cash Flow Swap. In addition, the outstanding term of the Cash Flow Swap at the end of each period also affects the impact of changes in the underlying crack spread. As of December 31, 2007, the Cash Flow Swap had a remaining term of approximately two years and six months whereas as of December, 2006, the remaining term on the Cash Flow Swap was approximately three years and six months. As a result of the longer remaining term as of December 31, 2006, a similar change in crack spread will have a greater impact on the unrealized gains or losses.

Provision for Income Taxes. Income tax benefit for the year ended December 31, 2007 was $88.5 million, or 57% of loss before income taxes, as compared to income tax expense of $119.8 million, or 39% of earnings before income taxes, for the year ended December 31, 2006. Our effective tax rate increased in the year ended December 31, 2007 as compared to the year ended December 31, 2006 primarily due to the impact of the American Jobs Creation Act of 2004, which provides an income tax credit to small business refiners related to the production of ultra low sulfur diesel. We recognized an income tax benefit of approximately $17.3 million in 2007 compared to $4.5 million in 2006 on a credit of approximately $26.6 million in 2007 compared to a credit of approximately $6.9 million in 2006 related to the production of ultra low sulfur diesel. In addition, state income tax credits, net of federal expense, approximating $19.8 million were earned and recorded in 2007 that related to the expansion of the facilities in Kansas.

Minority Interest in (Income) Loss of Subsidiaries. Minority interest in loss of subsidiaries for the year ended December 31, 2007 was $0.2 million. Minority interest relates to common stock in two of our subsidiaries owned by our chief executive officer. In October 2007, in connection with our

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initial public offering, our chief executive officer exchanged his common stock in our subsidiaries for common stock of CVR Energy.

Net Income. For the year ended December 31, 2007, net income decreased to a net loss of $67.6 million as compared to net income of $191.6 million for the year ended December 31, 2006. Net income decreased $259.2 million for the year ended December 31, 2007 as compared to the year

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ended December 31, 2006, primarily due to the refinery turnaround, downtime and costs associated with the flood and a significant change in the value of the Cash Flow Swap over the comparable periods.

Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Consolidated).

Net Sales. Consolidated net sales were $3,037.6 million for the year ended December 31, 2006 compared to $980.7 million for the 174 days ended June 23, 2005 and $1,454.3 million for the 233 days ended December 31, 2005. The increase of $602.6 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was primarily due to an increase in petroleum net sales of $613.2 million that resulted from significantly higher product prices ($384.1 million) and increased sales volumes ($229.1 million) over the comparable periods. Nitrogen fertilizer net sales decreased $10.5 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 due to decreased selling prices ($1.6 million) and a reduction in overall sales volumes ($8.9 million).

Cost of Product Sold Exclusive of Depreciation and Amortization. Consolidated cost of product sold exclusive of depreciation and amortization was $2,443.4 million for the year ended December 31, 2006 as compared to $768.0 million for the 174 days ended June 23, 2005 and $1,168.1 million for the 233 days ended December 31, 2005. The increase of $507.3 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was primarily due to an increase in crude oil prices, sales volumes and the impact of FIFO accounting in our petroleum business. The nitrogen fertilizer business accounted for approximately $2.3 million of the increase in cost of products sold over the comparable period primarily related to increases in freight expense.

Depreciation and Amortization. Consolidated depreciation and amortization was $51.0 million for the year ended December 31, 2006 as compared to $1.1 million for the 174 days ended June 23, 2005 and $24.0 million for the 233 days ended December 31, 2005. The increase of $25.9 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was due to an increase in petroleum depreciation and amortization of $16.6 million and an increase in nitrogen fertilizer depreciation and amortization of $8.4 million.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Consolidated direct operating expenses exclusive of depreciation and amortization were $199.0 million for the year ended December 31, 2006 as compared to $80.9 million for the 174 days ended June 23, 2005 and $85.3 million for the 233 days ended December 31, 2005. This increase of $32.8 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was due to an increase in petroleum direct operating expenses of $26.5 million and an increase in nitrogen fertilizer direct operating expenses of $6.2 million.

Selling, General and Administrative Expenses Exclusive of Depreciation and Amortization. Consolidated selling, general and administrative expenses were $62.6 million for the year ended December 31, 2006 as compared to $18.4 million for the 174 days ended June 23, 2005 and $18.4 million for the 233 days ended December 31, 2005. Consolidated selling, general and administrative expenses for the 174 days ended June 23, 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 $29.1 million for the year ended

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December 31, 2006 as compared to the combined periods ended December 31, 2005. This variance was primarily the result of increases in administrative labor related to increased headcount and share-based compensation ($18.6 million), office costs ($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

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not in place for approximately six months in the comparable period ($2.1 million), public relations expense ($0.5 million) and outside services expense ($2.4 million).

Operating Income. Consolidated operating income was $281.6 million for the year ended December 31, 2006 as compared to $112.3 million for the 174 days ended June 23, 2005 and $158.5 million for the 233 days ended December 31, 2005. For the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005, petroleum operating income increased $45.9 million and nitrogen fertilizer operating income decreased by $34.2 million.

Interest Expense. We reported consolidated interest expense for the year ended December 31, 2006 of $43.9 million as compared to interest expense of $7.8 million for the 174 days ended June 23, 2005 and $25.0 million for the 233 days ended December 31, 2005. This 34% increase for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was the direct result of increased average borrowings over the comparable periods associated with both our credit facility dated December 28, 2006 and our borrowing facility completed in association with the Subsequent Acquisition and an increase in the actual rate of our borrowings due primarily to increases both in index rates (LIBOR and prime rate) and applicable margins. See “— Liquidity and Capital Resources — Debt.” 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 of Our Financial Results.”

Interest Income. Interest income was $3.5 million for the year ended December 31, 2006 as compared to $0.5 million for the 174 days ended June 23, 2005 and $1.0 million for the 233 days ended December 31, 2005. The increase for the year ended December 31, 2006 as compared to the combined periods ended December 31, 2005 was primarily due to larger cash balances and higher yields on invested cash.

Gain (loss) on Derivatives. For the year ended December 31, 2006, we reported $94.5 million in gains on derivatives. This compares to a $7.7 million loss on derivatives for the 174 days ended June 23, 2005 and a $316.1 million loss on derivatives for the 233 days ended December 31, 2005. This significant change in gain (loss) on derivatives for the year ended December 31, 2006 as compared to the combined period ended December 31, 2005 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 December 31, 2006 (approximately three years and six months) and the NYMEX crack spread that is the basis for the underlying swap contracts that comprised the Cash Flow Swap had declined during this period, the unrealized gains on the Cash Flow Swap increased significantly. The $323.7 million loss on derivatives during the combined period ended December 31, 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 during the year ended December 31, 2005. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”

Extinguishment of Debt. On December 28, 2006, Coffeyville Acquisition LLC refinanced its existing first lien credit facility and second lien credit facility and raised $1.075 billion in long-term debt commitments under the new credit facility. See “— Liquidity and Capital Resources — Debt.” As a result of the retirement of the first and second lien credit facilities with the proceeds of the credit facility, we recognized $23.4 million as a loss on extinguishment of debt in 2006. On June 24, 2005

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and in connection with the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC, we raised $800.0 million in long-term debt commitments under both the first lien credit facility and second lien credit facility. See “— Factors Affecting Comparability of Our Financial Results” and “— Liquidity

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and Capital Resources — Debt.” As a result of the retirement of Immediate Predecessor’s outstanding indebtedness consisting of $150.0 million term loan and revolving credit facilities, we recognized $8.1 million as a loss on extinguishment of debt in 2005.

Other Income (Expense). For the year ended December 31, 2006, other expense was $0.9 million as compared to other expense of $0.8 million for the 174 days ended June 23, 2005 and other expense of $0.6 million for the 233 days ended December 31, 2005.

Provision for Income Taxes. Income tax expense for the year ended December 31, 2006 was $119.8 million, or 38.5% of earnings before income taxes, as compared to a tax benefit of $26.9 million, or 28.7% of earnings before income taxes, for the combined periods ended December 31, 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 year ended December 31, 2006, net income increased to $191.6 million as compared to net income of $52.4 million for the 174 days ended June 23, 2005 and a net loss of $119.2 million for the 233 days ended December 31, 2005. Net income increased $258.4 million for the year ended December 31, 2006 as compared to the combined periods ended December 31, 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.

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

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usefulness as a comparative measure. The following table shows selected information about our petroleum business including refining margin:

Immediate

Predecessor Successor
174 Days
233 Days
Year
Year

Ended
Ended
Ended
Ended
Three Months

June 23, December 31, December 31, December 31, Ended March 31,

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)

Petroleum Business:

Net sales $ 903.8 $ 1,363.4 $ 2,880.4 $ 2,806.2 $ 352.5 $ 1,168.5
Cost of product sold (exclusive of depreciation and amortization) 761.7 1,156.2 2,422.7 2,300.2 298.5 1,035.1
Direct operating expenses (exclusive of depreciation and amortization) 52.6 56.2 135.3 209.5 96.7 40.3
Net costs associated with flood — — — 36.7 — 5.5
Depreciation and amortization 0.8 15.6 33.0 43.0 9.8 14.9

Gross profit (loss) $ 88.7 $ 135.4 $ 289.4 $ 216.8 $ (52.5 ) $ 72.7
Plus direct operating expenses (exclusive of depreciation and amortization) 52.6 56.2 135.3 209.5 96.7 40.3
Plus net costs associated with flood — — — 36.7 — 5.5
Plus depreciation and amortization 0.8 15.6 33.0 43.0 9.8 14.9

Refining margin $ 142.1 $ 207.2 $ 457.7 $ 506.0 $ 54.0 $ 133.4
Refining margin per crude oil throughput barrel $ 9.28 $ 11.55 $ 13.27 $ 18.17 $ 12.69 $ 13.76
Gross profit (loss) per crude oil throughput barrel $ 5.79 $ 7.55 $ 8.39 $ 7.79 $ (12.34 ) $ 7.50
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel $ 3.44 $ 3.13 $ 3.92 $ 7.52 �� $ 22.73 $ 4.16
Operating income (loss) 76.7 123.0 245.6 144.9 (63.5 ) 63.6


	Immediate
	Predecessor		Successor
	174 Days		233 Days		Year		Year
	Ended		Ended		Ended		Ended		Six Months
	June 23,		December 31,		December 31,		December 31,		Ended June 30,
	2005		2005		2006		2007		2007		2008
									(unaudited)
	(in millions, except as otherwise indicated)

Petroleum Business:
Net sales	$	903.8	$	1,363.4	$	2,880.4	$	2,806.2	$	1,161.4	$	2,627.6
Cost of product sold (exclusive of depreciation and amortization)		761.7		1,156.2		2,422.7		2,300.2		869.1		2,320.6
Direct operating expenses (exclusive of depreciation and amortization)		52.6		56.2		135.3		209.5		141.1		83.0
Net costs associated with flood		—		—		—		36.7		2.0		8.9
Depreciation and amortization		0.8		15.6		33.0		43.0		23.1		31.2

Gross profit	$	88.7	$	135.4	$	289.4	$	216.8	$	126.1	$	183.9
Plus direct operating expenses (exclusive of depreciation and amortization)		52.6		56.2		135.3		209.5		141.1		83.0
Plus net costs associated with flood		—		—		—		36.7		2.0		8.9
Plus depreciation and amortization		0.8		15.6		33.0		43.0		23.1		31.2

Refining margin(1)	$	142.1	$	207.2	$	457.7	$	506.0	$	292.3	$	307.0
Refining margin per crude oil throughput barrel (dollars)(1)	$	9.28	$	11.55	$	13.27	$	18.17	$	22.71	$	15.98
Gross profit per crude oil throughput barrel (dollars)	$	5.79	$	7.55	$	8.39	$	7.79	$	9.80	$	9.57
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)	$	3.44	$	3.13	$	3.92	$	7.52	$	10.96	$	4.32
Operating income		76.7		123.0		245.6		144.9		102.9		165.5

Immediate

Predecessor

and Successor

Combined Successor
Year Ended
Year Ended
Year Ended
Three Months

December 31, December 31, December 31, Ended March 31,

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(dollars per barrel, except as indicated)

Market Indicators

West Texas Intermediate (WTI) crude oil $ 56.70 $ 66.25 $ 72.36 $ 58.27 $ 97.82
NYMEX 2-1-1 Crack Spread 11.62 10.84 13.95 12.17 11.81
Crude Oil Differentials:
WTI less WTS (sour) 4.73 5.36 5.16 4.26 4.63
WTI less Maya (heavy sour) 15.67 14.99 12.54 14.80 19.84
WTI less Dated Brent (foreign) 2.18 1.13 (0.02 ) 0.51 1.10
PADD II Group 3 versus NYMEX Basis:
Gasoline (0.53 ) 1.52 3.56 (0.54 ) (1.46 )
Heating Oil 3.20 7.42 7.95 8.77 3.65
PADD II Group 3 versus NYMEX Crack:
Gasoline 10.53 12.26 18.34 12.43 4.95
Heating Oil 15.60 18.77 21.40 20.57 20.77


(1)		Refining margin is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization). Refining margin is a non-GAAP measure that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Each of the components used in this calculation (net sales and cost of product sold (exclusive of depreciation and amortization)) is taken directly from our 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. In order to derive the refining margin per crude oil throughput barrel, we utilize the total dollar figures for refining margin as derived above and divide by the applicable number of crude oil throughput barrels for the period.

~~114~~115

Immediate

Predecessor

and Successor

Combined Successor
Year Ended
Year Ended
Year Ended
Three Months

December 31, December 31, December 31, Ended March 31,

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(dollars per barrel, except as indicated)

Company Operating Statistics

Per barrel profit, margin and expense of crude oil throughput:
Refining margin $ 10.50 $ 13.27 $ 18.17 $ 12.69 $ 13.76
Gross profit $ 6.74 $ 8.39 $ 7.79 $ (12.34 ) $ 7.50
Direct operating expenses (exclusive of depreciation and amortization) 3.27 3.92 7.52 22.73 4.16
Per gallon sales price:
Gasoline 1.61 1.88 2.20 1.59 2.45
Distillate 1.71 1.99 2.28 1.78 2.85


	Immediate
	Predecessor
	and Successor
	Combined			Successor
	Year Ended			Year Ended		Year Ended			Six Months
	December 31,			December 31,		December 31,			Ended June 30,
	2005			2006		2007			2007			2008
	(unaudited)
	(dollars per barrel, except as indicated)

Market Indicators
West Texas Intermediate (WTI) crude oil	$	56.70		$	66.25	$	72.36		$	61.67		$	111.12
NYMEX 2-1-1 Crack Spread		11.62			10.84		13.95			17.13			14.48
Crude Oil Differentials:
WTI less WTS (sour)		4.73			5.36		5.16			4.43			4.63
WTI less Maya (heavy sour)		15.67			14.99		12.54			16.39			21.52
WTI less Dated Brent (foreign)		2.18			1.13		(0.02	)		(1.54	)		2.07
PADD II Group 3 Basis:
Gasoline		(0.53	)		1.52		3.56			2.59			(2.56	)
Heating Oil		3.20			7.42		7.95			9.54			3.91
PADD II Group 3 Crack:
Gasoline		10.42			12.05		18.18			23.42			5.43
Heating Oil		15.49			18.56		21.24			22.97			24.88
Company Operating Statistics
Per barrel profit, margin and expense of crude oil throughput:
Refining margin	$	10.50		$	13.27	$	18.17		$	22.71		$	15.98
Gross profit	$	6.74		$	8.39	$	7.79		$	9.80		$	9.57
Direct operating expenses (exclusive of depreciation and amortization)		3.27			3.92		7.52			10.96			4.32
Per gallon sales price:
Gasoline		1.61			1.88		2.20			2.09			2.77
Distillate		1.71			1.99		2.28			2.03			3.26

Immediate

Predecessor and

Successor Combined
Successor
Successor
Three Months

December 31,
December 31,
December 31,
Ended March 31,
2005 2006 2007 2007 2008
Selected Company
Barrels
Barrels
Barrels
Barrels
Barrels

Volumetric Data

per Day
% per Day % per Day % per Day % per Day %
(unaudited) (unaudited)

Production:
Total gasoline 45,275 43.8 48,248 44.7 37,017 42.9 23,499 43.8 59,662 47.5
Total distillate 39,997 38.7 42,175 39.0 34,814 40.4 21,976 40.9 48,591 38.7
Total other 18,090 17.5 17,608 16.3 14,370 16.7 8,214 15.3 17,361 13.8

Total all production 103,362 100.0 108,031 100.0 86,201 100.0 53,689 100.0 125,614 100.0
Crude oil throughput 91,097 92.6 94,524 92.1 76,285 93.0 47,267 92.7 106,530 89.0
All other inputs 7,246 7.4 8,067 7.9 5,780 7.0 3,716 7.3 13,197 11.0

Total feedstocks 98,343 100.0 102,591 100.0 82,065 100.0 50,983 100.0 119,727 100.0
Crude oil throughput by crude type:
Sweet 13,958,567 42.0 17,481,803 50.7 18,190,459 65.3 2,782,136 65.4 6,573,627 67.8
Light/medium-sour 19,291,951 58.0 16,695,173 48.4 6,465,368 23.2 1,454,878 34.2 1,785,669 18.4
Heavy sour — — 324,312 0.9 3,188,133 11.5 17,016 0.4 1,334,889 13.8

Total crude oil throughput 33,250,518 100.0 34,501,288 100.0 27,843,960 100.0 4,254,030 100.0 9,694,185 100.0


	Immediate
	Predecessor and
	Successor Combined				Successor				Successor				Six Months
	December 31,				December 31,				December 31,				Ended June 30,
	2005				2006				2007				2007				2008
Selected Company	Barrels				Barrels				Barrels				Barrels				Barrels
Volumetric Data	per Day		%		per Day		%		per Day		%		per Day		%		per Day		%
	(unaudited)

Production:
Total gasoline		45,275		43.8		48,248		44.7		37,017		42.9		31,971		41.0		55,845		45.6
Total distillate		39,997		38.7		42,175		39.0		34,814		40.4		32,592		41.7		48,379		39.4
Total other		18,090		17.5		17,608		16.3		14,370		16.7		13,535		17.3		18,349		15.0

Total all production		103,362		100.0		108,031		100.0		86,201		100.0		78,098		100.0		122,573		100.0
Crude oil throughput		91,097		92.6		94,524		92.1		76,285		93.0		71,098		95.0		105,544		90.3
All other inputs		7,246		7.4		8,067		7.9		5,780		7.0		3,763		5.0		11,300		9.7

Total feedstocks		98,343		100.0		102,591		100.0		82,065		100.0		74,861		100.0		116,844		100.0
Crude oil throughput by crude type:
Sweet		13,958,567		42.0		17,481,803		50.7		18,190,459		65.3		8,362,963		65.0		13,350,256		69.5
Light/medium-sour		19,291,951		58.0		16,695,173		48.4		6,465,368		23.2		4,092,254		31.8		3,592,083		18.7
Heavy sour		—		—		324,312		0.9		3,188,133		11.5		413,505		3.2		2,266,662		11.8

Total crude oil throughput		33,250,518		100.0		34,501,288		100.0		27,843,960		100.0		12,868,722		100.0		19,209,001		100.0

116

~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 Compared to the ~~Year~~Six Months Ended ~~March 31,~~June 30, 2007 (Petroleum Business).

Net Sales. Petroleum net sales were ~~$1,168.5~~$2,627.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to ~~$352.5~~$1,161.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$816.0~~$1,466.2 million ~~during~~from the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of significantly higher sales volumes ($~~592.1~~874.7 million) and ~~higher~~increased product prices ($~~223.9~~591.5 million). Overall sales volumes of refined fuels for the ~~three~~six months ended ~~March 31,~~June 30, 2008 increased ~~110%~~54% as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increased sales volume ~~primarily~~ resulted primary from a significant ~~increase~~decrease in refined fuel production volumes over the ~~comparable periods~~six months ended June 30, 2007 due to the refinery turnaround which began in February 2007 and was completed in April 2007. Our average sales price per gallon for the ~~three~~six months ended

~~115~~

~~March 31,~~ June 30, 2008 for gasoline of ~~$2.45~~$2.77 and distillate of ~~$2.85~~$3.26 increased by ~~54%~~33% and ~~60%~~61%, respectively, as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007.

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~~(exclusive of depreciation and ~~amortization~~amortization) was ~~$1,035.1~~$2,320.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to ~~$298.5~~$869.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$736.6~~$1,451.5 million ~~during~~from the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of a significant increase in crude throughput due to ~~refinery downtime from~~ the refinery turnaround which began in February 2007 and was completed in April 2007. In addition to the ~~refinery~~impact of the turnaround, higher crude oil prices, increased sales volumes and the impact of FIFO accounting ~~also~~ impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil ~~consumed~~ for the ~~three~~six months ended ~~March 31,~~June 30, 2008 was ~~$92.35~~$105.87, compared to ~~$51.98~~$57.14 for the comparable period of 2007, an increase of ~~78%~~85%. Sales volume of refined fuels increased ~~110%~~54% for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31, 2007.~~June 30, 2007 principally due to the turnaround. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, we ~~had~~reported FIFO inventory gains of ~~$20.0~~$100.1 million compared to FIFO inventory gains of ~~$5.2~~$12.9 million for the comparable period of 2007. In 2007, as a result of the flood, our refinery exceeded the required average annual gasoline sulfur standard as mandated by our approved hardship waiver with the Environmental Protection Agency (“EPA”). In anticipation of a settlement with the EPA to resolve the non-compliance, we accrued a liability of approximately $3.5 million in the fourth quarter of 2007. During 2008, the matter was resolved with the EPA, and accordingly, the liability was reversed resulting in a reduction to cost of product sold (exclusive of depreciation and amortization) of approximately $3.5 million in the first quarter of 2008.

Refining margin per barrel of crude throughput ~~increased from $12.69~~decreased to $15.98 for the ~~three~~six months ended ~~March 31, 2007 to $13.76~~June 30, 2008 from $22.71 for the ~~three~~six months ended ~~March 31, 2008. Gross profit per barrel increased to $7.50 in the first quarter of 2008, up from a loss of $(12.34) in the equivalent period in 2007. The primary contributors~~June 30, 2007 primarily due to the positive variance in refining margin per barrel of crude throughput were an increase in FIFO inventory gains and increases in crude oil differentials over the comparable periods. Increased discounts for sour crude oils evidenced by the $0.37 per barrel, or 9%, increase in the spread between the WTI price, which is a market indicator for the price of light sweet crude, and the WTS price, which is an indicator for the price of sour crude, positively impacted refining margin for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007. Partially offsetting the positive effects of FIFO inventory gains and crude oil differentials was the 3%15% decrease ($~~0.36~~2.65 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods and ~~negative~~unfavorable regional differences between gasoline and distillate prices in our primary marketing region (the ~~mid-continent~~Coffeyville supply area) and those of the NYMEX. The average gasoline basis for the ~~three~~six months ended ~~March 31,~~June 30, 2008 decreased by ~~$0.92~~$5.15 per barrel to ~~($1.46)~~a negative basis of $2.56 per barrel compared to ~~($0.54)~~$2.59 per barrel in the comparable period of 2007. The average distillate basis for the six months ended June 30, 2008 decreased by ~~$5.12~~$5.63 per barrel to ~~$3.65~~$3.91 per barrel compared to ~~$8.77~~$9.54 per barrel in the comparable period of 2007.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our ~~petroleum~~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 (turnaround), labor and environmental compliance costs. Petroleum direct operating expenses ~~exclusive~~(exclusive of depreciation and ~~amortization~~amortization) were ~~$40.3~~$83.0 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to direct operating expenses of ~~$96.7~~$141.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The decrease of ~~$56.4~~$58.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was the result of decreases in expenses associated with the refinery turnaround ($~~66.0~~76.9 million), outside services ($1.1 million) and direct labor ($~~1.7~~1.0 million). These decreases in direct operating

~~116~~

expenses were partially offset by increases in expenses associated with ~~utilities~~energy and ~~energy ($4.3~~utilities

117

($7.2 million), repairs and maintenance ($~~3.0~~7.1 million), production chemicals ($~~2.1~~2.5 million), environmental compliance ($1.3 million), property taxes ($1.2 million), insurance ($0.8 million), rent and lease ($0.2 million) and ~~environmental~~operating materials ($~~0.5~~0.1 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude ~~oil~~ throughput for the ~~three~~six months ended ~~March 31,~~June 30, 2008 decreased to ~~$4.16~~$4.32 per barrel as compared to ~~$22.73~~$10.96 per barrel for the ~~three~~six months ended ~~March 31,~~June 30, 2007 principally due to ~~the 2007 downtime at the~~ refinery ~~for planned major maintenance~~turnaround expenses and the ~~corresponding~~related downtime associated with the turnaround and its impact on overall ~~crude oil throughput and~~ production volume.

Net Costs Associated with Flood. Petroleum net costs associated with the flood for the ~~three~~six months ended ~~March 31,~~June 30, 2008 approximated ~~$5.5 million. As the flood occurred in the second and third quarter of 2007, there were no flood related costs incurred in the first quarter of 2007. Total gross costs recorded~~$8.9 million as compared to $2.0 million for the ~~three~~six months ended March 31, 2008 were approximately $6.8 million. Of these gross costs approximately $3.0 million were associated with repair and other matters as a result of the physical damage to the refinery and approximately $3.8 million were associated with the environmental remediation and property damage. Total accounts receivable from insurers approximated $81.2 million at March 31, 2008, for which we believe collection is probable.June 30, 2007.

Depreciation and Amortization. Petroleum depreciation and amortization was ~~$14.9~~$31.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$9.8~~$23.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. ~~This~~The increase ~~in petroleum depreciation and amortization~~of $8.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of the completion of ~~several large~~the expansion in April 2007 and a significant capital ~~projects.~~project completed in February 2008.

Operating ~~Income (Loss).~~Income. Petroleum operating income was ~~$63.6~~$165.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to an operating ~~loss~~income of ~~$63.5~~$102.9 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This increase of ~~$127.1~~$62.6 million from the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of the refinery turnaround which began in February 2007 and was completed in April ~~2007~~2007. The turnaround negatively impacted daily refinery crude throughput and refined fuels production. In addition, direct operating expenses decreased substantially during the six months ended June 30, 2008 primarily due to decreases in expenses associated with the refinery turnaround ($~~66.0~~76.9 million), outside services ($1.1 million) and direct labor ($~~1.7~~1.0 million). These decreases in direct operating expenses were partially offset by increases in expenses associated with energy and utilities ~~and energy~~ ($~~4.3~~7.2 million), repairs and maintenance ($~~3.0~~7.1 million), production chemicals ($~~2.1~~2.5 million), environmental compliance ($1.3 million), property taxes ($1.2 million), insurance ($0.8 million), rent and ~~environmental~~lease ($~~0.5~~0.2 million) and operating materials ($0.1 million).

Year Ended December 31, 2007 Compared to the Year Ended December 31, 2006 (Petroleum Business).

Net Sales. Petroleum net sales were $2,806.2 million for the year ended December 31, 2007 compared to $2,880.4 million for the year ended December 31, 2006. The decrease of $74.2 million from the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of significantly lower sales volumes ($576.9 million), partially offset by higher product prices ($502.7 million). Overall sales volumes of refined fuels for the year ended December 31, 2007 decreased 18% as compared to the year ended December 31, 2006. The decreased sales volume primarily resulted from a significant reduction in refined fuel production volumes over the comparable periods due to the refinery turnaround which began in February 2007 and was completed in April 2007 and the refinery downtime resulting from the flood. Our average sales price per gallon for the year ended December 31, 2007 for gasoline of $2.20 and distillate of $2.28 increased by 17% and 15%, respectively, as compared to the year ended December 31, 2006.

~~117~~118

in April 2007 and the refinery downtime resulting from the flood. In addition to the refinery turnaround and the flood, crude oil prices, reduced sales volumes and the impact of FIFO accounting also impacted cost of product sold during the comparable periods. Our average cost per barrel of crude oil for the year ended December 31, 2007 was $70.06, compared to $61.71 for the comparable period of 2006, an increase of 14%. Sales volume of refined fuels decreased 18% for the year ended December 31, 2007 as compared to the year ended December 31, 2006 principally due to the refinery turnaround and flood. In addition, under our FIFO accounting method, changes in crude oil prices can cause fluctuations in the inventory valuation of our crude oil, work in process and finished goods, thereby resulting in FIFO inventory gains when crude oil prices increase and FIFO inventory losses when crude oil prices decrease. For the year ended December 31, 2007, we had FIFO inventory gains of ~~$70.5~~$69.9 million compared to FIFO inventory losses of ~~$7.6~~$1.2 million for the comparable period of 2006.

Refining margin per barrel of crude throughput increased from $13.27 for the year ended December 31, 2006 to $18.17 for the year ended December 31, 2007 primarily due to the 29% increase ($3.11 per barrel) in the average NYMEX 2-1-1 crack spread over the comparable periods and positive regional differences between gasoline and distillate prices in our primary marketing region (the mid-continent region) and those of the NYMEX. The average gasoline basis for the year ended December 31, 2007 increased by $2.04 per barrel to $3.56 per barrel compared to $1.52 per barrel in the comparable period of 2006. The average distillate basis for the year ended December 31, 2007 increased by $0.53 per barrel to $7.95 per barrel compared to $7.42 per barrel in the comparable period of 2006. The positive effect of the increased NYMEX 2-1-1 crack spreads and refined fuels basis over the comparable periods was partially offset by reductions in the crude oil differentials over the comparable periods. Decreased discounts for sour crude oils evidenced by the $0.20 per barrel, or 4%, decrease 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, negatively impacted refining margin for the year ended December 31, 2007 as compared to the year ended December 31, 2006.

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 (turnaround), labor and environmental compliance costs. Petroleum direct operating expenses exclusive of depreciation and amortization were $209.5 million for the year ended December 31, 2007 compared to direct operating expenses of $135.3 million for the year ended December 31, 2006. The increase of $74.2 million for the year ended December 31, 2007 compared to the year ended December 31, 2006 was the result of increases in expenses associated with repairs and maintenance related to the refinery turnaround ($67.3 million), taxes ($9.3 million), direct labor ($5.0 million), insurance ($2.4 million), production chemicals ($0.8 million) and outside services ($0.7 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with energy and utilities ($5.8 million), rent and lease ($2.4 million), environmental compliance ($1.4 million), operating materials ($0.8 million) and repairs and maintenance ($0.3 million). On a per barrel of crude throughput basis, direct operating expenses per barrel of crude throughput for the year ended December 31, 2007 increased to $7.52 per barrel as compared to $3.92 per barrel for the year ended December 31, 2006 principally due to refinery turnaround expenses and the related downtime associated with the turnaround and the flood and the corresponding impact on overall crude oil throughput and production volume.

Net Costs Associated with Flood. Petroleum net costs associated with the flood for the year ended December 31, 2007 approximated $36.7 million as compared to none for the year ended December 31, 2006. Total gross costs recorded for the year ended December 31, 2007 were approximately $138.0 million. Of these gross costs approximately $93.1 million were associated with repair and other matters as a result of the physical damage to the refinery and approximately ~~$44.9~~

119

$44.9 million were associated with the environmental remediation and property damage. Included in

~~118~~

the gross costs associated with the flood were certain costs that are excluded from the accounts receivable from insurers of $81.4 million at December 31, 2007, for which we believe collection is probable. The costs excluded from the accounts receivable from insurers were approximately $6.8 million recorded for depreciation for the temporarily idle facilities, $3.5 million of uninsured losses inside of the Company’s deductibles, $2.8 million of uninsured expenses and $23.5 million recorded with respect to environmental remediation and property damage. As of December 31, 2007, $20.0 million of insurance recoveries recorded in 2007 had been collected and are not reflected in the accounts receivable from insurers balance at December 31, 2007.

Depreciation and Amortization. Petroleum depreciation and amortization was $43.0 million for the year ended December 31, 2007 as compared $33.0 million for the year ended December 31, 2006, an increase of $10.0 million over the comparable periods. During the restoration period for the refinery due to the flood, $6.8 million of depreciation and amortization was reclassified into net costs associated with flood. Adjusting for this $6.8 million reclassification, the increase in petroleum depreciation and amortization for the year ended December 31, 2007 compared to the year ended December 31, 2006 would have been approximately $16.8 million. This adjusted increase in petroleum depreciation and amortization for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of the completion of the several large capital projects in late 2006 and during the year ended December 31, 2007.

Operating Income (Loss). Petroleum operating income was $144.9 million for the year ended December 31, 2007 as compared to operating income of $245.6 million for the year ended December 31, 2006. This decrease of $100.7 million from the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of the refinery turnaround which began in February 2007 and was completed in April 2007 and the refinery downtime resulting from the flood. The turnaround negatively impacted daily refinery crude throughput and refined fuels production. Substantially all of the refinery’s units damaged by the flood were back in operation by August 20, 2007. In addition, direct operating expenses increased substantially during the year ended December 31, 2007 related to refinery turnaround ($67.3 million), taxes ($9.3 million), direct labor ($5.0 million), insurance ($2.4 million), production chemicals ($0.8 million) and outside services ($0.7 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with energy and utilities ($5.8 million), rent and lease ($2.4 million), environmental compliance ($1.4 million), operating materials ($0.8 million) and repairs and maintenance ($0.3 million).

Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Petroleum Business).

Net Sales. Petroleum net sales were $2,880.4 million for the year ended December 31, 2006 compared to $903.8 million for the 174 days ended June 23, 2005 and $1,363.4 million for the 233 days ended December 31, 2005. The increase of $613.2 million from the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 resulted from significantly higher product prices ($384.1 million) and increased sales volumes ($229.1 million) over the comparable periods. Our average sales price per gallon for the year ended December 31, 2006 for gasoline of $1.88 and distillate of $1.99 increased by 17% and 16%, respectively, as compared to the year ended December 31, 2005. Overall sales volumes of refined fuels for the year ended December 31, 2006 increased 9% as compared to the year ended December 31, 2005. The increased sales volume primarily resulted from higher production levels of refined fuels during the year ended December 31, 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. Definitions of the

120

terms coker unit and crude unit are contained in the section of this prospectus entitled “Glossary of Selected Terms.”

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Refining margin per barrel of crude throughput increased from $10.50 for the year ended December 31, 2005 to $13.27 for the year ended December 31, 2006, due to increased discount for sour crude oils demonstrated by the $0.63, or 13%, 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, for the year ended December 31, 2006 as compared to the year ended December 31, 2005. In addition, positive regional differences between refined fuel prices in our primary marketing region (the mid-continent region) and those of the NYMEX, known as basis, significantly contributed to the increase in our consumed crack spread in the year ended December 31, 2006 as compared to the year ended December 31, 2005. The average distillate basis for the year ended December 31, 2006 increased by $4.22 per barrel to $7.42 per barrel compared to $3.20 per barrel in the comparable period of 2005. The average gasoline basis for the year ended December 31, 2006 increased by $2.05 per barrel to $1.52 per barrel in comparison to a negative basis of $0.53 per barrel in the comparable period of 2005.

Depreciation and Amortization. Petroleum depreciation and amortization was $33.0 million for the year ended December 31, 2006 as compared $0.8 million for the 174 days ended June 23, 2005 and $15.6 million for the 233 days ended December 31, 2005. The increase of $16.6 million for the year ended December 31, 2006 compared to the combined periods for the year ended December 31, 2005 was primarily the result of thestep-up in our property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability of Our Financial Results.”

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($7.7 million), major scheduled turnaround ($4.0 million), chemicals ($3.0 million), insurance $(1.3 million) and outside services ($1.4 million). On a per barrel of crude throughput basis, direct operating

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expenses per barrel of crude throughput for the year ended December 31, 2006 increased to $3.92 per barrel as compared to $3.27 per barrel for the year ended December 31, 2005.

Operating Income. Petroleum operating income was $245.6 million for the year ended December 31, 2006 as compared to $76.7 million for the 174 days ended June 23, 2005 and $123.0 million for the 233 days ended December 31, 2005 This increase of $45.9 million from the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 primarily resulted from higher refining margins due to improved crude differentials and strong gasoline and distillate basis during the comparable periods. The increase in operating income was somewhat offset by expenses associated with direct labor ($3.3 million), rent and lease ($2.3 million), environmental compliance ($1.9 million), operating materials ($1.2 million), repairs and maintenance ($7.7 million), major scheduled turnaround ($4.0 million), chemicals ($3.0 million), insurance ($1.3 million), outside services ($1.4 million) and depreciation and amortization ($16.6 million).

Nitrogen Fertilizer Business Results of Operations

The tables below provide an overview of the nitrogen fertilizer business’ results of operations, relevant market indicators and its key operating statistics during the past three years:

Immediate

Predecessor Successor
174 Days
233 Days
Year

Ended
Ended
Ended
Three Months

June 23, December 31, December 31, Ended March 31,
Nitrogen Fertilizer Business Financial Results

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)

Net sales $ 79.3 $ 93.7 $ 162.5 $ 165.9 $ 38.6 $ 62.6
Cost of product sold (exclusive of depreciation and amortization) 9.1 14.5 25.9 13.0 6.1 8.9
Direct operating expenses (exclusive of depreciation and amortization) 28.3 29.2 63.7 66.7 16.7 20.3
Net costs associated with flood — — — 2.4 — —
Depreciation and amortization 0.3 8.4 17.1 16.8 4.4 4.5
Operating income 35.3 35.7 36.8 46.6 9.3 26.0


	Immediate
	Predecessor		Successor
	174 Days		233 Days		Year
	Ended		Ended		Ended				Six Months
	June 23,		December 31,		December 31,				Ended June 30,
Nitrogen Fertilizer Business Financial Results	2005		2005		2006		2007		2007		2008
									(unaudited)
	(in millions)

Net sales	$	79.3	$	93.7	$	162.5	$	165.9	$	74.3	$	121.4
Cost of product sold (exclusive of depreciation and amortization)		9.1		14.5		25.9		13.0		6.2		15.8
Direct operating expenses (exclusive of depreciation and amortization)		28.3		29.2		63.7		66.7		33.2		39.9
Net costs associated with flood		—		—		—		2.4		0.1		—
Depreciation and amortization		0.3		8.4		17.1		16.8		8.8		9.0
Operating income		35.3		35.7		36.8		46.6		21.0		49.2

Year Ended December 31, Three Months Ended March 31,
Market Indicators

2005

2006

2007

2007

2008

Natural gas (dollars per MMBtu) $ 9.01 $ 6.98 $ 7.12 $ 7.17 $ 8.74
Ammonia — Southern Plains (dollars per ton) 356 353 409 389 590
UAN — Corn Belt (dollars per ton) 212 197 288 239 371


	Year Ended December 31,						Six Months Ended June 30,
Market Indicators	2005		2006		2007		2007		2008

Natural gas (dollars per MMBtu)	$	9.01	$	6.98	$	7.12	$	7.41	$	10.14
Ammonia — Southern Plains (dollars per ton)		356		353		409		395		634
UAN — Corn Belt (dollars per ton)		212		197		288		265		391

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Immediate

Predecessor

and Successor

Combined Successor
Year Ended
Year Ended
Year Ended
Three Months

December 31, December 31, December 31, Ended March 31,
Company Operating Statistics

2005

2006

2007

2007

2008

Production (thousand tons):
Ammonia 413.2 369.3 326.7 86.2 83.7
UAN 663.3 633.1 576.9 165.7 150.1

Total 1,076.5 1,002.4 903.6 251.9 233.8
Sales (thousand tons)(1):
Ammonia 141.8 117.3 92.1 20.7 24.1
UAN 646.5 645.5 555.4 166.8 158.0

Total 788.3 762.8 647.5 187.5 182.1
Product pricing (plant gate) (dollars per ton)(1):
Ammonia $ 324 $ 338 $ 376 $ 347 $ 494
UAN $ 173 $ 162 $ 211 $ 169 $ 262
On-stream factor(2):
Gasifier 98.1 % 92.5 % 90.0 % 91.8 % 91.8 %
Ammonia 96.7 % 89.3 % 87.7 % 86.3 % 90.7 %
UAN 94.3 % 88.9 % 78.7 % 89.4 % 85.9 %
Reconciliation to net sales (dollars in thousands):
Freight in revenue $ 15,010 $ 17,890 $ 13,826 $ 3,139 $ 4,022
Hydrogen revenue — 5,291
Sales net plant gate 157,989 144,575 152,030 35,436 53,287

Total net sales $ 172,999 $ 162,465 $ 165,856 $ 38,575 $ 62,600


	Immediate
	Predecessor
	and Successor
	Combined			Successor
	Year Ended			Year Ended			Year Ended			Six Months
	December 31,			December 31,			December 31,			Ended June 30,
Company Operating Statistics	2005			2006			2007			2007			2008
	(unaudited)

Production (thousand tons):
Ammonia		413.2			369.3			326.7			169.0			163.2
UAN		663.3			633.1			576.9			304.6			289.2

Total		1,076.5			1,002.4			903.6			473.6			452.4
Sales (thousand tons)(1):
Ammonia		141.8			117.3			92.1			34.1			43.3
UAN		646.5			645.5			555.4			293.5			296.6

Total		788.3			762.8			647.5			327.6			339.9
Product pricing (plant gate) (dollars per ton)(1):
Ammonia	$	324		$	338		$	376		$	354		$	509
UAN	$	173		$	162		$	211		$	190		$	281
On-stream factor(2):
Gasifier		98.1	%		92.5	%		90.0	%		90.6	%		87.3	%
Ammonia		96.7	%		89.3	%		87.7	%		86.8	%		85.4	%
UAN		94.3	%		88.9	%		78.7	%		81.9	%		82.1	%
Reconciliation to net sales (dollars in thousands):
Freight in revenue	$	15,010		$	17,890		$	13,826		$	6,430		$	8,072
Hydrogen revenue											—			7,891
Sales net plant gate		157,989			144,575			152,030			67,905			105,438

Total net sales	$	172,999		$	162,465		$	165,856			74,335			121,401


(1)		Plant gate sales per ton represents net sales less freight revenue divided by product sales volume in tons in the reporting period. Plant gate price per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry.

(2)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the fertilizer facility in the third quarter of 2006, the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN.

~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 compared to the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007 (Nitrogen Fertilizer Business).

Net Sales. Nitrogen fertilizer net sales were ~~$62.6~~$121.4 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 compared to ~~$38.6~~$74.3 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$24.0~~$47.1 million ~~for~~from the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was the result of an increase in higher plant gate prices ~~together~~($33.4 million), coupled with a change in intercompany accounting for hydrogen from cost of product sold (exclusive of depreciation and amortization) to net sales over the comparable periods, which eliminates in consolidation, partially offset by reductionsan increase in overall sales ~~volume.~~volumes ($13.7 million).

In regard to product sales volumes for the ~~three~~six months ended ~~March 31,~~June 30, 2008, our nitrogen ~~fertilizer~~ operations experienced an increase of ~~17%~~27% in ammonia sales unit volumes (9,175 tons) and ~~a decrease~~an increase of 5%1% in UAN sales unit ~~volumes.~~volumes (3,068 tons). On-stream factors (total number of hours operated divided by total hours in the reporting period) for the gasification ~~unit~~and ammonia units were ~~unchanged over~~less than the comparable ~~periods. On-stream factors for the ammonia unit were greater than the three months ended March 31, 2007.~~period, primarily due unscheduled downtime. On-stream factors for the UAN plant were ~~lower than~~slightly improved for the ~~three month period ended March 31, 2007. During the three~~six months ended ~~March 31,~~June 30, 2008 ~~all three primary nitrogen fertilizer units experienced approximately five days of downtime associated with repairs~~as compared to the ~~air separation unit.~~six months ended June 30, 2007. It is typical to

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experience brief outages in complex manufacturing operations

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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 ~~three~~six months to ~~three~~six months. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices for the ~~three~~six months ended ~~March 31,~~June 30, 2008 for ammonia ~~and UAN~~ were greater than plant gate prices for the comparable period of 2007 by ~~43% and 55%, respectively.~~44%. Similarly, UAN plant gate prices for the six months ending June 30, 2008 were greater than the comparable period of 2007 by 48%. This dramatic increase in nitrogen fertilizer prices was not the direct result of an increase in natural gas prices, but rather the result of increased demand for nitrogen-based fertilizers due to the ~~increased use~~historically low ending stocks of ~~corn for the production of ethanol~~global grains and ~~an overall increase~~a surge in prices for corn, wheat and soybeans, the primary row crops in our region. This increase in demand for nitrogen-based fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation to natural gas prices.

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.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold ~~exclusive~~(exclusive of depreciation and ~~amortization~~amortization) is primarily comprised of pet coke expense, ~~and~~ freight and distribution expenses. Cost of product sold ~~(excluding~~excluding depreciation and ~~amortization)~~amortization for the ~~three~~six months ended ~~March 31,~~June 30, 2008 was ~~$8.9~~$15.8 million compared to ~~$6.1~~$6.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$2.8~~$9.6 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of a change in intercompany accounting for hydrogen reimbursement. For the ~~three~~six months ended ~~March 31,~~June 30, 2007, hydrogen reimbursement was included in cost of product sold (exclusive of depreciation and amortization). For the ~~three~~six months ended ~~March 31,~~June 30, 2008, hydrogen has been included in net sales. These amounts eliminate in consolidation. Hydrogen is transferred from our nitrogen fertilizer operations to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit.

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for our ~~nitrogen~~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~~(exclusive of depreciation and ~~amortization~~amortization) for the ~~three~~six months ended ~~March 31,~~June 30, 2008 were ~~$20.3~~$39.9 million as compared to ~~$16.7~~$33.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The increase of ~~$3.6~~$6.7 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was primarily the result of increases in expenses associated with property taxes ($~~2.5~~4.9 million), repairs and maintenance ($~~1.7~~1.8 million), ~~labor~~catalysts ($1.2 million), outside services ($0.9 million), slag disposal ($0.3 million), ~~catalysts~~direct labor ($~~0.3~~0.2 million) and ~~outside services~~insurance ($~~0.2~~0.1 million). These increases in direct operating expenses were partially offset by ~~decreases~~reductions in expenses associated with ~~utilities ($0.6 million),~~ royalties and other ($~~0.4~~1.4 million), environmental compliance ($0.3 million) and equipment rental ($~~0.3~~0.2 million).

Net Costs Associated with Flood. Nitrogen fertilizer costs associated with the flood for the six months ended June 30, 2008 approximated $0 million as compared to $0.1 million for the six months ended June 30, 2007.

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Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased to ~~$4.5~~$9.0 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~$4.4~~$8.8 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. ~~Nitrogen fertilizer depreciation and amortization increased by approximately $0.1 million for the three months ended March 31, 2008 compared to the three months ended March 31, 2007.~~

Operating Income. Nitrogen fertilizer operating income was ~~$26.0~~$49.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as compared to ~~operating income of $9.3~~$21.0 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. This increase of ~~$16.7~~$28.2 million for the ~~three~~six months ended ~~March 31,~~June 30, 2008 as

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compared to the ~~three~~six months ended ~~March 31,~~June 30, 2007 was ~~primarily~~ the result of increased ~~fertilizer~~sales volumes ($13.7 million), coupled with higher plant gate prices ~~over the comparable periods. Additionally, decreased direct operating expenses associated with utilities~~for both UAN and ammonia ($~~0.6~~33.4 million)~~, royalties and other ($0.4 million) and equipment rental ($0.3 million) also contributed to~~. Partially offsetting the positive ~~operating income comparison over the comparable periods. These decreases in expenses were partially offset by reduced~~effects of sales volumes and higher plant gate prices were increased direct operating expenses primarily the result of increases in expenses associated with property taxes ($~~2.5~~4.9 million), repairs and maintenance ($~~1.7~~1.8 million), ~~labor~~catalysts ($1.2 million), outside services ($0.9 million), slag disposal ($0.3 million), ~~catalysts~~direct labor ($0.2 million) and insurance ($0.1 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with royalties and other ($1.4 million), environmental compliance ($0.3 million) and ~~outside services~~equipment rental ($0.2 million).

Year Ended December 31, 2007 compared to the Year Ended December 31, 2006 (Nitrogen Fertilizer Business).

Net Sales. Nitrogen fertilizer net sales were $165.9 million for the year ended December 31, 2007 compared to $162.5 million for the year ended December 31, 2006. The increase of $3.4 million from the year ended December 31, 2007 as compared to the year ended December 31, 2006 was the result of reductions in overall sales volumes ($31.0 million) which were more than offset by higher plant gate prices ($34.4 million).

In regard to product sales volumes for the year ended December 31, 2007, our nitrogen operations experienced a decrease of 22% in ammonia sales unit volumes (25,283 tons) and a decrease of 14% in UAN sales unit volumes (90,095 tons). The decrease in ammonia sales volume was the result of decreased production volumes during the year ended December 31, 2007 relative to the comparable period of 2006 due to unscheduled downtime at our fertilizer plant and the transfer of hydrogen to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit. The transfer of hydrogen to our petroleum operations will decrease, to some extent during 2008 because the new continuous catalytic reformer will produce hydrogen.

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 approximately eighteen days of downtime for all three primary nitrogen units associated with the flood, nine days of downtime related to compressor repairs in the ammonia unit and 24 days of downtime related to the UAN expander in the UAN unit. In addition, all three primary units also experienced brief and unscheduled downtime for repairs and maintenance during the year ended December 31, 2007. It is typical to experience brief outages in complex manufacturing operations such as our nitrogen fertilizer plant which result in less than one hundred percent on-stream availability for one or more specific units.

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prices for nitrogen fertilizer due to forward price contracts. As a result, forward price contracts entered into the late summer and fall of 2005 (during a period of relatively high natural gas prices due to the impact of hurricanes Rita and Katrina) comprised a significant portion of the product shipped in the spring of 2006. However, as natural gas prices moderated in the spring and summer of 2006, nitrogen fertilizer prices declined and the spot and fill contracts entered into and shipped during this lower natural gas prices environment realized lower average plant gate price. Ammonia and UAN sales prices for the year ended December 31, 2007 decoupled from natural gas prices and increased sharply driven by increased demand for fertilizer due to the increased use of corn for the production of ethanol and an overall increase in prices for corn, wheat and soybeans, which are the primary row

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crops in our region. This increase in demand for nitrogen fertilizer has created an environment in which nitrogen fertilizer prices have disconnected from their traditional correlation to natural gas.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold exclusive of depreciation and amortization is primarily comprised of petroleum coke expense, hydrogen reimbursement and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2007 was $13.0 million compared to $25.9 million for the year ended December 31, 2006. The decrease of $12.9 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of increased hydrogen reimbursement due to the transfer of hydrogen to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit and reduced freight expense partially offset by an increase in petroleum coke costs. In 2007, pet coke costs increased as the nitrogen fertilizer business purchased more pet coke from third parties than is typical as a result of the flood, which reduced our refinery’s pet coke production.

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 year ended December 31, 2007 were $66.7 million as compared to $63.7 million for the year ended December 31, 2006. The increase of $3.0 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of increases in repairs and maintenance ($6.5 million), equipment rental ($0.6 million) environmental ($0.4 million), utilities ($0.3 million), and insurance ($0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with turnaround ($2.6 million), royalties and other expense ($1.1 million), reimbursed expense ($0.6 million), catalyst ($0.3 million), chemicals ($0.3 million) and slag disposal ($0.2 million).

Net Costs Associated with Flood. Nitrogen fertilizer net costs associated with flood for the year ended December 31, 2007 approximated $2.4 million as compared to none for the year ended December 31, 2006. Total gross costs recorded as a result of the physical damage to the fertilizer plant for the year ended December 31, 2007 were approximately $5.7 million. Included in the gross costs associated with the flood were certain costs that are excluded from the accounts receivable from insurers of approximately $3.3 million at December 31, 2007, for which we believe collection is probable. The costs excluded from the accounts receivable from insurers were approximately $0.8 million recorded for depreciation for the temporarily idle facilities, $0.1 million of uninsured losses inside of the Company’s deductibles and $1.5 million of uninsured expenses.

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

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Operating Income. Nitrogen fertilizer operating income was $46.6 million for the year ended December 31, 2007 as compared to $36.8 million for the year ended December 31, 2006. This increase of $9.8 million for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was primarily the result of an increase in plant gate prices ($34.4 million), partially offset by reductions in overall sales volumes ($31.0 million). In addition, a $12.9 million reduction in cost of product sold excluding depreciation and amortization due to increased hydrogen reimbursement and reduced freight expense partially offset by an increase in petroleum coke costs contributed to the positive variance in operating income during for the year ended December 31, 2007 compared to the year ended December 31, 2006. Partially offsetting the positive effects of plant gate prices and cost of product sold excluding depreciation and amortization was an increase in direct operating

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expenses associated with repairs and maintenance ($6.5 million), equipment rental ($0.6 million) environmental ($0.4 million), utilities ($0.3 million), and insurance ($0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with turnaround ($2.6 million), royalties and other expense ($1.1 million), reimbursed expense ($0.6 million), catalyst ($0.3 million), chemicals ($0.3 million) and slag disposal ($0.2 million).

Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Nitrogen Fertilizer Business).

Net Sales. Nitrogen fertilizer net sales were $162.5 million for the year ended December 31, 2006 compared to $79.3 million for the 174 days ended June 23, 2005 and $93.7 million for the 233 days ended December 31, 2005. The decrease of $10.5 million from the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was the result of both decreases in selling prices ($1.6 million) and reductions in overall sales volumes ($8.9 million) of the fertilizer products as compared to the year ended December 31, 2005.

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

In regard to product sales volumes for the year ended December 31, 2006, the nitrogen fertilizer operations experienced a decrease of 17% in ammonia sales unit volumes (24,500 tons) and a decrease of 0.2% in UAN sales unit volumes (988 tons). The decrease in ammonia sales volume was the result of decreased production volumes during the year ended December 31, 2006 relative to the comparable period of 2005 due to the scheduled turnaround at the nitrogen fertilizer plant during July 2006 and the transfer of hydrogen to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit.

On-stream factors (total number of hours operated divided by total hours in the reporting period) for all units of the nitrogen fertilizer operations (gasifier, ammonia plant and UAN plant) were less in 2006 than in 2005 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 the nitrogen fertilizer plant which result in less than 100% on-stream availability for one or more specific units.

Plant gate prices are prices FOB the delivery point less any freight cost absorbed to deliver the product. We believe plant gate price is meaningful because the nitrogen fertilizer business sells products both FOB the 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 year ended December 31, 2006 for ammonia were greater than plant gate prices for the comparable period of 2005 by 4%. In contrast to ammonia, UAN prices decreased for

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the year ended December 31, 2006 as compared to the year ended December 31, 2005 by 6%. The positive price comparisons for ammonia sales, given the dramatic decline in natural gas prices during the comparable periods, were the result of prepay contracts executed during the period of relatively high natural gas prices that resulted from the impact of hurricanes Katrina and Rita on an already tight natural gas market.

Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold 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, 2006 was $25.9 million compared to $9.1 million for the 174 days ended June 23, 2005 and $14.5 million for the 233 days ended December 31, 2005. The increase of $2.3 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of increases in freight expense.

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Depreciation and Amortization. Nitrogen fertilizer depreciation and amortization increased to $17.1 million for the year ended December 31, 2006 as compared to $0.3 million for the 174 days ended June 23, 2005 and $8.4 million for the 233 days ended December 31, 2005. This increase of $8.4 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of thestep-up in property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting ~~Comparability.~~Comparability of Our Financial Results.”

Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for the nitrogen fertilizer operations include costs associated with the actual operations of the nitrogen fertilizer 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 year ended December 31, 2006 were $63.7 million as compared to $28.3 million for the 174 days ended June 23, 2005 and $29.2 million for the 233 days ended December 31, 2005. The increase of $6.2 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of increases in labor ($0.7 million), repairs and maintenance ($0.5 million), turnaround expenses ($2.6 million), outside services ($0.6 million), utilities ($2.3 million) and insurance ($0.5 million), partially offset by reductions in expenses related to catalyst ($0.6 million) and environmental ($0.8 million).

Operating Income. Nitrogen fertilizer operating income was $36.8 million for the year ended December 31, 2006 as compared to $35.3 million for the 174 days ended June 23, 2005 and $35.7 million for the 233 days ended December 31, 2005. This decrease of $34.2 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was the result of reduced sales volumes, lower plant gate prices for UAN and increased direct operating expenses related to labor ($0.7 million), repairs and maintenance ($0.5 million), turnaround expenses ($2.6 million), outside services ($0.6 million), utilities ($2.3 million), insurance ($0.5 million) and depreciation ($8.4 million), partially offset by reductions in expenses related to catalyst ($0.6 million) and environmental ($0.8 million) and higher ammonia prices.

Liquidity and Capital Resources

Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap as well as our convertible notes offering, if consummated. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses.

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As of ~~March 31,~~June 30, 2008, total outstanding debt under our credit facility was $508.3 million, which includes $21.5 million from our revolving credit facility. As of August 14, 2008, total outstanding debt under our credit facility was $485.5 million, which was all term debt. As of June 30, 2008, we had cash, cash equivalents and short-term investments of ~~$25.2~~$20.6 million and up to $91.1 million available under our revolving credit facility. As of August 14, 2008, we had cash, cash equivalents and short-term investments of $88.4 million and up to $112.6 million available under our revolving credit facility. ~~As of July 15, 2008, we had cash, cash equivalents and short-term investments of $19.1 million, and up to $109.4 million available under our revolving credit facility as of both dates.~~ In the current crude oil price environment, working capital is subject to substantial variability fromweek-to-week andmonth-to-month. The payable to swap counterparty included in the consolidated balance sheet at ~~March 31,~~June 30, 2008 was approximately ~~$371.4~~$418.3 million, and the current portion included an increase of ~~$32.6~~$109.2 million from December 31, 2007, resulting in an equal reduction in our working capital for the same period.

On June 30, 2007, our refinery and the nitrogen fertilizer plant were severely flooded and forced to conduct emergency shutdowns and evacuate. See “Flood and Crude Oil Discharge.” Our liquidity was significantly negatively impacted as a result of the reduction in cash provided by operations due to our temporary cessation of operations and the additional expenditures associated with the flood and crude oil discharge. In order to provide immediate and future liquidity, on August 23, 2007 we deferred payments of $123.7 million which were due to J. Aron under the terms of the Cash Flow Swap. ~~The~~We entered into a letter agreement with J. Aron

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~~deferred amounts~~ on July 29, 2008 to defer until December 15, 2008 the payment of $87.5 million of the $123.7 million ~~(plus~~plus accrued interest ~~of $6.2~~($6.7 million as of ~~July~~August 1, 2008) ~~are~~we owe to J. Aron. The remaining $36.2 million plus accrued interest will be due on August 31, ~~2008. We are in~~2008 (or earlier at our option). If we consummate this notes offering before December 15, 2008, the ~~process of negotiating a deferral of~~ $87.5 million ~~of these amounts owed~~deferral will automatically extend to ~~J. Aron until~~ July 31, 2009. ~~We cannot assure you that the new deferral agreement will be consummated.~~ See “— Liquidity and Capital Resources — Debt — Payment Deferrals Related to ~~the~~ Cash Flow Swap” for additional information about the payment deferral. These deferrals are supported by third-party guarantees. We paid J. Aron $52.4 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2008.

~~Our liquidity was enhanced during the fourth quarter of 2007 by the receipt of the net proceeds from our initial public offering.~~ We intend to use the net proceeds from the convertible notes offering, if consummated, for general corporate purposes, which may include ~~using a portion of the proceeds to pay amounts owed to J. Aron under the Cash Flow Swap and for other~~ future capital investments. If the convertible notes offering is not consummated, we intend to fund our operations through cash ~~generated~~flows from operations, borrowings under our ~~operating activities, existing cash balances, our existing~~ revolving credit facility and third party guarantees ~~of obligations~~ under the Cash Flow Swap. We believe these capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.

Debt

Credit Facility

On December 28, 2006, our subsidiary, Coffeyville Resources, LLC, entered into a credit facility (the “Credit Facility”) which provided financing of up to $1.075 billion. The Credit Facility consisted of $775.0 million of tranche D term loans, a $150.0 million revolving credit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. On October 26, 2007, we repaid $280.0 million of the tranche D term loans with proceeds from our initial public offering. The Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including the equity of our subsidiaries on a first-lien priority basis.

The tranche D term loans outstanding are subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on April 1, 2007 and increasing to 23.5% of the outstanding principal balance on April 1, 2013 and the next two quarters, with a final payment of the aggregate outstanding balance on December 28, 2013.

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The revolving credit facility of $150.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving credit facility are subject to a $75.0 million sub-limit. The revolving loan commitment expires on December 28, 2012. 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 December 28, 2013. As of ~~March 31,~~June 30, 2008, we had available ~~$112.6~~$91.1 million under the revolving credit facility. As of ~~July 15,~~August 14, 2008, we had available ~~$109.4~~$112.6 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. The funded letter of credit facility expires on December 28, 2010.

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The Credit Facility incorporates the following pricing by facility type:


	•	Tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions).

	•	Revolving loan borrowings bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions).

	•	Letters of credit issued under the $75.0 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% per annum 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% per annum 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 Credit Facility requires the borrower to pay 0.50% per annum in commitment fees on the unused portion of the revolving loan facility.

The Credit Facility requires 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 with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is

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		less than 1.50:1.00 or 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00.

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, and fifth to cash collateralize revolving letters of credit and funded letters of credit. Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.

The Credit Facility contains 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 stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The Credit Facility provides that

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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 December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap or the Partnership’s partnership 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 notes or common stock.

The Credit Facility also requires the borrower to maintain certain financial ratios as follows:


	Minimum
	Interest	Maximum
	Coverage	Leverage
Fiscal Quarter Ending	Ratio	Ratio

June 30, 2008	3.25:1.00	3.00:1.00
September 30, 2008	3.25:1.00	2.75:1.00
December 31, 2008	3.25:1.00	2.50:1.00
March 31, 2009 and thereafter	3.75:1.00	2.25:1.00 to December 31, 2009, 2.00:1.00 thereafter

The computation of these ratios is governed by the specific terms of the Credit Facility 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 Facility, 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 permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, 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. As of the date of this prospectus, we were in compliance with our covenants under the Credit Facility.

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We present consolidated adjusted EBITDA because it is a material component of material covenants within our current Credit Facility and significantly impacts our liquidity and ability to borrow under our revolving line of credit. 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 Credit Facility as follows:

Immediate

Predecessor

and Successor

Combined

(Non-GAAP) Successor
Year Ended December 31, Three Months Ended March 31,
Consolidated Financial Results

2005

2006

2007

2007

2008

(unaudited) (in millions) (unaudited in millions)
Net income (loss) $ (66.8 ) $ 191.6 $ (67.6 ) $ (154.4 ) $ 22.2
Plus:
Depreciation and amortization 25.1 51.0 68.4 14.2 19.6
Interest expense 32.8 43.9 61.1 11.9 11.3
Income tax expense (benefit) (26.9 ) 119.8 (88.5 ) (47.3 ) 6.9
Loss on extinguishment of debt 8.1 23.4 1.3 — —
Inventory fair market value adjustment 16.6 — — — —
Funded letters of credit expenses and interest rate swap not included in interest expense 2.3 — 1.8 — 0.9
Major scheduled turnaround expense — 6.6 76.4 66.0 —
Loss on termination of Swap 25.0 — — — —
Unrealized (gain) or loss on derivatives 229.8 (128.5 ) 113.5 126.9 18.9
Non-cash compensation expense for equity awards 1.8 16.9 43.5 3.7 (0.4 )
(Gain) or loss on disposition of fixed assets — 1.2 1.3 — —
Expenses related to acquisition 3.5 — — — —
Minority interest in subsidiaries — — (0.2 ) (0.7 ) —
Management fees 2.3 2.3 11.7 0.5 —

Consolidated adjusted EBITDA $ 253.6 $ 328.2 $ 222.7 $ 20.8 $ 79.4


	Immediate
	Predecessor
	and Successor
	Combined
	(Non-GAAP)			Successor
	Year Ended December 31,									Six Months Ended June 30,
Consolidated Financial Results	2005			2006			2007			2007			2008
	(unaudited in millions)
Net income (loss)	$	(66.8	)	$	191.6		$	(67.6	)	$	(54.3	)	$	53.2
Plus:
Depreciation and amortization		25.1			51.0			68.4			32.2			40.7
Interest expense		32.8			43.9			61.1			27.6			20.8
Income tax expense (benefit)		(26.9	)		119.8			(88.5	)		(141.0	)		10.9
Loss on extinguishment of debt		8.1			23.4			1.3			—			—
Inventory fair market value adjustment		16.6			—			—			—			—
Funded letters of credit expenses and interest rate swap not included in interest expense		2.3			—			1.8			0.2			3.3
Major scheduled turnaround expense		—			6.6			76.4			76.8			—
Loss on termination of Swap		25.0			—			—			—			—
Unrealized (gain) or loss on derivatives		229.8			(128.5	)		113.5			190.0			31.8
Non-cash compensation expense for equity awards		1.8			16.9			43.5			6.8			(11.2	)
(Gain) or loss on disposition of fixed assets		—			1.2			1.3			1.2			1.6
Expenses related to acquisition		3.5			—			—			—			—
Minority interest in subsidiaries		—			—			(0.2	)		(0.3	)		—
Management fees		2.3			2.3			11.7			1.1			—

Consolidated adjusted EBITDA	$	253.6		$	328.2		$	222.7		$	140.3		$	151.1

In addition to the financial covenants summarized in the table above, the Credit Facility restricts the capital expenditures of Coffeyville Resources, LLC to $125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and $50.0 million in 2011 and thereafter. The capital expenditures covenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe the limitations on our capital expenditures imposed by the Credit Facility should 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

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beyond those currently planned, we would need to obtain consent from the lenders under our Credit Facility.

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The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20.0 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20.0 million 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 $20.0 million, events relating to employee benefit plans resulting in liability in excess of $20.0 million, a change in control, the guarantees, collateral documents or the Credit Facility 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 Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.

Under the terms of our Credit Facility, our initial public offering was deemed a “Qualified IPO” because the offering generated more than $250.0 million of gross proceeds and we used the proceeds of the offering to repay at least $275.0 million of term loans under the Credit Facility. As a result of our Qualified IPO, the interest margin on LIBOR loans may in the future decrease from 3.25% to 2.75% (if we have credit ratings of B2/B) or 2.50% (if we have credit ratings of B1/B+). Interest on base rate loans will similarly be adjusted. In addition, as a result of our Qualified IPO, (1) we will be allowed to borrow an additional $225.0 million under the Credit Facility after June 30, 2008 to finance capital enhancement projects if we are in pro forma compliance with the financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we will be allowed to pay an additional $35.0 million of dividends each year, if our corporate family ratings are at least B2 from Moody’s and B from S&P, (3) we will not be subject to any capital expenditures limitations commencing with fiscal 2009 if our total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter ending December 31, 2008, and (4) at any time after March 31, 2008 we will be allowed to reduce the Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or equal to 1.25:1 and we have a corporate family rating of at least B2 from Moody’s and B from S&P.

The Credit Facility is subject to an intercreditor agreement among the lenders and the Cash Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.

At ~~March 31,~~June 30, 2008 and December 31, 2007, funded long-term debt, including current maturities, totaled ~~$488.0~~$486.8 million and $489.2 million, respectively, of tranche D term loans. Other commitments at ~~March 31,~~June 30, 2008 and December 31, 2007 included a $150.0 million funded letter of credit facility and a $150.0 million revolving credit facility. As of ~~March 31,~~June 30, 2008 the commitment outstanding on the revolving credit facility was ~~$37.4~~$58.9 million, including $21.5 million in revolver borrowings, $5.8 million in letters of credit in support of certain environmental obligations and $31.6 million in letters of credit to secure transportation services for crude oil. As of December 31, 2007, the commitment outstanding on the revolving credit facility was $39.4 million, including $5.8 million in letters of credit in support of certain environmental obligations, $3.0 million in support of surety bonds in place to support state and federal excise tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for crude oil.

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August 2007 Credit Facilities

The 2007 flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. We did not generate any material revenue while our facilities were shut down due to the flood, but we incurred and continue to incur significant flood repair and cleanup costs, as well as

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incremental legal, public relations and crisis management costs. We also had significant contractual obligations to purchase gathered crude oil. We also owed J. Aron approximately $123.7 million under the Cash Flow Swap, which we deferred to January 31, 2008 (see “— Payment Deferrals Related to Cash Flow Swap” below). In addition, although we believe that we will recover substantial sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery.

As a result of these factors, in August 2007 our subsidiaries entered into three new credit facilities.


	•	*$25.0 Million Secured Facility.* Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%.

	•	*$25.0 Million Unsecured Facility.* Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%.

	•	*$75.0 Million Unsecured Facility.* Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility.

All indebtedness outstanding under the $25.0 million secured facility and the $25.0 million unsecured facility was repaid in October 2007 with the proceeds of our initial public offering, and all three facilities were terminated at that time.

Payment Deferrals Related to Cash Flow Swap

As a result of the flood and the temporary cessation of our operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 and then to August 31, 2008 the payment of approximately $123.7 million ~~(plus~~plus accrued interest ~~of $6.2~~($6.7 million as of ~~July~~August 1, 2008) which we owed to J. Aron. We entered into a letter agreement with J. Aron ~~has agreed~~on July 29, 2008 to ~~further~~ defer ~~these payments~~until December 15, 2008 the payment of $87.5 million of the $123.7 million plus accrued interest we owe to J. Aron. Interest will accrue on the deferred amounts from August 31, ~~2008. We~~2008 to the date of payment at a rate of LIBOR plus 2.75%, and we are required to prepay the deferral amount each quarter with the greater of 50% of the Company’s free cash flow or $5.0 million. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at our option). If we consummate this notes offering before December 15, 2008, the deferral will automatically extend to July 31, 2009. Under the terms of the deferral of $87.5 million of the amounts owed to J. Aron, we are required to use ~~37.5%~~the substantial majority of ~~our consolidated~~any gross proceeds from any indebtedness we incur during the deferral period in excess ~~cash flow for any quarter after January 31, 2008~~of $125.0 million, including all of the gross proceeds received from the sale of notes issued in connection with the exercise by the underwriters of the over-allotment option net of fees, to prepay ~~the deferred amounts, but as of March 31, 2008 we were not required to prepay any~~a portion of the deferred ~~amount.~~amounts owed to J. Aron.


	•	On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we

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		owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%.


	•	On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

	•	On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued

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		interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.


	•	On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million, plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%.


	•	On July 29, 2008, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to December 15, 2008 the payment of $87.5 million of the $123.7 million (plus accrued interest) we owe to J. Aron under the Cash Flow Swap and had previously deferred to August 31, 2008. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at the company’s option). If we consummate this notes offering before December 15, 2008, the deferral will automatically extend to July 31, 2009. J. Aron deferred this $87.5 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. reaffirmed their guarantees of one half of the payments and (b) interest accrued on the deferred amounts from August 31, 2008 to the date of payment at the rate of LIBOR plus 2.75%.

We are in the process of negotiating a deferral of $87.5 million of these amounts owed to J. Aron until July 31, 2009. Interest will accrue on the amounts to the date of payment at the rate of LIBOR plus 2.75%. It is expected that the new deferral agreement will require the deferral amount to be prepaid each quarter with the greater of 50% of cash flow or $5 million. Any failure to make these quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts. Under the terms of the proposed deferral of $87.5 million of the amounts owed to J. Aron, we will be required to use the substantial majority of any gross proceeds from any indebtedness we incur in excess of $125.0 million, including the proceeds of this offering, to prepay a portion of the deferred amounts. We cannot assure you that the new deferral agreement will be consummated.

Nitrogen Fertilizer Limited Partnership

The managing general partner of the Partnership may, from time to time, seek to raise capital through a public or private offering of limited partner interests in the Partnership. Any decision to pursue such a transaction would be made in the discretion of the managing general partner, not us, and any proceeds raised in a primary offering would be for the benefit of the Partnership, not us (although in some cases, depending on the structure of the transaction, the Partnership might remit proceeds to us). If the managing general partner elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Any such amendments could result in significant changes to our Credit Facility’s pricing, mandatory repayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing

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general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice.

However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend our Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140.0 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and to distribute that cash to us prior to, or concurrently

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with, the closing of its initial public or private offering. If the managing general partner sells interests to third party investors, we expect that the Partnership may at such time seek to enter into its own credit facility.

The Partnership filed a registration statement in February 2008 for an initial public offering of its common units. On June 13, 2008, we announced that the managing general partner of the Partnership has decided to postpone indefinitely the Partnership’s initial public offering due to current market conditions for master limited partnerships. We believe maintaining the fertilizer business within the Company provides greater value for CVR Energy shareholders than would be the case if the Partnership became a publicly-traded partnership at this time. The Partnership subsequently requested that the registration statement be withdrawn. The Partnership may elect to move forward with a public or private offering in the future. Any future public or private offering by the Partnership would be made solely at the discretion of the Partnership’s managing general partner, subject to our specified joint management rights, and would be subject to market conditions and negotiation of terms acceptable to the Partnership’s managing general partner. In connection with the Partnership’s initial public or private offering, if any, the Partnership may require us to include a sale of a portion of our interests in the Partnership. If the Partnership becomes a public company, we may consider a secondary offering of interests which we own (either in connection with a public offering by the Partnership, but subject to priority rights in favor of the Partnership, or following completion of the Partnership’s initial public offering, if any) or in a private placement. We cannot assure you that any such transaction will be consummated. Neither the consent of the managing general partner nor the consent of the Partnership is required for any sale of our interests in the Partnership, other than customary blackout periods relating to offerings by the Partnership. Any proceeds raised would be for our benefit. The Partnership has granted us registration rights which will require the Partnership to register our interests with the SEC at our request from time to time (following any public offering by the Partnership), subject to various limitations and requirements. We cannot assure you that any such transaction will be consummated.

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. The total non-discretionary capital spending needs for our refinery business and the nitrogen fertilizer business, including major scheduled turnaround expenses, were approximately $170 million in 2006 and $218 million in 2007 and we estimate that the total non-discretionary capital spending needs of our refinery business and the nitrogen fertilizer business will be approximately $279 million in the aggregate over the three-year period beginning 2008. These estimates include, among other items, the capital costs necessary to comply

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with environmental regulations, including Tier II gasoline standards and on-road diesel regulations. As described above, our credit facility limits the amount we can spend on capital expenditures.

Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately ~~$68~~$70 million in the aggregate between 2008 and 2010. These amounts are reflected in the table below under “Environmental and safety capital needs.” See “Business — Environmental Matters — Fuel Regulations — Tier II, Low Sulfur Fuels.”

The following table sets forth our estimate of non-discretionary spending for our refinery business and the nitrogen fertilizer business for the years presented as of ~~March 31,~~June 30, 2008 (other than 2006 and 2007 which reflect actual spending). Capital spending for the nitrogen fertilizer business has been and will be determined by the managing general partner of the Partnership. The data contained in the table below represents our current plans, but these plans may change as a result of unforeseen

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circumstances and we may revise these estimates from time to time or not spend the amounts in the manner allocated below.

Petroleum Business

2006

2007

2008

2009

2010

2011

2012

Cumulative

(in millions)

Environmental and safety capital needs $ 144.6 $ 121.8 $ 46.0 $ 53.9 $ 23.5 $ 2.6 $ 2.1 $ 394.5
Sustaining capital needs 11.8 14.9 22.0 29.8 22.3 22.0 22.0 144.8

156.4 136.7 68.0 83.7 45.8 24.6 24.1 539.3
Major scheduled turnaround expenses 4.0 76.4 — — 50.0 — — 130.4

Total estimated non-discretionary spending $ 160.4 $ 213.1 $ 68.0 $ 83.7 $ 95.8 $ 24.6 $ 24.1 $ 669.7


	2006		2007		2008		2009		2010		2011		2012		Cumulative
	(in millions)

Environmental and safety capital needs	$	144.6	$	121.8	$	44.5	$	56.1	$	23.5	$	2.6	$	2.1	$	395.2
Sustaining capital needs		11.8		14.9		17.4		31.7		24.6		22.0		22.0		144.4

		156.4		136.7		61.9		87.8		48.1		24.6		24.1		539.6
Major scheduled turnaround expenses		4.0		76.4		—		—		50.0		—		—		130.4

Total estimated non-discretionary spending	$	160.4	$	213.1	$	61.9	$	87.8	$	98.1	$	24.6	$	24.1	$	670.0

Nitrogen Fertilizer Business

2006

2007

2008

2009

2010

2011

2012

Cumulative

(in millions)

Environmental and safety capital needs $ 0.1 $ 0.5 $ 2.2 $ 4.5 $ 2.6 2.7 3.8 $ 16.4
Sustaining capital needs 6.6 3.9 9.7 3.1 4.5 4.8 4.3 36.9

6.7 4.4 11.9 7.6 7.1 7.5 8.1 53.3
Major scheduled turnaround expenses 2.6 — 2.8 — 2.6 — 2.8 10.8

Total estimated non-discretionary spending $ 9.3 $ 4.4 $ 14.7 $ 7.6 $ 9.7 $ 7.5 $ 10.9 $ 64.1


	2006		2007		2008		2009		2010		2011		2012		Cumulative
	(in millions)

Environmental and safety capital needs	$	0.1	$	0.5	$	1.8	$	5.3	$	2.6		2.7		3.8	$	16.8
Sustaining capital needs		6.6		3.9		6.0		5.4		4.5		4.8		4.3		35.5

		6.7		4.4		7.8		10.7		7.1		7.5		8.1		52.3
Major scheduled turnaround expenses		2.6		—		2.8		—		2.6		—		2.8		10.8

Total estimated non-discretionary spending	$	9.3	$	4.4	$	10.6	$	10.7	$	9.7	$	7.5	$	10.9	$	63.1

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Combined

2006

2007

2008

2009

2010

2011

2012

Cumulative

(in millions)

Environmental and safety capital needs $ 144.7 $ 122.3 $ 48.2 $ 58.4 $ 26.1 5.3 5.9 $ 410.9
Sustaining capital needs 18.4 18.8 31.7 32.9 26.8 26.8 26.3 181.7

163.1 141.1 79.9 91.3 52.9 32.1 32.2 592.6
Major scheduled turnaround expenses 6.6 76.4 2.8 — 52.6 — 2.8 141.2

Total estimated non-discretionary spending $ 169.7 $ 217.5 $ 82.7 $ 91.3 $ 105.5 $ 32.1 $ 35.0 $ 733.8


	2006		2007		2008		2009		2010		2011		2012		Cumulative
							(in millions)

Environmental and safety capital needs	$	144.7	$	122.3	$	46.3	$	61.4	$	26.1		5.3		5.9	$	412.0
Sustaining capital needs		18.4		18.8		23.4		37.1		29.1		26.8		26.3		179.9

		163.1		141.1		69.7		98.5		55.2		32.1		32.2		591.9
Major scheduled turnaround expenses		6.6		76.4		2.8		—		52.6		—		2.8		141.2

Total estimated non-discretionary spending	$	169.7	$	217.5	$	72.5	$	98.5	$	107.8	$	32.1	$	35.0	$	733.1

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 December 31, 2007, we had committed approximately $14 million towards discretionary capital spending in 2008. Other than the nitrogen fertilizer plant expansion project referred to below, we anticipate that our discretionary capital spending will average approximately ~~$35~~$30 million per year between 2008 and 2012.

In 2007, as a result of the flood, our refinery exceeded the required average annual gasoline sulfur standard as mandated by our approved hardship waiver with the EPA. In anticipation of a settlement with the EPA to resolve the non-compliance, the Company planned to spend $28.0 million in capital required for interim compliance with the ultra low sulfur gasoline standards in 2008, ahead of the required full compliance date of January 1, 2011. The Company anticipates final resolution with the EPA during 2008. Accordingly, $10.1 million of planned capital spending has been deferred to 2009.

The Partnership is currently moving forward with an approximately $120 million fertilizer plant expansion, of which approximately ~~$11~~$14.5 million was incurred as of ~~March 31,~~June 30, 2008. We estimate this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010. This project is also expected to improve the cost structure of the nitrogen fertilizer business by eliminating the need for rail shipments of ammonia, thereby avoiding anticipated cost increases in such transport.

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Cash Flows

The following table sets forth our cash flows for the periods indicated below:

Immediate

Predecessor Successor
174 Days
233 Days
Year

Ended
Ended
Ended
Three Months

June 23, December 31, December 31, Ended March 31,

2005

2005

2006

2007

2007

2008

(unaudited) (unaudited)
(in millions)

Net cash provided by (used in)
Operating activities $ 12.7 $ 82.5 $ 186.6 $ 145.9 $ 44.1 $ 24.2
Investing activities (12.3 ) (730.3 ) (240.2 ) (268.6 ) (107.3 ) (26.2 )
Financing activities (52.4 ) 712.5 30.8 111.3 28.9 (3.4 )

Net increase (decrease) in cash and cash equivalents $ (52.0 ) $ 64.7 $ (22.8 ) $ (11.4 ) $ (34.3 ) $ (5.4 )


	Immediate
	Predecessor			Successor
	174 Days			233 Days			Year
	Ended			Ended			Ended						Six Months
	June 23,			December 31,			December 31,						Ended June 30,
	2005			2005			2006			2007			2007			2008
													(unaudited)
	(in millions)

Net cash provided by (used in)
Operating activities	$	12.7		$	82.5		$	186.6		$	145.9		$	160.7		$	23.3
Investing activities		(12.3	)		(730.3	)		(240.2	)		(268.6	)		(214.1	)		(49.6	)
Financing activities		(52.4	)		712.5			30.8			111.3			34.5			16.4

Net increase (decrease) in cash and cash equivalents	$	(52.0	)	$	64.7		$	(22.8	)	$	(11.4	)	$	(18.9	)	$	(9.9	)

In addition, we are currently entitled to all cash distributed by the Partnership. However, the amount of cash flows from the Partnership that we will receive in the future may be limited by a number of factors. The Partnership may enter into its own credit facility or other contracts that limit its ability to make distributions to us. Additionally, in the future the managing general partner of the Partnership will receive a greater allocation of distributions as more cash becomes available for distribution, and consequently we will receive a smaller percentage of quarterly distributions over time. Our rights to distributions will also be adversely affected if the Partnership consummates a public or private equity offering in the future. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the establishment of cash reserves.”

Cash Flows Provided by Operating Activities

Comparison of the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 and the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007

Net cash flows provided by operating activities for the six months ended June 30, 2008 was $23.3 million compared to cash flows from operating activities for the ~~three~~six months ended ~~March 31, 2008 was $24.2~~June 30, 2007 of $160.7 million. The positive cash flow from operating activities generated over ~~this period~~the six months ended June 30, 2008 was primarily driven by net income, favorable changes in other working capital, ~~and other assets and liabilities,~~ partially offset by unfavorable changes in ~~trading~~trade working capital and other assets and liabilities 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. 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 ~~loss~~income for the ~~three~~six months ended ~~March 31,~~June 30, 2008 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of ~~March 31,~~June 30, 2008 (approximately two ~~years and three months) and the NYMEX crack spread that is the basis for the underlying swaps had increased,~~years), the unrealized losses on the Cash

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Flow Swap significantly decreased our net income over this period. The impact of ~~these~~the realized and unrealized losses on the Cash Flow Swap is apparent in the ~~$20.8~~

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$67.7 million increase in the payable to swap counterparty. ~~Other sources of cash in other working capital included $16.6 million of deferred revenue related to prepaid fertilizer shipments and a $5.2 million increase in accrued income taxes.~~ Trade working capital for the ~~three~~six months ended ~~March 31,~~June 30, 2008 resulted in a use of cash of ~~$67.5~~$131.0 million. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, accounts receivable increased ~~$30.7~~$54.5 million, inventory increased by ~~$31.6~~$71.8 million and accounts payable decreased by ~~$5.2~~$4.7 million.

Net cash flows provided by operating activities for the ~~three~~six months ended ~~March 31,~~June 30, 2007 was ~~$44.1~~$160.7 million. The positive cash flow from operating activities during this period was primarily the result of favorable changes in other working capital and trade working capital, partially offset by unfavorable changes in other assets and ~~liabilities offset by unfavorable changes in trade working capital and other working capital.~~liabilities. Net ~~income~~loss for the period was not indicative of the operating margins for the period. This was the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. 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 loss for the ~~three~~six months ended ~~March 31,~~June 30, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of ~~March 31,~~June 30, 2007 (approximately three ~~years~~years), the realized and ~~three months years) and the NYMEX crack spread that is the basis for the underlying swaps had increased during the period, the~~ unrealized losses on the Cash Flow Swap significantly ~~decreased~~increased our net ~~income~~loss over this period. The impact of these realized and unrealized losses on the Cash Flow Swap is apparent in the ~~$129.3~~$276.6 million increase in the payable to swap counterparty. Adding to our operating cash flow for the ~~three~~six months ended ~~March 31,~~June 30, 2007 was a ~~$68.0~~$3.9 million source of cash related to a decrease in trade working capital. For the ~~three~~six months ended ~~March 31,~~June 30, 2007, accounts receivable ~~decreased $44.6~~increased $6.4 million, ~~while~~ inventory increased ~~$23.0~~$17.8 million and accounts payable increased ~~$46.4~~$28.1 million. The change in trade working capital was primarily driven by the impact of the refinery turnaround that began in February 2007. The primary use of cash during the period was $41.3 million for deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.

Comparison of the Year Ended December 31, 2007, the Year Ended December 31, 2006, the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.

Net cash flows ~~from~~provided by operating activities for the year ended December 31, 2007 was $145.9 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital partially offset by unfavorable changes in trade working capital and other assets and liabilities 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. 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 loss for the year ended December 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2007 (approximately two years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap significantly decreased our Net Income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $240.9 million increase in the payable to swap counterparty. Other sources of cash from other working capital included $4.8 million from prepaid expenses and other current assets, $27.0 million from other current liabilities and $20.0 million in insurance proceeds. Reducing our operating cash flow for the year ended December 31, 2007 was $42.9 million use of cash related to changes in trade working capital. For the year ended December 31, 2007, accounts receivable increased $17.0 million and inventory increased by $85.0 million resulting in a net use of cash of $102.0 million. These uses of cash due to changes in trade working

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capital were partially offset by an increase in accounts payable, or a source of cash, of $59.1 million. Other primary uses of cash during the period include a $105.3 million increase in our insurance receivable related to the flood and a $57.7 million use of cash related to deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.

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Net cash flows ~~from~~provided by operating activities for the year ended December 31, 2006 was $186.6 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. 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. 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 year ended December 31, 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 December 31, 2006 (approximately three years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had declined, 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 $147.0 million decrease in the payable to swap counterparty. Reducing our operating cash flow for the year ended December 31, 2006 was a $0.3 million use of cash related to an increase in trade working capital. For the year ended December 31, 2006, accounts receivable decreased approximately $1.9 million while inventory increased $7.2 million and accounts payable increased $5.0 million. Other primary uses of cash during the period include a $5.4 million increase in prepaid expenses and other current assets and a $37.0 million reduction in accrued income taxes. Offsetting these uses of cash was an $86.8 million increase in deferred income taxes primarily the result of the unrealized gain on the Cash Flow Swap and a $4.6 million increase in other current liabilities.

Analysis of cash flows ~~from~~provided by operating activities for the year ended December 31, 2005 was impacted by the Subsequent Acquisition. See “— Factors Affecting ~~Comparability”.~~Comparability of Our Financial Results.” 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 the 174 days ended June 23, 2005 and the 233 days ended December 31, 2005.

Net cash flows ~~from~~provided by 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 flows provided by 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 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 “— Results of Operations — Consolidated Results of Operations — Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Consolidated)”. We have determined that the Cash Flow Swap does not

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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 year ended December 31, 2005

141

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 $256.7 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 233 days ended December 31, 2005 was $14.3 million. Trade working capital provided $8.0 million in cash during the 233 days ended December 31, 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 $98.4 million use of cash related to deferred income taxes and a $4.7 million use of cash related to other long-term assets.

Cash Flows Used Inin Investing Activities

Comparison of the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 and the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007

Net cash used in investing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2008 was ~~$26.2~~$49.6 million compared to ~~$107.4~~$214.1 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. The decrease in investing activities ~~for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007~~ was the result of decreased capital expenditures associated with various capital projects that commenced in the first quarter of 2007 in conjunction with the refinery turnaround. The majority of these capital projects were completed during the six months ended June 30, 2007.

Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006

Net cash used in investing activities for the year ended December 31, 2007 was $268.6 million compared to $240.2 million for the year ended December 31, 2006. The increase in investing activities for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was the result of increased capital expenditures associated with various capital projects in our petroleum business.

Net cash used in investing activities was $12.3 million for the 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.

Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.

Net cash used in investing activities for the year ended December 31, 2006 was $240.2 million compared to $12.3 million for the 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the year ended December 31, 2006 was the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.

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Cash Flows (Used in) Provided by Financing Activities

Comparison of the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2008 and the ~~Three~~Six Months Ended ~~March 31,~~June 30, 2007

Net ~~cash used for financing activities for the three months ended March 31, 2008 was $3.4 million as compared to net~~ cash provided by financing activities ~~of $29.0~~for the six months ended June 30, 2008 was $16.4 million as compared to $34.5 million for the ~~three~~six months ended ~~March 31,~~June 30, 2007. During the ~~three~~six months ended ~~March 31,~~June 30, 2008 ~~we paid $1.2 million of scheduled principal payments~~ and ~~deferred $2.1 million of initial public offering costs related to CVR Partners, LP. For the three months ended March 31,~~June 30, 2007, the primary source of cash was the result of borrowings drawn on our revolving credit facility.

Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006

Net cash provided by financing activities for the year ended December 31, 2007 was $111.3 million as compared to net cash provided by financing activities of $30.8 million for the year ended December 31, 2006. The primary sources of cash for the year ended December 31, 2007 were obtained through $399.6 million of proceeds associated with our initial public offering. The primary uses of cash for the year ended December 31, 2007 was $335.8 million of long-term debt retirement and $2.5 million in payments of financing costs. The primary sources of cash for the year ended December 31, 2006 were obtained through a refinancing of the Successor’s first and second lien credit facilities into a new long term debt credit facility of $1.075 billion, of which $775.0 million was outstanding as of December 31, 2006. The $775.0 million term loan under the credit facility was used to repay approximately $527.7 million in first and second lien debt outstanding, fund $5.5 million in prepayment penalties associated with the second lien credit facility and fund a $250.0 million cash distribution to Coffeyville Acquisition LLC. Other sources of cash included $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 issued under the first lien credit facility. During this period, we also paid $1.7 million of scheduled principal payments on the first lien term loans.

For the combined period ended December 31, 2005, net cash provided by financing activities was $660.0 million. The primary sources of cash for the combined periods ended December 31, 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. Additional sources of funds during the year ended December 31, 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 year ended December 31, 2005 were $24.6 million in deferred financing costs associated with the first and second lien debt commitments raised by Successor in connection with the Subsequent Acquisition and a $52.2 million cash distribution to Immediate Predecessor prior to the Subsequent Acquisition. See ‘‘— Liquidity and Capital Resources — Debt.”

Working Capital

Working capital at ~~March 31,~~June 30, 2008, was ~~$21.5~~$(35.5) million, consisting of ~~$622.5~~$634.3 million in current assets and ~~$601.0~~$669.8 million in current liabilities. Working capital at December 31, 2007 was $10.7 million, consisting of $570.2 million in current assets and $559.5 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of ~~$112.6~~$91.1 million at ~~March 31,~~June 30, 2008. In the current crude oil price environment, working capital is subject to substantial variability fromweek-to-week andmonth-to-month. Working capital was negatively impacted due to the reclassification of a portion of the insurance receivable related to the flood from current to non-current as of June 30, 2008.

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Letters of Credit

Our revolving credit facility provides for the issuance of letters of credit. At ~~March 31,~~June 30, 2008, there were $37.4 million of irrevocable letters of credit outstanding, including $5.8 million in support of certain environmental obligators and $31.6 million to secure transportation services for crude oil.

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 ~~March 31,~~June 30, 2008 relating to long-term debt, operating leases, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following ~~March 31,~~June 30, 2008 and thereafter.

Payments Due by Period
Nine Months

Ending

Total

2008

2009

2010

2011

2012

Thereafter

(in millions)

Contractual Obligations

Long-term debt(1) $ 488.0 $ 3.7 $ 4.8 $ 4.8 $ 4.7 $ 4.7 $ 465.3
Operating leases(2) 8.9 2.8 3.3 1.7 0.9 0.2 —
Unconditional purchase obligations(3) 582.3 20.8 28.2 55.8 53.9 51.3 372.3
Environmental liabilities(4) 8.8 2.6 0.7 1.6 0.3 0.3 3.3
Funded letter of credit fees(5) 10.1 3.4 4.5 2.2 — — —
Interest payments(6) 142.0 20.2 26.6 26.3 26.1 25.9 16.9

Total $ 1,240.1 $ 53.5 $ 68.1 $ 92.4 $ 85.9 $ 82.4 $ 857.8
Other Commercial Commitments

Standby letters of credit(7) $ 37.4 $ 37.4 $ — $ — $ — $ — $ —


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

Contractual Obligations
Long-term debt(1)	$	486.8	$	2.4	$	4.8	$	4.8	$	4.7	$	4.7	��	$	465.4
Operating leases(2)		8.5		1.9		3.3		2.2		0.9		0.2			—
Unconditional purchase obligations(3)		584.0		14.4		28.7		56.3		54.4		51.8			378.4
Environmental liabilities(4)		8.3		2.2		0.7		1.6		0.3		0.3			3.2
Funded letter of credit fees(5)		9.0		2.3		4.5		2.2		—		—			—
Interest payments(6)		137.5		13.7		27.0		26.8		26.5		26.3			17.2

Total	$	1,234.1	$	36.9	$	69.0	$	93.9	$	86.8	$	83.3		$	864.2
Other Commercial Commitments
Standby letters of credit(7)	$	37.4	$	37.4	$	—	$	—	$	—	$	—		$	—


(1)		Long-term debt amortization is based on the contractual terms of our Credit Facility. We may be required to amend our Credit Facility in connection with an offering by the Partnership. As of ~~March 31,~~June 30, 2008, ~~$488.0~~$486.8 million was outstanding under our credit facility. See “— Liquidity and Capital Resources — Debt.”


(2)		The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, 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 (1) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (2) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program. 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 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.”

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(6)		Interest payments are based on interest rates in effect at April 1, 2008 and assume contractual amortization payments.

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(7)		Standby letters of credit include $5.8 million of letters of credit issued in connection with environmental liabilities and $31.6 million in letters of credit to secure transportation services for crude oil.

In addition to the amounts described in the above table, we owe J. Aron approximately $123.7 million plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008) ~~which will be due August 31, 2008.~~. We ~~are in~~entered into a letter agreement with J. Aron on July 29, 2008 to defer until December 15, 2008 the ~~process of negotiating a deferral~~payment of $87.5 million of ~~these amounts owed~~the $123.7 million plus accrued interest we owe to J. ~~Aron until~~Aron. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at our option). If we consummate this notes offering before December 15, 2008, the $87.5 million deferral will automatically extend to July 31, 2009. ~~We cannot assure you that the new deferral agreement will be consummated.~~ Also, if the Partnership does not consummate an initial private or public offering by October 24, 2009, the managing general partner of the Partnership can require us to purchase the managing general partner interest at fair market value until the earlier of October 24, 2012 and the closing of the Partnership’s initial offering.

Our ability to make payments on and to refinance our indebtedness, to repay the amounts owed to J. Aron, to purchase the Partnership’s managing general partner interest if the Partnership’s managing general partner exercises its put right, 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, receipt of distributions from the Partnership and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile and have experienced significant increases in the cost of financing. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.

Off-Balance Sheet Arrangements

We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.

~~Recently Issued~~Recent Accounting ~~Standards~~Pronouncements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 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 standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At ~~March 31,~~June 30, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14 to our consolidated financial statements, “Fair Value Measurements”, included elsewhere in this prospectus.

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In February 2008, the FASB issued FASB Staff Position157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will not have a material impact on the Company’s financial position or earnings.

In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. Under this standard, an entity is required to provide additional information

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that will assist investors and other users of financial information to more easily understand the effect of the Company’s choice to use fair value on its earnings. Further, the entity is required to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 107,Disclosures about Fair Value of Financial Instruments. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of SFAS 159 did not impact the Company’s consolidated financial statements as of the ~~quarter~~six months ended ~~March 31,~~June 30, 2008.

In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of the acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR Energy will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141(R) will be limited to any future business combinations for which the acquisition date is on or after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160,Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.

In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement will change the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, net earnings, and cash flows. The Company will be required to adopt this statement as of January 1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Company’s consolidated financial statements.

~~The~~In May 2008, the FASB ~~recently~~ issued final FASB Staff Position (“FSP”) No. APB14-1,Accounting for Convertible Debt Instruments That May Bebe Settled in Cash upon Conversion (Including Partial Cash ~~Settlement~~Settlement). The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,Accounting for Derivative Instruments and Hedging Activities. Under the FSP, cash settled

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convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years and will require issuers of convertible debt that can be settled in cash to record the additional expense incurred. The Company is currently evaluating the FSP in conjunction with its convertible debt offering.

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Critical Accounting Policies

We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.

Receivables from Insurance

As of ~~March 31,~~June 30, 2008, we have incurred total gross costs of approximately of ~~$154.5~~$153.6 million as a result of the 2007 flood and crude oil discharge. During this period, we have maintained insurance policies that were issued by a variety of insurers and which covered various risks, such as property damage, interruption of our business, environmental cleanup costs, and potential liability to third parties for bodily injury or property damage. Accordingly, as of ~~March 31,~~June 30, 2008, we have recognized receivables of approximately ~~$107.2~~$102.4 million related to these gross costs incurred that we believe are probable of recovery from the insurance carriers under the terms of the respective policies. As of ~~March 31,~~June 30, 2008, we have collected approximately $21.5 million of these receivables. In July 2008 we received an additional $13.0 million from our property insurance policy.

We ~~are in the process of submitting our~~have submitted voluminous claims information to, ~~responding~~and continue to respond to information requests from and ~~negotiating~~negotiate with, the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. Our property insurers have raised a question as to whether our facilities are principally located in “Zone A,” which iswas, at the time of the flood, subject to a $10 million insurance limit for flood or “Zone B”’ which iswas, at the time of the flood, subject to a $300 million insurance limit for flood. We have reached agreement with ~~32.5%~~certain of our property insurers representing approximately 32.5% of our total property coverage for theflood that our facilities are principally located in ~~Zone B.~~“Zone B” and are therefore subject to the $300 million limit for flood. Our remaining property insurers have not, at this time, agreed to this position. In addition, our primary environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup,” which is subject to a $10 million sub-limit, rather than “property damage,” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While we will vigorously contest the primary carrier’s position, we ~~believe~~contend that if that position were upheld, our umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. ~~Although each~~Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage ~~defenses, we are vigorously pursuing our insurance recovery claims. Ultimate recovery will be subject to continued negotiation as well as litigation.~~defenses. See “Flood and Crude Oil Discharge — Insurance” for a discussion of two lawsuits we filed against certain of our insurance carriers on July 10, 2008.

There is inherent uncertainty regarding the ultimate amount or timing of the recovery of the insurance receivable because of the difficulty in projecting the final resolution of our claims. The

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difference between what we ultimately receive under our insurance policies compared to the receivable we have recorded could be material to our consolidated financial statements.

Long-Lived Assets

We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. CVR accounts for impairment oflong-lived assets in accordance with SFAS No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with SFAS 144, CVR reviewslong-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

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the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.

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, $94.5 million, $(282.0) million and ~~$(47.9)~~$(127.2) million in gain (loss) on derivatives for the fiscal years ended December 31, 2005, 2006 and 2007 and the ~~three~~six months ended ~~March 31,~~June 30, 2008, respectively.

As of ~~March 31,~~June 30, 2008, a $1.00 change in quoted prices for the crack spreads utilized in the Cash Flow Swap would result in a ~~$36.2~~$30.1 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 (exclusive of estimated obligations associated with the crude oil discharge) at ~~March 31,~~June 30, 2008 totaled ~~$7.7~~$7.2 million, including ~~$2.8~~$2.5 million included in current liabilities. Additionally, at ~~March 31,~~June 30, 2008, ~~$1.0~~$1.2 million was included in current liabilities for estimated future remediation obligations arising from the crude oil

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discharge. This amount also included estimated obligations to settle third party property damage claims resulting from the crude oil discharge.

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 capable of being estimated.

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

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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.

Consolidation of Variable Interest Entities

In accordance with FIN No. 46R management has reviewed the terms associated with our interests in the Partnership based upon the partnership agreement. Management has determined that the Partnership is treated as a variable interest entity and as such has evaluated the criteria under FIN 46R to determine that we are the primary beneficiary of the Partnership. FIN 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. FIN 46R defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and where there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. As the primary beneficiary, we absorb the majority of the expected lossesand/or receive a majority of the expected residual returns of the VIE’s activities.

We will need to reassess our investment in the Partnership from time to time to determine whether we are the primary beneficiary. If in the future we conclude that we are no longer the primary beneficiary, we will be required to deconsolidate the activities of the Partnership on a going forward basis. The interest would then be recorded using the equity method and the Partnership gross revenues, expenses, net income, assets and liabilities as such would not be included in our consolidated financial statements.

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

Our petroleum business, as a manufacturer of refined petroleum products, and the nitrogen fertilizer business, as a manufacturer of nitrogen fertilizer products, all of which are commodities, has

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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;

	•	hedge the value of inventories in excess of minimum required inventories; and

	•	hedge the value of inventories held with respect to our rack marketing business.

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

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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 into 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 underlying 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. The most significant derivative position we have is our Cash Flow Swap. The Cash Flow Swap, for which the underlying commodity is the crack spread, enabled us to lock in a margin on the spread between the price of crude oil and price of refined products at the execution date of the agreement. We may look for opportunities to reduce the effective position of the Cash Flow Swap by buying either exchange-traded contracts in the form of futures contracts or over-the-counter contracts in the form of commodity price swaps. In addition, we may sell forward crack spreads when opportunities exist to lock in a margin.

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

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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.

As of ~~March 31,~~June 30, 2008, a $1.00 change in quoted futures price for the crack spreads described in the first bullet point would result in a ~~$36.2~~$30.1 million change to the fair value of the derivative commodity position and the same change in net income.

Interest Rate Risk

As of ~~March 31,~~June 30, 2008, all of our ~~$488.0~~$508.3 million of outstanding ~~term~~ debt under our credit facility was at floating rates. An increase of 1.0% in the LIBOR rate would result in an increase in our interest expense of approximately ~~$4.9~~$5.2 million per year.

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In an effort to mitigate the interest rate risk highlighted above and as required under our then-existing 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 forth 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

$250.0 million

March 31, 2008

March 30, 2009

4.195

$180.0 million

March 31, 2009

March 30, 2010

4.195

$110.0 million

March 31, 2010

June 29, 2010

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 year ended December 31, 2007, we had $4.8 million of realized and unrealized losses on these interest rate swaps. For the ~~three~~six months ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 30, 2007, we had ~~$5.6~~$(1.7) million and ~~$0.6~~$2.4 million of realized and unrealized ~~losses~~gains (losses) on these interest rate swaps, respectively.

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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, 2008, there were 146 oil refineries operating in the United States, with the 15 smallest each having a capacity of 13,000 bpd or less, and the 10 largest having capacities ranging from 306,000 to 567,000 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 gasoline crack spread, (2) the heat crack spread, and (3) the 2-1-1 crack spread. The gasoline crack spread is the simple difference in per barrel value between reformulated gasoline (gasoline with compounds or properties 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 distillates. 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.

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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,

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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 $11.37 per barrel from 2004 to June 30, 2008. The following chart shows a rolling average of the NYMEX based 2-1-1 crack spread from 1994 through June 30, 2008:

Source: Platts

There are a number of reasons high crude oil costs have a negative impact on our earnings. Less than 100% of the crude oil we purchase can actually be turned into profitable transportation fuels; the conversion process also produces less valuable byproducts such as pet coke, slurry and sulfur. These byproducts are less valuable than transportation fuels, and their sales prices have not increased in proportion to crude oil prices. Therefore, as the price on crude oil increases our loss on byproduct sales increases, which results in a reduction in earnings. Also, as discussed previously, as crack spreads increase in absolute terms in connection with higher crude prices, the Company realizes increasing losses on the Cash Flow Swap.

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 0.8% per year compared to total domestic refining capacity growth of only 0.3% per year. Substantially all of the projected demand growth is expected to come from the increased consumption of transportation fuels.

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 5% between January 1981 and January 2008 from 18.6 million bpd to 17.6 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.

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As reflected within the U.S. Days Forward Supply and the U.S. Mogas Inventory statistics provided by the EIA, the gasoline available for consumption in the United States has declined year after year. This trend is in most part attributable to a steady increase in demand that has not been matched by an equal increase in supply. Although existing refiners are improving their utilization rates, the total number of refiners has declined. As a result, the U.S. has been dependent on imported fuels

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to meet domestic demand while the global supply which has historically been available for importation has been subject to increasing worldwide demand. With this reduction in days of available supply, we believe the U.S. will occasionally experience periods of little or no supply of gasoline in various markets as the supply and distribution system continues to strain to match available inventory with consumer demand.

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 2007, refinery utilization increased from 69% to 89%. The EIA projects that utilization will remain high relative to historic levels, through 2030, ranging from 86% to 92% of design capacity.

~~The price discounts available to refiners of heavy~~Heavy sour crude oil ~~have widened as many refiners have turned~~continues to price at a discount 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.~~oils will enjoy a crude oil cost advantage.

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

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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.

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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 12% of total U.S. consumption in 2005. 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 mid-continent region where our refinery is located, 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.

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 38% 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 2007, demand for gasoline and distillates (primarily diesel fuels, kerosene and jet fuel) exceeded refining production in the mid-continent region, 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.

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Nitrogen Fertilizer Industry

Plant Nutrition and Nitrogen Fertilizers

Commercially produced nitrogen fertilizers provide primary nutrients for plant growth in a form that is readily absorbable. Nitrogen is an essential element for plant growth and vigor and is the most important element for increasing yields in crop plants. Nitrogen and other plant nutrients are found naturally in organic matter and soil materials but are depleted by intensive crop production and harvesting. Replenishing nitrogen through application of commercial fertilizers is the most widely used way of sustaining or increasing crop yields. Two primary sources of plant nutrients are manufactured fertilizers and organic manures. Farmers determine the types, quantity and proportions of fertilizer to apply depending upon crop type, soil and weather conditions, regional farming practices, fertilizer and crop prices and other factors.

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 such as corn, which on average requires100-160 pounds of nitrogen for each acre of plantings. 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 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.

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Urea Ammonium Nitrate Solution. 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.

In 2007, we produced approximately 326,662 tons of ammonia, of which approximately 72% was upgraded into approximately 576,888 tons of UAN.

Ammonia Production Technology — Advantages of Pet 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 was 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 as a result production costs increase significantly as natural gas prices 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 petroleum refining process. The pet coke gasification process, which the nitrogen fertilizer business commercially employs at its fertilizer plant, the only such plant in North America, takes advantage of the large cost differential between pet coke and

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natural gas in current markets. The nitrogen fertilizer plant’s pet coke gasification process allows it to use approximately 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. The nitrogen fertilizer business also benefits from the ready availability of pet coke supply from our 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 and pricing. 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 that45-year period, North American fertilizer demand has grown 2.4% annually with North American nitrogen fertilizer demand growing at a faster rate of 3.3% annually. North American fertilizer demand is met both through domestic production and imports from Latin America, the Middle East and the former Soviet Union.

According to the United States Department of Agriculture, or USDA, U.S. farmers planted 92.9 million acres of corn in 2007, exceeding the 2006 planted area by 19 percent. This increase was driven in large part by ethanol demand. The actual planted acreage is the highest on record since 1944, when farmers planted 95.5 million acres of corn. Farmers in nearly all states increased their planted corn acreage in 2007. State records were established in Illinois, Indiana, Minnesota and North Dakota, while Iowa led all states in total planted corn acres. A net effect of these additional planted acres was to increase the demand for nitrogen fertilizers by over one million tons. This equates to an annual increase of 3.3 million tons of UAN, or approximately 5 times the nitrogen fertilizer plant’s total UAN production. The USDA ~~is forecasting as~~projects corn plantings to maintain at an average of ~~March~~91.6 million acres between 2009 and 2013.

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The USDA June 2008 ~~that~~Acreage Report showed a decline in the total U.S. planted corn acreage in 2008 ~~will decline~~ to 8687.3 million acres. Despite this decrease, Blue Johnson estimates that nitrogen fertilizer consumption by farm users in 2008 will increase by one million tons due to the need to correct for under fertilization of corn in 2007, a forecasted increase in total planted wheat acreage and very strong crop prices. This estimated increase in nitrogen usage translates into an annual increase of 3.3 million tons of UAN, or approximately five times the nitrogen fertilizer business’ total 2008 estimated UAN production.

The Farm Belt Nitrogen Market

The majority of the nitrogen fertilizer business’ 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 and importers. As a result, locally based fertilizer producers, such as the nitrogen fertilizer business, enjoy a distribution cost advantage over U.S. Gulf Coast ammonia and UAN producers and importers. Southern Plains spot ammonia and corn belt UAN 32 prices averaged $337/ton and $201/ton, respectively, for the

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2003 through 2007 period, based on data provided by Blue Johnson. The volumes of ammonia and UAN sold into certain farm belt markets in 2007 are set forth in the table below:

2005-2007 Average U.S. Ammonia and UAN Demand in Selected Mid-continent Areas


	Ammonia		UAN 32
State	Quantity		Quantity(1)
	(thousand tons
	per year)

Texas		2,125		850
Oklahoma		95		200
Kansas		395		690
Missouri		325		230
Iowa		710		900
Nebraska		425		1,150
Minnesota		310		200


(1)		UAN 32, which consists of 45% ammonium nitrate, 35% urea and 20% water, contains 32% nitrogen by weight and is the most common grade of UAN sold in the United States.Source: Blue Johnson

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 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

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gas, the marginal cost and pricing of fertilizer products also tend to exhibit positive correlation with the price of natural gas.

Strong industry fundamentals have led current demand for nitrogen fertilizers to all time highs. US corn inventories at the end of the2008-2009 fertilizer year are projected to be at 673 million bushels, which is the lowest level since1995-1996. Corn prices are at record high levels, and corn planting for2008-2009 is projected to be higher than2007-2008. Nitrogen fertilizer prices are at record high levels due to increased demand and increasing worldwide natural gas prices. In addition, nitrogen fertilizer prices have been decoupled from their historical correlation with natural gas prices in recent years and increased substantially more than natural gas prices in 2007 and 2008 (based on data provided by Blue Johnson). The quest for healthier lives and better diets in developing countries is a primary driving factor behind the increased global demand for fertilizers. As of ~~July 22,~~August 14, 2008, our order book for all orders received prior to such date is ~~378,473~~333,561 tons of UAN at an average netback price of ~~$358.16~~$361.73 per ton and ~~30,216~~32,202 tons of ammonia at an average netback price of ~~$692.53.~~$767.40. There has been a significant increase in nitrogen fertilizer prices in the last few months. As of July 22, 2008, our order book for orders received solely during the month of July 2008 is 76,502 tons of UAN at an average netback price of $483.31 per ton and 3,411 tons of ammonia at an average netback price of $857.17 per ton.

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The historical average annual U.S. corn belt ammonia and UAN 32 spot prices as well as natural gas and crude oil prices are detailed in the table below.


Year	Natural Gas		WTI		Ammonia		UAN 32		Natural Gas		WTI		Ammonia		UAN 32
	($/million btu)		($/bbl)		($/ton)		($/ton)		($/million btu)		($/bbl)		($/ton)		($/ton)

1990		1.78		24.53		125		90		1.78		24.53		125		90
1991		1.53		21.55		130		97		1.53		21.55		130		97
1992		1.73		20.57		134		95		1.73		20.57		134		95
1993		2.11		18.43		139		102		2.11		18.43		139		102
1994		1.94		17.16		197		108		1.94		17.16		197		108
1995		1.69		18.38		238		132		1.69		18.38		238		132
1996		2.50		22.01		217		129		2.50		22.01		217		129
1997		2.48		20.59		220		116		2.48		20.59		220		116
1998		2.16		14.43		162		96		2.16		14.43		162		96
1999		2.32		19.26		145		86		2.32		19.26		145		86
2000		4.32		30.28		208		115		4.32		30.28		208		115
2001		4.04		25.92		262		144		4.04		25.92		262		144
2002		3.37		26.19		191		108		3.37		26.19		191		108
2003		5.49		31.03		292		141		5.49		31.03		292		141
2004		6.18		41.47		326		170		6.18		41.47		326		170
2005		9.02		56.58		394		210		9.02		56.58		394		210
2006		6.98		66.09		379		196		6.98		66.09		379		196
2007		7.12		72.36		469		290		7.12		72.36		469		290
2008 (through June 30)		10.14		111.12		696		388
2008 (through July 31)										10.78		114.47		739		402

Source: Bloomberg (natural gas and WTI) and Blue Johnson (ammonia and UAN)

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BUSINESS

We are an independent refiner and marketer of high value transportation fuels and, through a limited partnership, a producer of ammonia and UAN fertilizers. We are one of only eight petroleum refiners and marketers located within the mid-continent region (Kansas, Oklahoma, Missouri, Nebraska and Iowa). The nitrogen fertilizer business is the only operation in North America that uses a coke gasification process, and at current natural gas and pet coke prices, the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America.

Our petroleum business includes a 115,000 bpd complex full coking medium-sour crude refinery in Coffeyville, Kansas. In addition, our supporting businesses include (1) a crude oil gathering system serving central Kansas, northern Oklahoma and southwestern Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and associated crude oil storage tanks with a capacity of approximately 1.2 million barrels and (4) 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 into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Partners L.P. and NuStar Energy L.P. Our refinery is situated approximately 100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubs 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 oil variety in the world capable of being transported by pipeline.

The nitrogen fertilizer business, consists of a nitrogen fertilizer manufacturing facility comprised of (1) a 1,225ton-per-day ammonia unit, (2) a 2,025ton-per-day UAN unit and (3) an 84 million standard cubic foot per day gasifier complex. The nitrogen fertilizer business is the only operation in North America that utilizes a coke gasification process to produce ammonia (based on data provided by Blue Johnson). In 2007, approximately 72% of the ammonia produced by the fertilizer plant was further upgraded to UAN fertilizer (a solution of urea, ammonium nitrate and 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 a primary raw material, at current natural gas and pet coke prices the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. Furthermore, on average during the last four years, over 75% of the pet coke utilized by the fertilizer plant was produced and supplied to the fertilizer plant as a by-product of our refinery. As such, the nitrogen fertilizer business benefits from high natural gas prices, as fertilizer prices generally increase with natural gas prices, without a directly related change in cost (because pet coke rather than natural gas is used as a primary raw material). During the second quarter of 2008, we enjoyed unprecedented fertilizer prices which contributed favorably to our earnings.

We have two business segments: petroleum and nitrogen fertilizer. We generated combined net sales of $2.4 billion, $3.0 billion and $3.0 billion and operating income of $270.8 million, $281.6 million and $186.6 million for the fiscal years ended December 31, 2005, 2006 and 2007, respectively. Our petroleum business generated $2.3 billion, $2.9 billion and $2.8 billion of our combined net sales, respectively, over these periods, with the nitrogen fertilizer business generating substantially all of the remainder. In addition, during these periods, our petroleum business contributed $199.7 million, $245.6 million and $144.9 million, respectively, of our combined operating income with substantially all of the remainder contributed by the nitrogen fertilizer business. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, we generated combined net sales of ~~$1.22~~$2.74 billion and operating income of ~~$87.4~~$210.3 million. Our petroleum business generated ~~$1.17~~$2.63 billion of our combined net sales and ~~$63.6~~$165.5 million of our combined operating income during this period, with substantially all of the remainder contributed by the nitrogen fertilizer business.

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Our Competitive Strengths

Regional Advantage and Strategic Asset Location. Our refinery is located in the southern portion of the PADD II Group 3 distribution area. Because refined product demand in this area exceeds production, the region has historically required U.S. Gulf Coast imports to meet demand. We estimate that this favorable supply/demand imbalance allowed refineries in PADD II Group 3 to generate higher refining margins, measured by the 2-1-1 crack spread, as compared to U.S. Gulf Coast refineries on average during the last four years. The 2-1-1 crack spread is a general industry standard that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil.

In addition, the nitrogen fertilizer business is geographically advantaged to supply nitrogen fertilizer products to markets in Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without incurring intermediate transfer, storage, barge or pipeline freight charges. Because the nitrogen fertilizer business does not incur these costs, this geographic advantage provides it with a distribution cost advantage over competitors not located in the farm belt who transport ammonia and UAN from the U.S. Gulf Coast, based on recent freight rates and pipeline tariffs for U.S. Gulf Coast importers.

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 maintain capacity on the Spearhead pipeline, owned by CCPS Transportation, LLC (which is ultimately owned by Enbridge), which connects Chicago to the Cushing hub. We have also committed to additional pipeline capacity on the proposed Keystone pipeline project currently under development by TransCanada Keystone Pipeline, LP which will provide us with access to incremental oil supplies from Canada. We also own and operate a crude gathering system serving northern Oklahoma, central Kansas and southwestern Nebraska, which allows us to acquire quality crudes at a discount to WTI.

High Quality, Modern Refinery 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. In particular, in 2007 42% of our refinery’s product yield consisted of higher-margin diesel fuel (mainly ultra low sulfur diesel). 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 June 2005 through ~~March 31,~~June 30, 2008, we have invested approximately ~~$550~~$566 million to modernize our oil refinery and to meet more stringent U.S. environmental, health and safety requirements. As a result, our refinery’s complexity has increased from ~~10.0~~10.3 to 12.1, and we have achieved significant increases in our refinery crude oil 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, over 94,500 bpd for all of 2006 and over 110,000 bpd in the fourth quarter of 2007 with maximum daily rates in excess of 120,000 bpd for the fourth quarter of 2007.

Unique Coke Gasification Fertilizer Plant. The nitrogen fertilizer plant, completed in 2000, is the newest fertilizer facility in North America and the only one of its kind in North America using a pet coke gasification process to produce ammonia. While this facility is unique to North America, gasification technology has been in use for over 50 years in various industries to produce fuel, chemicals and other products from carbon-based source materials. Because it uses significantly less natural gas in the manufacture of ammonia than other domestic nitrogen fertilizer plants, with the currently high price of natural gas the nitrogen fertilizer business’ feedstock cost per ton for ammonia is considerably lower than that of its natural gas-based fertilizer plant competitors. We estimate that the facility’s production cost advantage over U.S. Gulf Coast ammonia producers is sustainable at natural gas prices as low as $2.50 per MMBtu (at ~~July 15,~~August 14, 2008, the price of natural gas was ~~$11.48~~$8.14 per MMBtu).

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Near Term Internal Expansion Opportunities. Since June 2005, we have identified and developed several significant capital improvements 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 substantial completion of approximately $522 million of significant capital improvements (including $170 million in expenditures for our refinery expansion project, excluding $3.7 million in related capitalized interest), 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. The spare gasifier at the nitrogen fertilizer plant was expanded in 2006, increasing ammonia production by 6,500 tons per year. In addition, the nitrogen fertilizer plant is moving forward with an approximately $120 million fertilizer plant expansion, of which approximately ~~$11~~$14.5 million was incurred as of ~~March 31,~~June 30, 2008. It is estimated that this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium-priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010.

Experienced Management Team. In conjunction with the acquisition of our business in June 2005 by funds affiliated with Goldman, Sachs & Co. and Kelso & Company, L.P., or the Goldman Sachs Funds and the Kelso Funds, a new senior management team was formed that combined selected members of existing management with experienced new members. Our senior management team averages over 28 years of refining and fertilizer industry experience and, in coordination with our broader management team, has increased our operating income and stockholder value since June 2005.

Mr. John J. Lipinski, our Chief Executive Officer, has over 36 years of 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 34 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 19 years of 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

The primary business objectives for our refinery business are to increase value for our stockholders and to maintain our position as an independent refiner and marketer of refined fuels in our markets by maximizing the throughput and efficiency of our petroleum refining assets. In addition, management’s business objectives on behalf of the nitrogen fertilizer business are to increase value for our stockholders and maximize the production and efficiency of the nitrogen fertilizer facilities. We intend to accomplish these objectives through the following strategies:

Pursuing Organic Expansion Opportunities. We continually evaluate opportunities to expand our existing asset base and consider capital projects that accentuate our core competitiveness in petroleum refining. We are also evaluating projects that will improve our ability to process heavy crude oil feedstocks and to increase our overall operating flexibility with respect to crude oil slates. In addition, management also continually evaluates capital projects that are intended to enhance the Partnership’s competitiveness in nitrogen fertilizer manufacturing.

Increasing the Profitability of Our Existing Assets. We strive to improve our operating efficiency and to reduce our costs by controlling our cost structure. We intend to make investments to improve the efficiency of our operations and pursue cost saving initiatives. We have recently completed the greenfield construction of a new continuous catalytic reformer. This project is expected to increase the profitability of our petroleum business through increased refined product yields and the elimination of scheduled downtime associated with the reformer that was replaced. In addition, this project reduces the dependence of our refinery on hydrogen supplied by the fertilizer facility, thereby

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allowing the nitrogen fertilizer business to generate higher margins by using the hydrogen to produce ammonia and UAN. The nitrogen fertilizer business expects, over time, to convert 100% of its production to higher-margin UAN.

Seeking Strategic Acquisitions. We intend to consider strategic acquisitions within the energy industry that are beneficial to our shareholders. We will seek acquisition opportunities in our existing areas of operation that have the potential for operational efficiencies. We may also examine opportunities in the energy industry outside of our existing areas of operation and in new geographic regions. In addition, working on behalf of the Partnership, management may pursue strategic and accretive acquisitions within the fertilizer industry, including opportunities in different geographic regions. We have no agreements or understandings with respect to any acquisitions at the present time.

Pursuing Opportunities to Maximize the Value of the Nitrogen Fertilizer Business. Our management, acting on behalf of the Partnership, will continually evaluate opportunities that are intended to enable the Partnership to grow its distributable cash flow. Management’s strategies specifically related to the growth opportunities of the Partnership include the following:


	•	*Expanding UAN Production.* The nitrogen fertilizer business is moving forward with an approximately $120 million nitrogen fertilizer plant expansion, of which approximately ~~$11~~$14.5 million was incurred as of ~~March 31,~~June 30, 2008. This expansion is expected to permit the nitrogen fertilizer business to increase its UAN production and to result in its UAN manufacturing facility consuming substantially all of its net ammonia production. This should increase the nitrogen fertilizer plant’s margins because UAN has historically been a higher margin product than ammonia. The UAN expansion is expected to be complete in July 2010 and it is estimated that it will result in an approximately 50% increase in the nitrogen fertilizer business’ annual UAN production. The company has also begun to acquire or lease offsite UAN storage facilities and continues to expand this program.


	•	*Executing Several Efficiency-Based and Other Projects.* The nitrogen fertilizer business is currently engaged in several efficiency-based and other projects in order to reduce overall operating costs, incrementally increase its ammonia production and utilize byproducts to generate revenue. For example, by redesigning the system that segregates carbon dioxide, or CO₂, during the gasification process, the nitrogen fertilizer business estimates that it will be able to produce approximately 25 tons per day of incremental ammonia, worth approximately $6$8 million per year at current market prices. The nitrogen fertilizer business estimates that this project will cost approximately $7 million (of which none has yet been incurred) and will be completed in 2010. The nitrogen fertilizer business has a proven track record of operating gasifiers and is well positioned to offer operating and technical services as a third-party operator to other gasifier-based projects.


	•	*Evaluating Construction of a Third Gasifier Unit and a New Ammonia Unit and UAN Unit at the Nitrogen Fertilizer Plant.* The nitrogen fertilizer business has engaged a major engineering firm to help it evaluate the construction and operation of an additional gasifier unit to produce a synthesis gas from pet coke. It is expected that the addition of a third gasifier unit, together with additional ammonia and UAN units, to the nitrogen fertilizer business’ operations could result, on a long-term basis, in an increase in UAN production of approximately 75,000 tons per month. This project is in its earliest stages of review and is still subject to numerous levels of internal analysis.

Other opportunities our management may consider on behalf of the Partnership in the event that its managing general partner proceeds with an initial offering include acquiring certain of our petroleum business’ ancillary assets and providing incremental pipeline transportation and storage infrastructure services to our petroleum business. There are currently no agreements or understandings in place with respect to any such acquisitions or opportunities, and there can be no assurance that the Partnership would be able to operate any of these assets or businesses profitably.

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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 refinery assets and the nitrogen fertilizer plant 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 CLJV Holdings, LLC (CLJV), 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, the entire interest in the Judith Leiber business held by CLJV was returned to The Leiber Group, Inc. in exchange for all of its ownership interest in CLJV, resulting in a complete separation of the Immediate Predecessor and the Judith Leiber business.

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.

We were formed in Delaware in September 2006 as a wholly owned subsidiary of Coffeyville Acquisition LLC in order to complete the initial public offering of the businesses acquired by Coffeyville Acquisition, LLC from Coffeyville Group Holdings LLC. We completed our initial public offering on October 26, 2007. At that time, we transferred the nitrogen fertilizer business to CVR Partners, LP, a limited partnership we formed in June 2007. As consideration for the transfer, we received 30,303,000 special GP units and 30,333 special LP units in the Partnership, and the Partnership’s managing general partner, which at that time was our indirect wholly-owned subsidiary, received the managing general partner interest and the IDRs. Immediately prior to the consummation of our initial public offering, we sold the managing general partner, together with the IDRs, to Coffeyville Acquisition III LLC, an entity owned by the Goldman Sachs Funds, the Kelso Funds and certain members of CVR Energy’s senior management team, for its fair market value on the date of sale.

Petroleum Business

Asset Description

We operate one of the eight refineries located within the mid-continent region (Kansas, Oklahoma, Missouri, Nebraska and Iowa). The Company’s complex cracking and coking medium-sour oil refinery has a maximum capacity of 123,500 bpd of petroleum products, which accounts for approximately 17% of the region’s output. The facility is situated on approximately 440 acres in southeastern Kansas, approximately 100 miles from Cushing, Oklahoma, a major crude oil trading and storage hub.

The 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 and distillate, thereby providing a competitive advantage over less complex refineries. We have a modified Solomon complexity score of ~~approximately~~ 12.1, up from ~~10.0~~10.3 in June 2005. “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

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~~throughput~~ of each refinery unit, divided by the crude capacity of the refinery. For the year ended December 31, 2007, our refinery’s product yield included gasoline (mainly regular unleaded) (45%), diesel fuel (mainly ultra low sulfur diesel) (42%), and coke and other refined products such as NGL (propane, butane), slurry, reformer feeds, sulfur, gas oil and produced fuel (13%).

The refinery consists of two crude units and two vacuum units. 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 capacity crude oil gathering system serving central Kansas, northern Oklahoma and southwestern Nebraska. The system has field offices in Bartlesville, Oklahoma and Plainville and Winfield, Kansas. The system is comprised of over 300 miles of feeder and trunk pipelines, 43 trucks, and associated storage facilities for gathering light, sweet Kansas, Nebraska and Oklahoma crude oils purchased from independent crude producers. We also lease a section of a pipeline from Magellan Pipeline Company, L.P.

	•	*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. We also collect fees for refined products we store for another oil company.

	•	*Pipelines.* We own a 145,000 bpd proprietary pipeline system that transports crude oil from Caney, Kansas to our refinery. Crude oils sourced outside of our proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to Caney, Kansas via a pipeline owned by Plains All American L.P. We also own associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our refinery.

	•	*Rack Marketing Division.* We own a rack marketing division which supplies product through tanker trucks directly to customers located in close geographic proximity to our refinery and Phillipsburg terminal and to customers at throughput terminals on Magellan Midstream Partners L.P.’s refined products distribution systems.

Feedstocks Supply

Our refinery has the capability to process blends of a variety of crudes ranging from heavy sour to light sweet crudes. Currently, our refinery processes crude from a broad array of sources. We purchase foreign crudes from Latin America, South America, West Africa, the Middle East, the North Sea and Canada. We purchase domestic crudes from Kansas, Oklahoma, Nebraska, Texas, and offshore deepwater Gulf of Mexico production. While crude oil has historically constituted over 85% of our feedstock inputs during the last five years, other feedstock inputs include isobutane, normal butane, natural gas, alky feed, gas oil and vacuum tower bottoms.

Crude is supplied to our refinery through our wholly owned gathering system and by pipeline. Our crude gathering system was expanded in 2006 and currently supplies in excess of 21,000 bpd of crude to the refinery (approximately 20% of total supply). ~~Locally~~These locally produced crudes are delivered to the refinery at a discount to WTI and are of similar quality to WTI. Gathered barrels are delivered at an economic value equivalent to, or better than, that of WTI. These lighter sweet crudes allow us to blend higher percentages of low cost crudes such as heavy sour Canadian while maintaining our

165

target medium sour blend with an API gravity of28-36 degrees and 0.9-1.2% sulfur. Crude oils

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sourced outside of our proprietary gathering system are delivered to Cushing, Oklahoma by various pipelines including Seaway, Basin and Spearhead and subsequently to Coffeyville via Plains pipeline and our own 145,000 bpd proprietary pipeline system.

For the year ended December 31, 2007, our crude oil supply blend was comprised of approximately 65% light sweet crude oil, 12% heavy sour crude oil and 23% medium/light sour crude oil. The light sweet crude oil includes our locally gathered crude oil. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, our crude oil supply blend was comprised of approximately ~~68%~~69% of light sweet crude oil, ~~14%~~12% heavy sour crude oil and ~~18%~~19% medium/light sour crude oil.

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 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.

Distribution, Sales and Marketing

We focus our petroleum products marketing efforts in the central mid-continent and Rocky Mountain areas because of their relative proximity to our oil refinery and their pipeline access.

Since June 2005, we have significantly expanded our rack sales. Rack sales are sales made using tanker trucks via either a proprietary or third party terminal facility designed for truck loading. In the year ended December 31, 2007, approximately 23% of the refinery’s products were sold through the rack system directly to retail and wholesale customers while the remaining 77% was sold through pipelines via bulk spot and term contracts. Rack sales represent an increasing percentage of our total sales in 2008; we currently sell approximately 35% of the refinery’s products through the rack system and approximately 65% through pipelines. Furthermore, almost 75% of the gasoline sold through the rack system contains ethanol, up from approximately 33% in 2007.

We make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.

We are able to distribute gasoline, diesel fuel, and natural gas liquids produced at the refinery either into the Magellan or Enterprise pipelines and further on through NuStar and other Magellan systems or via the trucking system. The Magellan #2 and #3 pipelines (with capacity of 81,000 bpd and 32,000 bpd, respectively) are connected directly to the refinery and transport products to Kansas City and other northern cities. The NuStar and Magellan (Mountain) pipelines are accessible via the Enterprise outbound line (with capacity of 12,000 bpd) or through the Magellan system at El Dorado, Kansas. Our fuels loading rack at our refinery has a maximum delivery capability of 40,000 bpd of finished gasoline and diesel fuels.

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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.

Customers

Customers for our petroleum products include other refiners, convenience store companies, railroads and farm cooperatives. We have bulk term contracts in place with many of these customers, which typically extend from a few months to one year in length. For the year ended December 31, 2007, QuikTrip Corporation accounted for 11.6% of our petroleum business sales and 64.3% of our petroleum sales were made to our 10 largest customers. For the ~~three~~six months ended ~~March 31,~~June 30, 2008, QuikTrip Corporation accounted for ~~14.8%~~13.2% of our petroleum business sales and ~~66.1%~~65.2% of our petroleum sales were made to our 10 largest customers.

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Competition

Our oil refinery in Coffeyville, Kansas ranks second in processing capacity and fourth in refinery complexity, among the eight mid-continent fuels refineries. The following table presents certain information about us and six other large 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		13.7
CVR Energy	Coffeyville, KS		115,000		12.1
Frontier Oil	El Dorado, KS		110,000		13.0
Valero	Ardmore, OK		91,500		11.2
NCRA	McPherson, KS		82,700		13.1
Sinclair	Tulsa, OK		70,000		6.2
Gary Williams Energy	Wynnewood, OK		52,500		8.5

Mid-continent Total:			708,700

Source: 2007 Oil and Gas ~~Journal.~~Journal Worldwide Refining Survey. A Sunoco refinery located in Tulsa, Oklahoma was excluded from this table because it is not a stand-alone fuels refinery. The table also excludes Ventura Refining’s refinery in Thomas, Oklahoma that processes less than 15,000 barrels per calendar day. The Solomon Complexity Index of each of these facilities has been calculated based on data from the Oil and Gas Journal together with Company estimates and assumptions.

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.

Seasonality

Our petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel during the winter months also decreases due to 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 monthsand/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products can vary demand for gasoline and diesel fuel.

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Nitrogen Fertilizer Business

The nitrogen fertilizer business operates 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. The nitrogen fertilizer business is also moving forward with an $120 million fertilizer plant expansion, of which approximately ~~$11~~$14.5 million was incurred as of ~~March 31,~~June 30, 2008, which we estimate could increase the facility’s capacity to upgrade ammonia into premium priced UAN by 50% and which we expect to be completed in June 2010.

The facility uses a gasification process licensed from an affiliate of The General Electric Company, or General Electric, to convert pet coke to high purity hydrogen for subsequent conversion to ammonia. It uses between 975 to 1,075 tons per day of pet coke from the refinery and another 260 to 310 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. The 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 nitrogen fertilizer plant’s pet coke gasification process uses approximately 1% of the natural gas used by other nitrogen-based fertilizer facilities that are heavily dependent upon natural gas and are thus heavily impacted by natural gas price swings. Because the nitrogen fertilizer plant uses pet coke, we have a significant cost advantage over other North American natural gas-based fertilizer producers. This cost advantage is sustainable at natural gas prices as low as $2.50 per MMBtu. Natural gas sold at an average price of $7.12 per MMBtu in the United States in 2007. Average yearly natural gas prices have exceeded $2.50 per MMBtu since 2000, although average prices were lower in prior years. See “Industry Overview — Fertilizer Pricing Trends”. Natural gas prices are cyclical and volatile and may decline at any time. See “Risk Factors — Risks Related to the Nitrogen Fertilizer Business — Natural gas prices affect the price of the nitrogen fertilizers that the nitrogen fertilizer business sells. Any decline in natural gas prices could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions”. CVR Energy’s adjacent refinery has supplied on average more than 75% of our pet coke needs during the last four years.

Strategic Location with Transportation Advantage. The nitrogen fertilizer business believes that selling products to customers in close proximity to the UAN plant and reducing transportation costs are keys to maintaining its profitability. Due to the plant’s favorable location relative to end users and high product demand relative to production volume all of the product shipments are targeted to freight advantaged destinations located in the U.S. farm belt. The available ammonia production at the nitrogen fertilizer plant is small and easily sold into truck and rail delivery points. The products leave the plant either in trucks for direct shipment to customers or in railcars for principally Union Pacific Railroad destinations. The nitrogen fertilizer business does not incur any intermediate transfer, storage, barge freight or pipeline freight charges. Consequently, because these costs are not incurred, we estimate that the plant enjoys a distribution cost advantage over those competitors who are U.S. Gulf Coast ammonia and UAN importers, assuming in each case freight rates and pipeline tariffs for U.S. Gulf Coast importers as recently in effect.

On-Stream Factor. The on-stream factor is a measure of how long the units comprising our nitrogen fertilizer facility have been operational over a given period. We expect that efficiency of the nitrogen fertilizer plant will continue to improve with operator training, replacement of unreliable equipment, and reduced dependence on contract maintenance.


	Year Ended December 31,
	2003			2004(1)			2005			2006(1)			2007(1)

Gasifier		90.1	%		92.4	%		98.1	%		92.5	%		90.0	%
Ammonia		89.6	%		79.9	%		96.7	%		89.3	%		87.7	%
UAN		81.6	%		83.3	%		94.3	%		88.9	%		78.7	%

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(1)		On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the nitrogen fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors in 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN, and (ii) the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN.

Raw Material Supply

The nitrogen fertilizer facility’s primary input is pet coke. During the past four years, more than 75% of the nitrogen fertilizer facility’s pet coke requirements on average were supplied by our adjacent oil refinery. Historically the nitrogen fertilizer business has obtained the remainder of its pet coke from third parties such as other midwestern refineries or pet coke brokers at spot prices. If necessary, the gasifier can also operate on low grade coal as an alternative, which provides an additional raw material source. There are significant supplies of low grade coal within a60-mile radius of the nitrogen fertilizer plant.

Pet coke is produced as a by-product of our refinery’s coker unit process, which is one step in refining crude oil into gasoline, diesel and jet fuel. In order to refine heavy or sour crude oil, which is lower in cost and more prevalent than higher quality crude, refiners use coker units, which help to reduce the sulfur content in fuels refined from heavy or sour crude oil. In North America, the shift from refining dwindling reserves of sweet crude oil to more readily available heavy and sour crude (which can be obtained from, among other places, the Canadian oil sands) will result in increased pet coke production. With $26.6 billion in coker unit projects planned at North American refineries as of November 2007, pet coke production is expected to increase significantly in the future.

The nitrogen fertilizer plant is located in Coffeyville, Kansas, which is part of the Midwest coke market. The Midwest coke market is not subject to the same level of pet coke price variability as is the U.S. Gulf Coast coke market, due mainly to more stable transportation costs. Transportation costs have gone up substantially in both the Atlantic and Pacific sectors. Given the fact that the majority of the nitrogen fertilizer business’ suppliers are located in the Midwest, its geographic location gives it (and its similarly located competitors) a significant freight cost advantage over its U.S. Gulf Coast market competitors. The Midwest Green Coke (Chicago Area, FOB Source) annual average price over the last three years has ranged from $24.50 per ton to $27.00. The U.S. Gulf Coast market annual average price during the same period has ranged from $21.29 per ton to $49.83. Furthermore, Sinclair Tulsa Refining, located in Oklahoma, has announced a coker expansion project, and Frontier in El Dorado, Kansas has a coker expansion project under construction. These new refineries should help to further stabilize the Midwest coke market.

The Linde 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. The nitrogen fertilizer business provides and pays 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 $25.0 million in case of any interruption in the supply of oxygen from Linde from a covered peril. The agreement with Linde expires in 2020. The agreement also provides that if our requirements for liquid or gaseous oxygen, liquid or gaseous nitrogen or clean dry air exceed specified instantaneous flow rates by at least 10%, we can solicit bids from Linde and third parties to supply our incremental product needs. We are required to provide notice to Linde of the approximate quantity of excess product that we will need and the approximate date by which we will need it; we and Linde will then jointly develop a request for proposal for soliciting bids from third parties and Linde. The bidding procedures may be limited under specified circumstances.

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The nitrogen fertilizer business importsstart-up steam for the fertilizer plant from our adjacent oil refinery, and then exports steam back to the oil refinery once all of its units are in service. Monthly charges and credits are booked with steam valued at the gas price for the month. We have entered into a feedstock and shared services agreement with the Partnership which regulates, among other things, the import and export ofstart-up steam between the refinery and the nitrogen fertilizer plant.

Production Process

The nitrogen fertilizer plant was built in 2000 with two separate gasifiers to provide reliability. It uses a gasification process licensed from General Electric to convert pet coke into high purity hydrogen for subsequent conversion into ammonia. 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. A majority of the ammonia is converted to approximately 2,000 tons per day of UAN. Typically 0.41 tons of ammonia are required to produce one ton of UAN.

Pet coke is first ground and blended with water and a fluxant (a mixture of fly ash and sand) to form a slurry that is then pumped into the partial oxidation gasifier. The slurry is then contacted with oxygen from an air separation unit, 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.

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The following is an illustrative Nitrogen Fertilizer Plant Process Flow Chart:

The nitrogen fertilizer business schedules and provides routine maintenance to its critical equipment using its own maintenance technicians. Pursuant to a Technical Services Agreement with General Electric, which licenses the gasification technology to the nitrogen fertilizer business, General Electric experts provide technical advice and technological updates from their ongoing research as well as other licensees’ operating experiences.

The pet coke gasification process is licensed from General Electric pursuant to a license agreement that was fully paid up as of June 1, 2007. The license grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions. The license is important because it allows the nitrogen fertilizer facility to operate at a low cost compared to facilities which rely on natural gas.

Distribution, Sales and Marketing

The primary geographic markets for the fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas. Ammonia products are marketed to industrial and agricultural customers and UAN products are marketed to agricultural customers. The direct application agricultural demand from the 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 afreight-on-board basis, and freight is normally arranged by the customer. The nitrogen fertilizer business also owns and leases a fleet of railcars. It also negotiates with distributors that have their own leased railcars to utilize these assets to deliver products. The nitrogen fertilizer business owns all of the truck and rail loading equipment at its facility. It operates two truck loading and eight rail loading racks for each of ammonia and UAN.

The nitrogen fertilizer business markets agricultural products to destinations that produce the best margins for the business. These markets are primarily located on the Union Pacific railroad or destinations which can be supplied by truck. By securing this business directly, the nitrogen fertilizer business reduces its dependence on distributors serving the same customer base, which enables it to capture a larger margin and allows it to better control its product distribution. Most of the agricultural sales are made on a competitive spot basis. The nitrogen fertilizer business also offers products on a

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prepay basis for in-season demand. The heavy in-season demand periods are spring and fall in the corn belt and summer in the wheat belt. The corn belt is the primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. The wheat belt is the primary wheat producing region of the United States, which includes Kansas, North Dakota, Oklahoma, South Dakota and Texas. Some of the industrial sales are spot sales, but most are on annual or multiyear contracts. Industrial demand for ammonia provides consistent sales and allows the nitrogen fertilizer business to better manage inventory control and generate consistent cash flow.

Customers

The nitrogen fertilizer business sells ammonia to agricultural and industrial customers. It sells approximately 80% of the ammonia it produces to agricultural customers, in the mid-continent area between North Texas and Canada, and approximately 20% to industrial customers. Agricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., ConAgra Fertilizer, Interchem, and CHS, Inc. Industrial customers include Tessenderlo Kerley, Inc. and National Cooperative Refinery Association. The nitrogen fertilizer business sells UAN products to retailers and distributors. Given the nature of its business, and consistent with industry practice, the nitrogen fertilizer business does not have long-term minimum purchase contracts with any of its customers.

For the years ended December 31, 2005, 2006 and 2007 and the ~~three~~six months ended ~~March 31,~~June 30, 2008, the top five ammonia customers in the aggregate represented 55.2%, 51.9%, 62.1% and ~~68.4%~~69.9% of the nitrogen fertilizer business’ ammonia sales, respectively, and the top five UAN customers in the aggregate represented 43.1%, 30.0%, 38.7% and ~~42.4%~~39.9% of its UAN sales, respectively. During the year ended December 31, 2005, Brandt Consolidated Inc. and MFA accounted for 23.3% and 13.6% of the nitrogen fertilizer business’ ammonia sales, respectively, and CHS Inc. and ConAgra Fertilizer accounted for 14.7% and 12.7% of its UAN sales, respectively. During the year ended December 31, 2006, Brandt Consolidated Inc. and MFA accounted for 22.2% and 13.1% of the nitrogen fertilizer business’ ammonia sales, respectively, and ConAgra Fertilizer and CHS Inc. accounted for 8.4% and 6.8% of its UAN sales, respectively. During the year ended December 31, 2007, Brandt Consolidated Inc., MFA and ConAgra Fertilizer accounted for 17.4%, 15.0% and 14.4% of the nitrogen fertilizer business’ ammonia sales, respectively, and ConAgra Fertilizer accounted for 18.7% of its UAN sales. During the ~~three~~six months ended ~~March 31,~~June 30, 2008, Brandt Consolidated Inc. ConAgra Fertilizer and ~~National Cooperative Refinery Association~~Tessenderlo Kerley Inc. accounted for ~~32.3%~~33.4%, 11.6% and ~~9.6%~~10.4% of the nitrogen fertilizer business’ ammonia sales, respectively, and ConAgra Fertilizer accounted for ~~11.1%~~14.9% of its UAN sales.

Competition

Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. The nitrogen fertilizer plant maintains a large fleet of rail cars and seasonally adjusts inventory to enhance its manufacturing and distribution operations.

Domestic competition, mainly from regional cooperatives and integrated multinational fertilizer companies, is intense due to customers’ sophisticated buying tendencies and production strategies that focus on cost and service. Also, foreign competition exists from producers of fertilizer products manufactured in countries with lower cost natural gas supplies. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments. The nitrogen fertilizer business’ major competitors include Koch Nitrogen, PCS, Terra and CF Industries, all of which produce more UAN than the nitrogen fertilizer business does.

The 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.

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Based on Blue Johnson data regarding total U.S. demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant’s UAN production in 2007 represented approximately 4.5% of the total U.S. demand and that the net ammonia produced and marketed at Coffeyville represents less than 1% of the total U.S. demand.

Seasonality

Because the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, the nitrogen fertilizer business typically generates greater net sales 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, farmers’ current liquidity, soil conditions, weather patterns and the types of crops planted.

Environmental Matters

The petroleum and nitrogen fertilizer businesses are subject to extensive and frequently changing federal, state and local laws and regulations relating to the protection of the environment. These laws, their underlying regulatory requirements and the enforcement thereof impact our petroleum and nitrogen fertilizer businesses by imposing:


	•	restrictions on operationsand/or the need to install enhanced or additional controls;

	•	the need to obtain and comply with permits, licenses 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 manufactured and marketed by our petroleum and nitrogen fertilizer businesses, primarily gasoline, diesel fuel, UAN and ammonia.

The petroleum refining industry is subject to frequent public and governmental scrutiny of its environmental compliance. The laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal and state agencies. The ultimate impact 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 (the “RCRA”), the federal Clean Water Act and the federal Clean Air Act have not yet been finalized, are frequently undergoing governmental or judicial review or are being revised. These regulations and other new hazardous or solid waste, air or water quality standards or stricter fuel regulations could result in increased capital, operating and compliance costs.

The principal environmental risks associated with our petroleum and nitrogen fertilizer businesses 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. For a discussion of the environmental impact of the 2007 flood and crude oil discharge, see ~~“— Flood~~“Flood and Crude Oil Discharge — Crude Oil Discharge” and ~~“— Flood~~“Flood and Crude Oil Discharge — EPA Administrative Order on Consent.”

The Federal Clean Air Act

The federal Clean Air Act and its implementing regulations as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air affect our petroleum operations and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through federal and state air permitting requirementsand/or emission control requirements relating to specific

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air pollutants. The federal Clean Air Act indirectly affects our petroleum operations and the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide (“SO₂”), volatile organic compounds, nitrogen oxides and other compounds including those emitted by mobile sources, which are direct or indirect users of our products.

Some or all of the standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of standards, may require the installation of controls or changes to our petroleum operations or the nitrogen fertilizer facilities in order to comply. If new controls or changes to operations are needed, the costs could be significant. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to complyand/or permit our refinery to produce products that meet applicable requirements.

Air Emissions. The regulation of air emissions under the federal Clean Air Act requires us to obtain various construction and 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 various general and specific source standards under the National Emission Standard for Hazardous Air Pollutants (“NESHAP”), New Source Performance Standards and New Source Review. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations.

In March 2004, we entered into a Consent Decree with the U.S. Environmental Protection Agency (the “EPA”) and the Kansas Department of Health and Environment (the “KDHE”) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland’s prior operation of our oil refinery. 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 seek 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 began adding catalyst to reduce oxides of nitrogen (“NOx”) in 2008. 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 completed 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 $41 million, of which approximately $35 million is expected to be capital expenditures and which does not include the cleanup obligations.

Over the course of the last several years, the EPA has embarked on a National Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues: New Source Review, flaring, Leak Detection and Repair, and 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. The EPA has indicated that it will seek all refiners to enter into “global settlements” pertaining to all “marquee” issues. Our current Consent Decree covers some, but not all, of the “marquee” issues. To the extent that we were to agree to enter into a “global settlement,” we believe our incremental capital exposure would be limited primarily to the retrofit and replacement of certain existing heaters and boilers over a five to seven year timeframe. We also would incur additional operating expenses to enhance our

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flaring and leak detection and control programs. In addition, consistent with other refiners that have entered into “global settlements,” we may be required to pay a civil penalty.

Title V 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 nitrogen fertilizer plant has amended its Title V permit application to contain all terms and conditions imposed under its new Prevention of Significant Deterioration (“PSD”) permit and all other air permitsand/or approvals in place. We do not anticipate significant cost or difficulty in obtaining the Title V operating air permit for the nitrogen fertilizer plant. We believe that we hold all material air permits required to operate the Phillipsburg Terminal and our crude oil transportation company’s facilities.

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 petroleum operations and the nitrogen fertilizer business periodically experience releases of hazardous substances and extremely hazardous substances that could cause our petroleum businessand/or the nitrogen fertilizer business to become the subject of a government enforcement action or third-party claims.

The nitrogen fertilizer facility experienced an ammonia release as a result of a malfunction in August 2007 and reported the excess ammonia emissions to the EPA and KDHE. The EPA has investigated the release and has requested additional data. Our incident investigation related to the release indicates that the malfunction could not have been reasonably anticipated or avoided and we have forwarded our results to the EPA.

As a result of an inspection by OSHA following the August 2007 ammonia release OSHA issued citations against both the nitrogen fertilizer facility and the refinery seeking penalties totaling $163,000. We have agreed to settle all allegations as a result of this incident with payment of a $163,000 penalty and review and, if necessary, implement improvements in general health and safety programs at each facility, which may include integrating the plant alarm and notification systems.

Fuel Regulations

Tier II, Low Sulfur Fuels. In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule for all passenger vehicles, establishing standards for sulfur content in gasoline. 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. Such compliant gasoline is referred to as Ultra Low Sulfur Gasoline (“ULSG”). Phase-in of these requirements began during 2004. In addition, in January 2001, the 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. The 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. Such compliant diesel is referred to as Ultra Low Sulfur Diesel (“ULSD”). Our production of ULSG and ULSD made us eligible for significant tax benefits in 2007, and we expect to be eligible for significant tax benefits in 2008 as well.

Modifications have been and will continue to be required at our refinery as a result of the Tier II gasoline and low sulfur diesel standards. In February 2004 the EPA granted us approval under a “hardship waiver” that defers meeting final low sulfur Tier II gasoline standards until January 1, 2011 and deferred meeting low sulfur highway diesel requirements until January 1, 2007. We completed the construction and startup phase of our Ultra Low Sulfur Diesel Hydrodesulfurization unit in late 2006 in accordance with the conditions of the “hardship waiver.” We are currently continuing our phased

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construction and startup of projects related to meeting our compliance date with ULSG standards and may agree to meet these standards one year early as described below. Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately ~~$68~~$70 million between 2008 and 2010. Changes in equipment or construction costs could require significantly greater expenditures.

In 2007, as a result of the flood, our refinery exceeded the required average gasoline sulfur standard mandated by the hardship waiver. We are re-negotiating provisions of the hardship waiver and have agreed in principal to meet the final low sulfur Tier II gasoline standards by January 1, 2010 (one year earlier than required under the hardship waiver) in consideration for the EPA’s agreement not to seek a penalty for the 2007 sulfur exceedance and higher gasoline sulfur limits for 2008 and 2009.

Greenhouse Gas Emissions

The United States Congress has considered various proposals to reduce greenhouse gas emissions, but none have become law, and presently, there are no federal mandatory greenhouse gas emissions requirements. While it is probable that Congress will adopt some form of federal mandatory greenhouse gas emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time. In the absence of existing federal regulations, a number of states have adopted regional greenhouse gas initiatives to reduce CO₂ and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas (where our refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Accord, which calls for the development of acap-and-trade system to control greenhouse gas emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and the timing and specific requirements of any such laws or regulations in Kansas are uncertain at this time.

In 2007, the U.S. Supreme Court decided that CO₂ is an air pollutant under the federal Clean Air Act for the purposes of vehicle emissions. Similar lawsuits have been filed seeking to require the EPA to regulate CO₂ emissions from stationary sources, such as our refinery and the fertilizer plant, under the federal Clean Air Act. Our refinery and the nitrogen fertilizer plant produce significant amounts of CO₂ that are vented into the atmosphere. If the EPA regulates CO₂ emissions from facilities such as ours, we may have to apply for additional permits, install additional controls to reduce CO₂ emissions or take other as yet unknown steps to comply with these potential regulations. For example, we may have to purchase CO₂ emission reduction credits to reduce our current emissions of CO₂ or to offset increases in CO₂ emissions associated with expansions of our operations.

Compliance with any future legislation or regulation of greenhouse gas emissions, if it occurs, may result in increased compliance and operating costs and may have a material adverse effect on our results of operations, financial condition, and the ability of the nitrogen fertilizer business to make distributions. In anticipation of the potential legislation or regulation of greenhouse gas emissions, the nitrogen fertilizer business is looking into initiatives to reduce greenhouse gas emissions, particularly CO₂, and is working with a company involved in CO₂ capture and storage systems to try to develop plans whereby the nitrogen fertilizer business may, in the future, either sell approximately 850,000 tons per year of high purity CO₂ produced by the nitrogen fertilizer plant to oil and gas exploration and production companies to enhance oil recovery or pursue an economic means of geologically sequestering such CO₂. This project is currently in development, but, if completed, is expected to include either the direct sale of CO₂ or the sale of verified emission reduction credits should the credits accrete value in the future due to the implementation of mandatory emissions caps for CO₂.

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The Clean Water Act

The federal Clean Water Act of 1972 affects our petroleum operations and the nitrogen fertilizer business by regulating the treatment of wastewater and imposing restrictions on effluent discharges 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. Our petroleum business maintains numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the federal Clean Water Act and has implemented internal programs to oversee our compliance efforts. Our nitrogen fertilizer facility operates under pretreatment requirements and has a permit to discharge our process wastewater to the local publicly owned treatment works.

All of our facilities are subject to Spill Prevention, Control and Countermeasures (“SPCC”) requirements under the Clean Water Act. In 2004, certain requirements of the rule were extended, and additional modifications are expected. When the modifications to the SPCC rule become final, we may be required to make capital expenditures in order to comply with the modified rule; however, we do not anticipate that any such costs will be significant.

In addition, we are regulated under the Oil Pollution Act of 1990 (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 (“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 ofon-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 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 the EPA and KDHE requires us to complete all activities in accordance with federal and state rules and to maintain financial assurance (e.g., a bond or letter of credit) for the costs of doing so. See “— Financial ~~Assurance,”~~Assurance” below.

The anticipated remediation costs through 2011 were estimated, as of ~~March 31,~~June 30, 2008, to be as follows (in millions):


							Total
	Site				Total O&M		Estimated
	Investigation				Costs		Costs
Facility	Costs		Capital Costs		Through 2011		Through 2011

Coffeyville Oil Refinery	$	0.3	$	—	$	1.1	$	1.4
Phillipsburg Terminal		0.3		—		1.9		2.2

Total Estimated Costs	$	0.6	$	—	$	3.0	$	3.6

These estimates are based on current information and could go up or down as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2008, we will spend between $5.8 million and $6.3 million to remedy impacts from past manufacturing activity at the 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.

Financial Assurance. We were required in the Consent Decree to establish $15.0 million in financial assurance to cover the projected cleanup costs under the 1994 and 1996 EPA administrative orders described above, in the event we failed to fulfill ourclean-up obligations. In accordance with the Consent Decree, this financial assurance is partially secured by a bond posted by Original Predecessor, Farmland. We are replacing the financial assurance currently provided by Farmland on a quarterly basis and, so far, have replaced approximately $4.5 million. At this point, it is not clear what the amount of financial assurance will be when replaced. Although it may be significant, we do not expect it will be more than $15.0 million.

Environmental Insurance. We have entered into environmental insurance policies as part of our overall risk management strategy. Our primary pollution legal liability policy provides us with an aggregate limit of $25.0 million subject to a $5.0 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 a45-day waiting period. Our excess pollution legal liability policies provide us with up to an additional $50.0 million of aggregate limit. The excess pollution legal liability policies may not provide coverage until the $25.0 million of underlying limit available in the primary pollution legal liability policy has been exhausted. We also have a financial assurance policy linked to our pollution legal liability 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 refinery and the Phillipsburg terminal. Each of these policies contains substantial exclusions; as such, there can be no assurance that we will have coverage for all or any particular liabilities. For a discussion of our insurance policies that relate to coverage for the 2007 flood and crude oil discharge, see ~~“— Flood~~“Flood and Crude Oil Discharge — Insurance.”

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Environmental Remediation

Under the Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, retroactive and 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 and toxicity 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, including soil and water contamination, personal injury or property damage allegedly caused by hazardous substances that 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, Health and Security Matters

We operate a comprehensive safety, health and security program, involving the active participation of employees at all levels of the organization. We measure our success in the health and safety area primarily through the use of injury frequency rates administered by OSHA. In 2007, our oil refinery experienced a 75% reduction in injury frequency rates and the nitrogen fertilizer plant experienced a 81% reduction in such rate as compared to the average of the previous three 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, 2007, we had a recordable injury rate of 0.50 in our petroleum business and 0.93 in the nitrogen fertilizer business, which did not have a single lost-time accident. Our recordable injury rate for all business units was 0.28 for the year ended December 31, 2007, and ~~0.57~~1.15 for the ~~quarter~~twelve months ended ~~March 31,~~June 30, 2008. In 2006, our refinery achieved one year worked without a lost-time accident, which based on available records, had never been achieved in the 100 year history of the facility. In March 2007 our petroleum business achieved a milestone after operating for 1,000,000 consecutive man hours without a lost-time accident. For the year ended December 31, 2007, our nitrogen fertilizer business did not have a single lost-time accident. 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 (“PSM”) program. This program is designed to address all facets associated with OSHA guidelines for developing and maintaining a PSM program. We will continue to audit our programs and consider improvements in our management systems and equipment.

We have evaluated and continue to implement improvements at our refinery’s process units, process pumping and piping systems and emergency isolation valves for control of process flows. We currently estimate the costs for implementing any recommended improvements to be between $7 million and $9 million over a period of four years. These improvements, if warranted, would reduce the risk of releases, spills, discharges, leaks, accidents, fires or other events and minimize the

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potential effects thereof. We are currently completing thestart-up of the final additions of a new $27 million refinery flare system that replaced any remaining atmospheric sumps in our refinery. We have assessed the potential impacts on building occupancy caused by the location and design of our refinery and fertilizer plant control rooms and operator shelters. We have relocated non-essential personnel and contractors away from the process areas and are currently constructing and installing permanent blast-proof operator control rooms and outside shelters. We expect the costs to upgrade or relocate these areas to be between $4 million and $6 million over the next two to five years.

In 2007, OSHA began PSM inspections of all refineries under its jurisdiction as part of its National Emphasis Program (the “NEP”) following OSHA’s investigation of PSM issues relating to the multiple fatality explosion and fire at the BP Texas City facility in 2005. Completed NEP inspections have resulted in OSHA levying significant fines and penalties against most of the refineries inspected to date. At this time, our refinery has not been inspected in connection with OSHA’s NEP program. Although we believe that our PSM program is in substantial compliance with OSHA PSM regulations, an OSHA NEP inspection could result in the imposition of significant fines and penalties as well as significant additional capital expenditures related to PSM.

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 haveon-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.

Security. We have a comprehensive security program to protect our refinery and the nitrogen fertilizer facility from unauthorized entry and exit and potential acts of terrorism. Recent changes in the U.S. Department of Homeland Security rules and requirements may require enhancements and improvements to our current program.

Community Advisory Panel. We have developed and continue to support ongoing discussions with the community to share information about our operations and future plans. Our community advisory panel includes wide representation of residents, business owners and local elected representatives for the city and county.

Employees

As of ~~March 31,~~June 30, 2008, ~~455~~471 employees were employed in our petroleum business, ~~110~~113 were employed by the nitrogen fertilizer business and 4950 employees were employed at our offices in Sugar Land, Texas and Kansas City, Kansas.

We entered into collective bargaining agreements which, as of ~~March 31,~~June 30, 2008, covered approximately ~~42%~~40% of our employees (all of whom work in our petroleum business) with the Metal Trades Union and the United Steelworkers of America. The collective bargaining agreements expire in March 2009. We believe that our relationship with our employees is good.

Prior to the consummation of our initial public offering, we entered into a services agreement with the Partnership and the managing general partner of the Partnership pursuant to which we agreed to provide certain management and other services to the Partnership, the managing general partner of the Partnership, and the nitrogen fertilizer business. The services we provide under the agreement include the following services, among others:


	•	services by our employees as the Partnership’s corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve the Partnership on a shared, part-time basis only, unless we and the Partnership agree otherwise;

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	•	administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs;

	•	management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business;

	•	recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions;

	•	managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice;

	•	recommending the payment of distributions; and

	•	managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time.

Personnel performing the actual day-to-day business and operations of the Partnership at the plant level are employed directly by the Partnership and its subsidiaries, which bear all personnel costs for these employees. We pay all compensation and benefits for our executive officers, including executive officers who perform services for the Partnership, and we are reimbursed by the managing general partner of the Partnership for a pro rata portion of such compensation and benefits based on the percentage of time each officer works for the Partnership. For more information on this services agreement, see “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.”

Properties

The following table contains certain information regarding our principal properties


Location	Acres	Own/Lease		Use

Coffeyville, KS	440		Own	Oil refinery, fertilizer 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	185		Own	Crude oil storage
Cowley County, KS (Hooser Station)	80		Own	Crude oil storage
Holdrege, NE	7		Own	Crude oil storage
Stockton, KS	6		Own	Crude oil storage
Sugar Land, TX	22,000 (square feet)		Lease	Office space
Kansas City, KS	18,400 (square feet)		Lease	Office space

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 $515,000 annually, plus operating expenses, increasing to approximately $550,000 in 2009. The lease expires in 2011. Rent under our lease for the Kansas City office space is approximately $268,000 annually, plus a portion of operating expenses and taxes. 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.

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In January 2008, we transferred ownership of certain parcels of land, including land that the fertilizer plant is situated on, to the Partnership so that the Partnership would be able to operate the fertilizer plant on its own land. Additionally, in October 2007, we entered into a new cross easement agreement with the Partnership so that both we and the Partnership will be able to access and utilize each other’s land in certain circumstances in order to operate our respective businesses in a manner to provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other parties’ property. For more information on this cross-easement agreement, see “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.”

As of December 31, 2007, we had storage capacity for 769,000 barrels of gasoline, 1,068,000 barrels of distillates, 928,000 barrels of intermediates and 3,364,000 barrels of crude oil. The crude oil storage consisted of 674,000 barrels of refinery storage capacity, 520,000 barrels of field storage capacity and 2,170,000 barrels of storage at Cushing, Oklahoma.

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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FLOOD AND CRUDE OIL DISCHARGE

Overview

During the weekend of June 30, 2007, torrential rains in southeastern Kansas caused the Verdigris River to overflow its banks and flood the city of Coffeyville. The river crested more than ten feet above flood stage, setting a new record for the river. Approximately 2,000 citizens and hundreds of homes throughout the city of Coffeyville were affected. Our refinery and the nitrogen fertilizer plant, both of which are located in close proximity to the Verdigris River, were severely flooded and were forced to conduct emergency shutdowns and evacuations. The majority of the refinery’s process units were under four to six feet of water and portions of the refinery’s tank farms and wastewater treatment area were covered with eight to ten feet of water. As a result, the refinery and nitrogen fertilizer facilities sustained major damage and required extensive repairs.

Property Damage and Lost Earnings

The refinery sustained damage to a large number of pumps, motors, tanks, control rooms and other buildings, electrical equipment and electronic controls, and required significantclean-up in the areas surrounding the water and wastewater treatment plants. We hired nearly 1,000 extra contract workers to help repair and replace damaged equipment. The refinery started operating its reformer on August 6, 2007 and began to charge crude oil to the facility on August 9, 2007. Substantially all of the refinery’s units were in operation by August 20, 2007.

The nitrogen fertilizer facility, situated on slightly higher ground, sustained less damage than the refinery. Bringing the nitrogen fertilizer plant back on line involved replacing or repairing 30% of all electric drives, repairing 60% of the plant’s motor control centers, refurbishing 100% of the plant’s distributive control systems and programmable logic controllers and repairing the main control room. The nitrogen fertilizer facility initiated startup at its production facility on July 13, 2007.

As of ~~March 31,~~June 30, 2008, total third party costs to repair the refinery and fertilizer facilities were approximately ~~$82.5~~$76.9 million and ~~$4.0~~$4.3 million, respectively. ~~In addition, we currently estimate that approximately $2.1 million in third party costs related to the repair of flood damaged property will be recorded in future periods.~~ We are currently uncertain how much of these amounts we will be able to recover through insurance. See “— Insurance.”

Crude Oil Discharge

Because the Verdigris River rose so rapidly during the flood, much faster than predicted, our employees had to shut down and secure the refinery in six to seven hours, rather than the 24 hours typically needed for such an effort. Despite our efforts to secure the refinery prior to its evacuation as a result of the flood, we estimate that 1,919 barrels (80,600 gallons) of crude oil and 226 barrels of crude oil fractions were discharged from our refinery into the Verdigris River flood waters beginning on or about July 1, 2007. In particular, crude oil and its fractions were released from refinery storage tanks and the refinery sewer system. Crude oil was carried by floodwaters downstream from our refinery and into residential and commercial areas.

In response to the crude oil discharge, on July 1, 2007 we established an incident command center and assembled a team of environmental consultants and oil spill response contractors to manage our response to the crude oil discharge.


	•	The O’BRIEN’S Group managed the overall process, including containment and recovery. The O’BRIEN’S Group is the largest provider of emergency preparedness and crisis management services to the energy and internal shipping industries.

	•	United States Environmental Services, LLC provided operations support. This firm is a full-service environmental contracting company specializing in environmental emergency response,

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		in-plant industrial services, contaminated site remediation, chemical/biological terrorism response, safety training and industrial hygiene.

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	•	The Center for Toxicology and Environmental Health oversaw sampling, analysis and reporting for the operation. This firm specializes in toxicology, risk assessment, industrial hygiene, occupational health and response to emergencies involving the release or threat of release of chemicals.

On July 2, 2007, the EPA dispatched additional oil spill response contractors to the site with the EPA’s mobile command post to monitor and coordinate pollution assessments related to the flooding and the crude oil discharge.

Beginning on or about July 2, 2007, the EPA’s oil spill response contractors and we began jointly conducting daily aerial overflights of the Coffeyville area and our refinery. On or about July 2, 2007, (a) crude oil from the refinery was observed to be in the flood waters surrounding the above-ground storage tanks located at our refinery and (b) oil was observed in the Verdigris River and in flood waters that had inundated a portion of the city of Coffeyville.

Representatives from the KDHE and the Oklahoma Department of Environmental Quality have also been heavily involved in the response to the oil discharge.

EPA Administrative Order on Consent

On July 10, 2007, we entered into an administrative order on consent (the “Consent Order”) with the EPA. As set forth in the Consent Order, the EPA concluded that the discharge of oil from our refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, we agreed to perform specified remedial actions to respond to the discharge of crude oil from our refinery.

Under the Consent Order, within 90 days after the completion of such remedial action, we will submit to the EPA for review and approval a final report summarizing the actions taken to comply with the Consent Order. We have worked with the EPA throughout the recovery process and we could be required to reimburse the EPA’s costs under the federal Oil Pollution Act. Except as otherwise set forth in the Consent Order, the Consent Order does not limit the EPA’s rights to seek other legal, equitable or administrative relief or action as it deems appropriate and necessary against us or from requiring us to perform additional activities pursuant to applicable law. Among other things, the EPA reserved the right to assess administrative penalties against us and/or to seek civil penalties against us. In addition, the Consent Order states that it is not a satisfaction of or discharge from any claim or cause of action against us or any person for any liability we or such person may have under statutes or the common law, including any claims of the United States, for penalties, costs and damages.

We ~~expect to~~ substantially ~~complete~~completed remediation of the contamination caused by the crude oil discharge byin July ~~31,~~ 2008 and ~~anticipate~~expect any remaining minor remedial actions ~~thereafter.~~to be completed by December 31, 2008. We are currently preparing a final report to the EPA to satisfy the final requirement of the Consent Order. Total ~~net~~gross costs recorded as of ~~March 31,~~June 30, 2008 associated with remediation efforts and third party property damage incurred by the crude oil discharge are approximately ~~$27.3 million. This amount is net of anticipated insurance recoveries of $21.4~~$52.3 million. In 2007, the Company received insurance proceeds of $10.0 million under its property insurance policy, $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge and $1.5 million under its builders’ risk policy. In addition, we received $13.0 million from our property insurance carriers in July 2008. These amounts do not include potential fines or penalties which may be imposed by regulatory authorities or costs arising from potential natural resource damages claims (for which we are unable to estimate a range of possible costs at this time) or possible additional damages arising from lawsuits related to the flood.

Property Repurchase Program and Claims for Property Damage

On July 19, 2007 we commenced a program to purchase approximately 330 homes and certain other properties in connection with the flood and the crude oil discharge. We offered to purchase the

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property of approximately 330 residential landowners (with the consent and cooperation of the city of

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Coffeyville) for 110% of their pre-flood appraised value (to be established by appraisal conducted without consideration of the flood), without release or other waiver of any rights by the landowners, and without deduction for the greater harm unquestionably caused to these properties by the flood itself. As of ~~March 31,~~June 30, 2008, 322 of these approximately 330 residential properties are under contract. ~~We estimate that this program will cost~~Total costs recorded to date are approximately ~~$17.5 million, excluding certain costs associated with remediation.~~$14.3 million.

In addition, in early July 2007 we opened a claims center in Coffeyville and established a toll-free number to facilitate the recording and processing of claims for compensation by those who may have incurred property and other damages related to the oil discharge. Staff assisted local residents in filing claims related to the 2007 flood and crude oil discharge. We also offered a toll-free number at the claims call center which was answered 24 hours a day. Call center operators collected property owners’ information and forwarded it to claims adjustors. The claims adjustors contacted property owners to schedule appointments. Operators also directed callers to local, state and federal disaster response agencies for additional assistance. As of the date of this prospectus, we have adjusted most of these claims.

Litigation

As a result of the crude oil discharge, two putative class action lawsuits (one federal and one state) were filed against us and/or our subsidiaries in July 2007. The federal suit, Danny Dunham vs. Coffeyville Resources, LLC, et al., was filed in the United States District Court for the District of Kansas at Wichita (case number 6:07-cv-01186-JTM-DWB). The state suit, Western Plains Alliance, LLC and Western Plains Operations, LLC v. Coffeyville Resources Refining & Marketing, LLC, was filed in the District Court of Montgomery County, Kansas (case number 07CV99I).

Plaintiff’s complaint in the federal suit alleged that the crude oil discharge resulted from our negligent operation of the refinery and that class members suffered unspecified damages, including damages to their personal and real property, diminished property value, lost full use and enjoyment of their property, lost or diminished business income and comprehensive remediation costs. The federal suit sought recovery under the federal Oil Pollution Act, Kansas statutory law imposing a duty of compensation on a party that releases any material detrimental to the soil or waters of Kansas, and the Kansas common law of negligence, trespass and nuisance. This suit was dismissed on November 6, 2007 for lack of subject matter jurisdiction, and no appeal was taken.

The state suit sought class certification under applicable law. The proposed class would have consisted of all persons and entities who own or have owned real property within the “contaminated area,” and all businesses and/or other entities located within the “contaminated area.” The Court conducted an evidentiary hearing on the issue of class certification on October 24 and 25, 2007 and ruled against class certification, leaving only the original two plaintiffs who have agreed, subject to final documentation, to settle their claims and dismiss the state lawsuit.

We recently received 16 notices of claims under the Oil Pollution Act from private claimants in an aggregate amount of approximately $4.4 million. No lawsuits related to these claims have yet been filed.

Insurance

During and after the time of the 2007 flood and crude oil discharge, Coffeyville Resources, LLC was insured under insurance policies that were issued by a variety of insurers and which covered various risks, such as damage to our property, interruption of our business, environmental cleanup

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costs, and potential liability to third parties for bodily injury or property damage. These coverages include the following:


	•	Our primary property damage and business interruption insurance program provided $300 million of coverage for flood-related damage, subject to a deductible of $2.5 million per “occurrence” and a45-day waiting period for business interruption loss. While we believe that

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		property insurance should cover substantially all of the estimated total physical damage to our property, our insurance carriers have cited potential coverage limitations and defenses that might preclude such a result.


	•	Our builders’ risk policy provided coverage for property damage to buildings in the course of construction. Flood-related loss or damage was subject to a $100,000 deductible and sub-limit of $50 million.

	•	Our environmental insurance coverage program provided coverage for bodily injury, property damage, and cleanup costs resulting from new pollution conditions. At the time of the flood, the program included a primary policy with a $25.0 million aggregate limit of liability. This policy was subject to a $1 million self-insured retention. In addition, at the time of the flood we had a $25.0 million excess policy that was triggered by exhaustion of the primary policy. The excess policy covered bodily injury and property damage resulting from new pollution conditions, but did not cover cleanup costs.

	•	Our umbrella and excess liability coverage program provided $100 million of coverage for claims in excess of $5.0 million and other applicable insurance for third-party claims of property damage and bodily injury arising out of the sudden and accidental discharge of pollutants.

Coffeyville Resources, LLC promptly notified its insurers of the flood, the crude oil discharge, and related claims and lawsuits. We are in the process of submitting our claims to, responding to information requests from, and negotiating with the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. Our property insurers have raised a question as to whether our facilities are principally located in “Zone A” which iswas, at the time of the flood, subject to a $10 million insurance limit for flood or “Zone B” which iswas, at the time of the flood, subject to a $300 million insurance limit for flood. We have reached agreement with ~~32.5%~~certain of our property insurers representing approximately 32.5% of our total property coverage for theflood-damaged facilities that our facilities are principally located in Zone B.B and are therefore subject to the $300 million limit for flood. Our remaining property insurers have not, at this time, agreed to this position. In addition, our primary environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup” which is subject to a $10 million sub-limit, rather than “property damage” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While we will vigorously contest the primary carrier’s position, we ~~believe~~contend that if that position were upheld, our umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. ~~Although each~~Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage ~~defenses, we are vigorously pursuing our insurance recovery claims.~~defenses. We filed two lawsuits in the United States District Court for the District of Kansas on July 10, 2008 against certain of our insurance carriers with regard to our insurance coverage for the flood and crude oil discharge. The lawsuits involved the Zone A/Zone B issue and the cleanup/property damage issue described above. We intend to pursue the litigation vigorously.

Our insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs we have incurred relating to the damages and losses suffered. This coverage, however, applies only to losses incurred after a business interruption of 45 days. Because both the refinery and the nitrogen fertilizer plant were restored to operation within this45-day period, a majority of the lost profits incurred because of the flood are unlikely to be paid by our business interruption insurance.

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Financial Impact on Our Results

Total gross costs recorded due to the flood and related crude oil discharge that were included in our statement of operations for the year ended December 31, 2007 were approximately $146.8 million. Of these gross costs, approximately $101.9 million were associated with repair and other matters as a result of the flood damage to our facilities. Included in this cost was $7.6 million of depreciation for temporarily idled facilities, $6.1 million of salaries, $2.2 million of professional fees and $86.0 million

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for other repair and related costs. There were approximately $44.9 million of costs recorded for the year ended December 31, 2007 related to the third party and property damage remediation as a result of the crude oil discharge.

Total gross costs recorded due to the flood and related oil discharge that were included in our statement of operations for the ~~three~~six months ended ~~March 31,~~June 30, 2008 were approximately ~~$7.6~~$6.7 million. Of these gross costs for the three month period ended March 31, 2008, approximately $3.8 million were associated with repair and other matters as a result of the flood damage to our facilities. Included in this cost was $0.3 million of professional fees and $3.5 million for other repair and related costs. There were also $3.8 million of costs recorded related to the third party and property damage remediation as a result of the crude oil discharge. We anticipate that approximately $2.1 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods.

As of ~~March 31,~~June 30, 2008, we had received insurance proceeds of $10.0 million under our property insurance policy, an additional $10.0 million under our environmental policies related to recovery of certain costs associated with the crude oil discharge and $1.5 million under our Builder’s Risk Insurance Policy. In July 2008, we received $13.0 million under our property insurance policy. Although we believe that we will recover substantial additional sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of our claims. The difference between what we ultimately receive under our insurance policies compared to what has been recorded in our financial statements could be material to our financial statements. We could recover substantially less than our full claim.

Below is a summary of the gross cost and reconciliation of the insurance receivable as of ~~March 31,~~June 30, 2008 (in millions):

Total Costs

Total gross costs incurred $ 154.5
Total insurance receivable (107.2 )

Net costs associated with the flood $ 47.3


	Total Costs

Total gross costs incurred	$	153.6
Total insurance receivable		(102.4	)

Net costs associated with the flood	$	51.2

Receivable

Reconciliation

Total insurance receivable $ 107.2
Less insurance proceeds received (21.5 )

Insurance receivable $ 85.7


	Receivable
	Reconciliation

Total insurance receivable	$	102.4
Less insurance proceeds received		(21.5	)

Insurance receivable	$	80.9

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MANAGEMENT

Executive Officers and Directors

The following table sets forth the names, positions and ages of the executive officers and directors of CVR Energy. We also indicate in the biographies below which executive officers and directors of CVR Energy also hold similar positions with the managing general partner of the Partnership. Senior management of CVR Energy manages the Partnership pursuant to the services agreement described under “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.” All of the named executive officers of CVR Energy listed below will devote all of their time to CVR Energy and its wholly-owned subsidiaries, except that certain of them will also devote a portion of their time to the management of the Partnership.


Name	Age		Position

John J. Lipinski		57	Chairman of the Board of Directors, Chief Executive Officer and President
Stanley A. Riemann		57	Chief Operating Officer
James T. Rens		41	Chief Financial Officer and Treasurer
Edmund S. Gross		57	Senior Vice President, General Counsel and Secretary
Daniel J. Daly, Jr.		62	Executive Vice President, Strategy
Robert W. Haugen		50	Executive Vice President, Refining Operations
Wyatt E. Jernigan		56	Executive Vice President, Crude Oil Acquisition and Petroleum Marketing
Kevan A. Vick		54	Executive Vice President and Fertilizer General Manager
Christopher G. Swanberg		50	Vice President, Environmental, Health and Safety
Scott L. Lebovitz		32	Director
Regis B. Lippert		68	Director
George E. Matelich		52	Director
Steve A. Nordaker		61	Director
Stanley de J. Osborne		37	Director
Kenneth A. Pontarelli		37	Director
Mark E. Tomkins		52	Director

John J. Lipinskihas served as our chairman of the board since October 2007, our chief executive officer and president and a member of our board since September 2006, chief executive officer and president of Coffeyville Acquisition LLC since June 2005 and chief executive officer and president of Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC since October 2007. Since October 2007, Mr. Lipinski has also served as the chief executive officer, president and a director of the managing general partner of the Partnership. Mr. Lipinski has over 3536 years of experience in the petroleum refining and nitrogen fertilizer industries. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation, eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation’s refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen-based chemical processing, and lubricant operations, as well as the corporate engineering and construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a Managing Director and Partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski graduated from Stevens Institute of Technology with a Bachelor of Engineering (Chemical) and received a Juris Doctor degree from Rutgers University School of Law.

Stanley A. Riemannhas served as chief operating officer of our company since September 2006, chief operating officer of Coffeyville Acquisition since June 2005, chief operating officer of

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Coffeyville Resources since February 2004 and chief operating officer of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. Since October 2007 Mr. Riemann has also served as the chief operating officer of the managing general partner of the Partnership. Prior to joining our company in February 2004, Mr. Riemann held various positions associated with the Crop Production and Petroleum Energy Division of Farmland for over 29 years, including, most recently, Executive Vice President of Farmland and President of Farmland’s Energy and Crop Nutrient Division. In this capacity, he was directly responsible for managing the petroleum refining operation and all domestic fertilizer operations, which included the Trinidad and Tobago nitrogen fertilizer operations. His leadership also extended to managing Farmland’s interests in SF Phosphates in Rock Springs, Wyoming and Farmland Hydro, L.P., a phosphate production operation in Florida, and managing all company-wide transportation assets and services. Mr. Riemann served as a board member and board chairman on several industry organizations including the Phosphate Potash Institute, the Florida Phosphate Council, and the International Fertilizer Association. He currently serves on the board of The Fertilizer Institute. Mr. Riemann received a B.S. from the University of Nebraska and an M.B.A. from Rockhurst University.

James T. Renshas served as chief financial officer and treasurer of our company since September 2006, chief financial officer and treasurer of Coffeyville Acquisition since June 2005, chief financial officer and treasurer of Coffeyville Resources since February 2004 and chief financial officer and treasurer of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. Since October 2007, Mr. Rens has also served as chief financial officer and treasurer of the managing general partner of the Partnership. 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 over 19 years in various accounting and financial positions associated with the fertilizer and energy industry. Mr. Rens received a B.S. degree in accounting from Central Missouri State University.

Edmund S. Grosshas served as senior vice president, general counsel and secretary of our company since October 2007, senior vice president, general counsel and secretary of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007, vice president, general counsel and secretary of our company since September 2006, secretary of Coffeyville Acquisition since June 2005, and general counsel and secretary of Coffeyville Resources since July 2004. Since October 2007 Mr. Gross has also served as the senior vice president, general counsel, and secretary of the managing general partner of the Partnership. 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 B.A. in history from Tulane University, a J.D. from the University of Kansas and an M.B.A. from the University of Kansas.

Daniel J. Daly, Jr.has been our executive vice president, strategy since December 2007 and was our Senior Vice President, Administration and Controls from September 2006 through December 2007 and our Vice President, Accounting and Administration from June 2005 through August 2006. From December 2004 to June 2005 Mr. Daly was self-employed as a consultant in mergers & acquisitions. From 1978 to 2001 Mr. Daly worked at Coastal Corporation, first as Manager of Transportation and Supply Operations and then as Controller, Refining Division and Vice President and Controller, Refining and Marketing. Following the merger of Coastal with El Paso in 2001, Mr. Daly served as Vice President and Controller of Tosco Corporation from January 2001 to December 2001. Mr. Daly received a B.S. in commerce from St. Louis University.

Robert W. Haugenjoined our business on June 24, 2005 and has served as executive vice president, refining operations at our company since September 2006 and as executive vice

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president — engineering & construction at Coffeyville Resources since June 24, 2005. Since October 2007 Mr. Haugen has also served as executive vice president, refining operations at Coffeyville Acquisition and Coffeyville Acquisition II. 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 midstream/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. Jerniganhas served as executive vice president, crude oil acquisition and petroleum marketing at our company since September 2006 and as executive vice president — crude & feedstocks at Coffeyville Resources since June 24, 2005. Since October 2007 Mr. Jernigan has also served as executive vice president, crude oil acquisition and petroleum marketing at Coffeyville Acquisition and Coffeyville Acquisition II. 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. Vickhas served as executive vice president and fertilizer general manager at our company since September 2006, senior vice president at Coffeyville Resources Nitrogen Fertilizers since February 27, 2004 and executive vice president and fertilizer general manager of Coffeyville Acquisition III since October 2007. Since October 2007 Mr. Vick has also served as executive vice president and fertilizer general manager of the managing general partner of the Partnership. 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 an experienced executive 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, he was general manager of nitrogen manufacturing at Farmland from January 2001 to February 2004. Mr. Vick received a B.S. in chemical engineering from the University of Kansas and is a licensed professional engineer in Kansas, Oklahoma and Iowa.

Christopher G. Swanberghas served as vice president, environmental, health and safety at our company since September 2006, as vice president, environmental, health and safety at Coffeyville Resources since June 2005 and as vice president, environmental, health and safety at Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. Since October 2007 Mr. Swanberg has also served as vice president, environmental, health and safety at the managing general partner of the Partnership. He has served in numerous management positions in the petroleum refining industry such as Manager, Environmental Affairs for the refining and marketing division of Atlantic Richfield Company (ARCO), and Manager, Regulatory and Legislative Affairs for Lyondell-Citgo Refining. Mr. Swanberg’s experience includes technical and management assignments in project, facility and corporate staff positions in all environmental, safety and health areas. Prior to joining Coffeyville Resources, he was vice president of Sage Environmental Consulting, an environmental consulting firm focused on petroleum refining and petrochemicals, from September 2002 to June 2005

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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 M.B.A. from the University of Tulsa.

Scott L. Lebovitzhas been a member of our board since September 2006 and a member of the board of directors of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. He was also a member of the board of directors of Coffeyville Acquisition from June 2005 until October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since October 2007. Mr. Lebovitz is a managing director in the Merchant Banking Division of Goldman, Sachs & Co. Mr. Lebovitz joined Goldman, Sachs & Co. in 1997 and became a managing director in 2007. He is a director of Energy Future Holdings Corp. and Village Voice Media Holdings, LLC. He received his B.S. in commerce from the University of Virginia.

Regis B. Lipperthas been a member of our board since June 2007. He was also a member of the board of directors of Coffeyville Acquisition from June 2007 until October 2007. He is the founder, principal shareholder and a director of INTERCAT, Inc., a specialty chemicals company which primarily develops, manufactures, markets and sells specialty catalysts used in petroleum refining. Mr. Lippert serves as president and chief executive officer of INTERCAT, Inc. and its affiliate companies and is a Managing Director of INTERCAT Europe B.V. Mr. Lippert is also a director of Indo Cat Private Limited, an Indian company which is part of a joint venture between INTERCAT, Inc. and Indian Oil Corporation Limited. Prior to founding INTERCAT, Mr. Lippert served from 1981 to 1985 as President, Chief Executive Officer and a director of Katalistiks, Inc., a manufacturer of fluid cracking catalysts which ultimately became a subsidiary of Union Carbide Corporation. From 1979 to 1981, Mr. Lippert was an Executive Vice President with Catalysts Recovery, Inc. In this capacity he was responsible for developing the joint venture which ultimately formed Katalistiks. From 1963 to 1979, Mr. Lippert was employed by Engelhard Minerals and Chemical Co., where he attained the position of Director of Sales and Marketing/Catalysts. Mr. Lippert attended Carnegie-Mellon University where he studied metallurgy. He is a member of the National Petroleum Refiners Association.

George E. Matelichhas been a member of our board since September 2006, a member of the board of directors of Coffeyville Acquisition since June 2005 and a member of the board of directors of Coffeyville Acquisition III since October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since October 2007. Mr. Matelich has been a managing director of Kelso & Company since 1989. 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 a B.A. in business administration from the University of Puget Sound and an M.B.A. from the Stanford Graduate School of Business. He is a director of Global Geophysical Services, Inc., Shelter Bay Energy Inc. and Waste Services, Inc. He is also a Trustee of the University of Puget Sound and serves on the National Council of the American Prairie Foundation.

Steve A. Nordakerhas been a member of our board since June 2008. He has served as senior vice president, finance of Energy Capital Group Holdings LLC, a development company dedicated to building, owning and operating gasification and IGCC units for the refining, petrochemical and fertilizer industries, since June 2004. Mr. Nordaker has also worked as a financial consultant for various companies in the areas of acquisitions, divestitures, restructuring and financial matters since January 2002. From 1996 through 2001, he was a managing director at J.P. Morgan Securities/JPMorgan Chase Bank in the global chemicals group and global oil & gas group. From 1992 to 1995, he was a managing director in the Chemical Bank worldwide energy, refining and petrochemical group. From 1982 to 1992, Mr. Nordaker served in numerous banking positions in the energy group at Texas Commerce Bank. Mr. Nordaker was Manager of Projects for the Frantz Company, an engineering consulting firm, from 1977 through 1982 and worked as a Chemical Engineer for UOP, Inc. from 1968 through 1977. Mr. Nordaker received a B.S. in chemical engineering from South Dakota School of Mines and Technology and an M.B.A. from the University of Houston.

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Stanley de J. Osbornehas been a member of our board since September 2006, a member of the board of directors of Coffeyville Acquisition since June 2005 and a member of the board of directors of Coffeyville Acquisition III since October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since October 2007. Mr. Osborne was a Vice President of Kelso & Company from 2004 through 2007 and has been a managing director since 2007. 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., Global Geophysical Services, Inc., Karat Acquisition LLC, Shelter Bay Energy Inc. and Traxys S.A.

Kenneth A. Pontarellihas been a member of our board since September 2006 and a member of the board of directors of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. He has also been a director of the managing general partner of the Partnership since October 2007. He also was a member of the board of directors of Coffeyville Acquisition from June 2005 until October 2007. Mr. Pontarelli is a partner 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 CCS, Inc., Cobalt International Energy, L.P., Energy Future Holdings Corp., Knight Holdco LLC, and Kinder Morgan, Inc. He received a B.A. from Syracuse University and an M.B.A. from Harvard Business School.

Mark E. Tomkinshas been a member of our board since January 2007. He also was a member of the board of directors of Coffeyville Acquisition from January 2007 until October 2007. Mr. Tomkins has served as the senior financial officer at several large companies during the past ten years. He was Senior Vice President and Chief Financial Officer of Innovene, a petroleum refining and chemical polymers business and a subsidiary of British Petroleum, from May 2005 to January 2006, when Innovene was sold to a strategic buyer. From January 2001 to May 2005 he was Senior Vice President and Chief Financial Officer of Vulcan Materials Company, a publicly traded construction materials and chemicals company. From August 1998 to January 2001 Mr. Tomkins was Senior Vice President and Chief Financial Officer of Chemtura (formerly ~~GreatLakes~~Great Lakes Chemical Corporation), a publicly traded specialty chemicals company. From July 1996 to August 1998 he worked at Honeywell Corporation as Vice President of Finance and Business Development for its polymers division and as Vice President of Finance and Business Development for its electronic materials division. From November 1990 to July 1996 Mr. Tomkins worked at Monsanto Company in various financial and accounting positions, including Chief Financial Officer of the growth enterprises division from January 1995 to July 1996. Prior to joining Monsanto he worked at Cobra Corporation and as an auditor in private practice. Mr. Tomkins received a B.S. degree in business, with majors in Finance and Management, from Eastern Illinois University and an ~~M.B.A~~M.B.A. from Eastern Illinois University and is a certified public accountant. Mr. Tomkins is a director of W.R. Grace & Co. and Elevance Renewable Sciences, Inc.

Board of Directors

Our board of directors consists of eight 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.

Our board has an audit committee, a compensation committee, a nominating and corporate governance committee and a conflicts committee. Our board of directors has determined that we are a “controlled company” under the rules of the New York Stock Exchange, and, as a result, qualify for, and may rely on, exemptions from certain corporate governance requirements of the New York Stock Exchange. Pursuant to the “controlled company” exception to the board of directors and committee composition requirements, we are exempt from the rules that require that (a) our board of directors be comprised of a majority of “independent directors,” (b) our compensation committee be comprised solely of “independent directors” and (c) our nominating and corporate governance committee be comprised solely of “independent directors” as defined under the rules of the New York Stock Exchange. The controlled company exemption does not modify the independence requirements for

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the audit committee. The Sarbanes-Oxley Act and the New York Stock Exchange rules require that our audit committee be composed entirely of independent directors, except that our audit committee is only required to have a majority of independent directors until October 22, 2008. The audit committee currently has three members, two of which are independent directors. Thus, the composition of our audit committee satisfies the independence requirements of the New York Stock Exchange and the Sarbanes-Oxley Act. Steve A. Nordaker and Mark E. Tomkins are the independent directors currently serving on the audit committee. Our board has affirmatively determined that Messrs. Steve A. Nordaker and Mark E. Tomkins are independent directors under the rules of the SEC and the NYSE. We do not believe that our reliance on the exemption that allows our audit committee to consist only of a majority of independent directors until October 22, 2008 will adversely affect the ability of our audit committee to act independently and to satisfy applicable independence requirements.

Audit Committee. The members of the audit committee are Messrs. Mark Tomkins, Steve A. Nordaker, and Stanley de J. Osborne. Mr. Tomkins is chairman of the audit committee. Our board of directors has determined that Mr. Tomkins qualifies as an “audit committee financial expert.” Our board of directors has also determined that Mr. Nordaker and Mr. Tompkins are “independent directors” as discussed above. The audit committee’s responsibilities are 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. The members of the compensation committee are Messrs. George E. Matelich, Steve A. Nordaker, Kenneth Pontarelli and Mark Tomkins. Mr. George E. Matelich is the chairman of the compensation committee. The principal responsibilities of the compensation committee are 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. A subcommittee of the compensation committee consisting of Messrs. Nordaker and Tomkins will make stock and option awards to the extent deemed necessary or advisable for regulatory purposes. See “Compensation Discussion and Analysis.”

Nominating and Corporate Governance Committee. The members of the nominating and corporate governance committee are Messrs. Scott L. Lebovitz, Stanley de J. Osborne, John J. Lipinski and Regis B. Lippert. Mr. Scott L. Lebovitz is the chairman of the nominating and corporate governance committee. The principal duties of the nominating and corporate governance committee are 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.

Conflicts Committee. The members of the conflicts committee are Messrs. Steve A. Nordaker and Mark Tomkins. The principal duties of the conflicts committee are to determine, in accordance with the conflicts of interests policy adopted by our board of directors, if the resolution of a conflict of interest between CVR Energy and our subsidiaries, on the one hand, and the Partnership, the Partnership’s managing general partner or any subsidiary of the Partnership, on the other hand, is fair and reasonable to us.

Compensation Committee Interlocks and Insider Participation

Our compensation committee is comprised of Messrs. George E. Matelich, Steve A. Nordaker, Kenneth A. Pontarelli and Mark E. Tomkins. Mr. Matelich is a managing director of Kelso & Company and Mr. Pontarelli is a partner managing director in the Merchant Banking Division of Goldman, Sachs & Co. For a description of the Company’s transactions with certain affiliates of Kelso &

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Company and certain affiliates of Goldman, Sachs & Co., see “Certain Relationships and Related Party Transactions — Transactions with the Goldman Sachs Funds and the Kelso Funds” below.

Mr. John J. Lipinski, our chairman of the board and chief executive officer, is also a director of and serves on the compensation committee of INTERCAT, Inc., a privately held company of which Regis B. Lippert, who serves as a director on our board, is the chief executive officer. Otherwise, no interlocking relationship exists between our board or compensation committee and the board of directors or compensation committee of any other company.

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COMPENSATION DISCUSSION AND ANALYSIS

Executive Compensation

Overview

The compensation committee of the board of directors oversees companywide compensation practices and has specifically reviewed, developed and administered executive compensation programs and made recommendations to the board of directors of Coffeyville Acquisition LLC (prior to our initial public offering) and CVR Energy (following our initial public offering) on compensation matters. Messrs. George E. Matelich, Kenneth Pontarelli and John J. Lipinski served as members of Coffeyville Acquisition LLC’s committee during 2006 and prior to our initial public offering. Following our initial public offering, our board of directors established a compensation committee for CVR Energy comprised of Messrs. George E. Matelich (as chairperson), Kenneth Pontarelli, Wesley Clark and Mark Tomkins, which took over the duties of the compensation committee of the board of directors of Coffeyville Acquisition LLC. As of June 2008, Messrs. George E. Matelich (as chairperson), Steve A. Nordaker, Kenneth Pontarelli and Mark Tomkins are the members of our compensation committee. For purposes of this Compensation Discussion and Analysis, the “board of directors” and the “compensation committee” refer to the board of directors and compensation committee of Coffeyville Acquisition LLC prior to our initial public offering and CVR Energy following our initial public offering. The definitions of certain defined terms used in this Compensation Discussion and Analysis, including Phantom Unit Plan I, Phantom Unit Plan II, phantom points, phantom service points, phantom performance points, common units, profits interests, override units, operating units and value units, among others, are contained in the section of this prospectus entitled “Glossary of Selected Terms.”

The executive compensation philosophy of the compensation committee is threefold:


	•	To align the executive officers’ interest with that of the stockholders and stakeholders, which provides long-term economic benefits to the stockholders;

	•	To provide competitive financial incentives in the form of salary, bonuses, and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and

	•	To maintain a compensation program whereby the executive officers, through exceptional performance and equity ownership, will have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders.

The compensation committee reviews and makes recommendations to the board of directors regarding our overall compensation strategy and policies, with the full board of directors having the final authority on compensation matters. The board of directors may from time to time delegate to the compensation committee the authority to take actions on specific compensation matters or with respect to compensation matters for certain employees or officers. In the past, there has been no such delegation, but our board of directors may delegate to the compensation committee, for example, in order to comply with Section 16 of the Exchange Act or Section 162(m) of the Internal Revenue Code of 1986 when those laws require actions by outside or non-employee directors, as applicable.Rule 16b-3 issued under Section 16 of the Exchange Act provides that transactions between an issuer and its officers or directors involving issuer securities may be exempt from Section 16(b) of the Exchange Act if it meets certain requirements, one of which is approval by a committee of the board of directors of the issuer consisting of two or more non-employee directors. Section 162(m) of the Internal Revenue Code limits deductions by publicly held corporations for compensation paid to its “covered employees” (i.e., its chief executive officer and next four highest compensated officers) to the extent that the employee’s compensation for the taxable year exceeds $1,000,000. This limit does not apply to “qualified performance-based compensation,” which requires, among other things, satisfaction of a performance goal that is established by a committee of the board of directors consisting of two or more outside directors.

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The compensation committee (1) develops, approves and oversees policies relating to compensation of our chief executive officer and other executive officers, (2) discharges the board’s responsibility relating to the establishment, amendment, modification, or termination of our 2007 Long Term Incentive Plan, the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) (the “Phantom Unit Plan I”) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (the “Phantom Unit Plan II”), health and welfare plans, incentive plans, defined contribution plans (401(k) plans), and any other benefit plan, program or arrangement which we sponsor or maintain and (3) discharges the responsibilities of the override unit committee of the board of directors.

Specifically, the compensation committee reviews and makes recommendations to the board of directors regarding annual and long-term performance goals and objectives for the chief executive officer and our other senior executives; reviews and makes recommendations to the board of directors regarding the annual salary, bonus and other incentives and benefits, direct and indirect, of the chief executive officer and our senior executives; reviews and authorizes the company to enter into employment, severance or other compensation agreements with the chief executive officer and other senior executives; administers our executive incentive plans, including the Phantom Unit Plan I and the Phantom Unit Plan II; establishes and periodically reviews perquisites and fringe benefits policies; reviews annually the implementation of our company-wide incentive bonus program; oversees contributions to our 401(k) plan; and performs such duties and responsibilities as may be assigned by the board of directors to the compensation committee under the terms of any executive compensation plan, incentive compensation plan or equity-based plan and as may be assigned to the compensation committee with respect to the issuance and management of the override units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.

The compensation committee has regularly scheduled meetings concurrent with the board of directors meetings and additionally meets at other times as needed throughout the year. Frequently issues are discussed via teleconferencing. The chief executive officer, while a member of the compensation committee prior to our becoming a public company, did not participate in the determination of his own compensation, thereby avoiding any potential conflict of interest. However, he actively provided and will continue to provide guidance and recommendations to the committee regarding the amount and form of the compensation of the other executive officers and key employees. During 2006 and prior to our becoming a public company, given that the compensation committee consisted of senior representatives of the Goldman Sachs Funds and the Kelso Funds, as well as our chief executive officer, the board did not change or reject decisions made by the compensation committee.

Compensation paid to executive officers is closely aligned with our performance on both a short-term and long-term basis. Compensation is structured competitively in order to attract, motivate and retain executive officers and key employees and is considered crucial to our long-term success and the long-term enhancement of stockholder value. Compensation is structured to ensure that the executive officers’ objectives and rewards are directly correlated to our long-term objectives and the executive officers’ interests are aligned with those of stockholders. To this end, the compensation committee believes that the most critical component of compensation is equity compensation.

The following discusses in detail the foundation underlying and the drivers of our executive compensation philosophy, and also how the related decisions are made. Qualitative information related to the most important factors utilized in the analysis of these decisions is described.

Elements of Compensation

The three primary components of the compensation program are salary, an annual cash incentive bonus, and equity awards. Executive officers are also provided with benefits that are generally available to our salaried employees.

While these three components are related, we view them as separate and analyze them as such. The compensation committee believes that equity compensation is the primary motivator in

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attracting and retaining executive officers. Salary and cash incentive bonuses are viewed as secondary; however, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.

Base Salary

We fix the base salary of each of our executive officers at a level that we believe enables us to hire, motivate and retain individuals in a competitive environment and to reward satisfactory individual and company performance. In determining its recommendations for salary levels, the compensation committee takes into account peer group pay and individual performance.

With respect to our peer group, management, through the chief executive officer, provides the compensation committee with information gathered through a detailed annual review of executive compensation programs of other publicly and privately held companies in our industry, which are similar to us in size and operations (among other factors). In 2007, management reviewed and provided information to the compensation committee regarding the salary, bonus and other compensation amounts paid to named executive officers in respect of 2006 for the following independent refining companies, which we view as members of our peer group: Frontier Oil Corporation, Holly Corporation and Tesoro Corporation. Management also reviewed the following fertilizer businesses for executives focused on our fertilizer business: CF Industries Holdings Inc. and Terra Industries, Inc. It then averaged these peer group salary levels over a number of years to develop a range of salaries of similarly situated executives of these companies, and used this range as a factor in determining base salary (and overall cash compensation) of the named executive officers. Management also reviewed the differences in levels of compensation among the named executive officers of this peer group, and used these differences as a factor in setting a different level of salary and overall compensation for each of our named executive officers based on their relative positions and levels of responsibility.

With respect to individual performance, the compensation committee considered, among other things, the following specific achievements over the past 12 months with respect to Mr. Lipinski.


	•	Flood Response. Mr. Lipinski directed the Company’s successful response to an unprecedented flood which devastated portions of the city of Coffeyville during the weekend of June 30, 2007 and closed down our refinery and the nitrogen fertilizer plant. The flood also resulted in a crude oil discharge from our refinery into the Verdigris River that required an immediate environmental response. Under Mr. Lipinski’s leadership, the refinery was restored to full operation in approximately six weeks, and the fertilizer plant, situated on higher ground, returned to full operation in approximately 18 days. In addition, Mr. Lipinski oversaw our efforts to work closely with the EPA and Kansas and Oklahoma regulators to review and analyze the environmental effects of the crude oil discharge and coordinate a property repurchase project in which we purchased approximately 300 homes from citizens of Coffeyville at their pre-flood values (or greater). This effort contributed to a successful outcome in our defense of two class action lawsuits.

	•	Initial Public Offering. Mr. Lipinski supervised the initial filing of our registration statement with the Securities and Exchange Commission in September 2006 and the consummation of our initial public offering in October 2007. The initial public offering process required a large amount of time and attention due to the turnaround in the first quarter of 2007, the decision to move our nitrogen fertilizer operations into a limited partnership structure, and the flood which occurred during the weekend of June 30, 2007. We ultimately listed our shares of common stock on the New York Stock Exchange and sold 23 million shares in the offering at an initial price of $19.00 per share.

	•	Business Expansion. Mr. Lipinski directed the Company’s growth strategy beginning in 2005, which included our refinery expansion project during 2006 and 2007 and the fertilizer plant UAN expansion project that commenced in 2007. Nearly every process unit at the refinery was involved in the refinery expansion project, which was consummated in the fourth quarter of

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		2007. Our refinery throughput rates, averaging less than 90,000 bpd prior to June 2005, averaged over 110,000 bpd of crude during the fourth quarter of 2007, a record rate for our refinery. In addition, the blend of crudes was optimized to accommodate larger volumes of heavy sour crude. We processed more than 21,000 bpd of heavy sour crude in the fourth quarter of 2007, as compared with 2,700 bpd of heavy sour crude in the first quarter of 2006. Part of this project also included the addition of a new 24,000 bpd continuous catalytic reforming (“CCR”) unit which replaced an older technology unit two-thirds its size. The new CCR increased reforming capacity and also over time will produce more hydrogen, which over time will reduce our refinery’s dependence on the nitrogen fertilizer business for hydrogen purchases. The fertilizer plant UAN expansion project is expected to enable the nitrogen fertilizer plant to consume substantially all of its net ammonia production in the production of UAN, historically a higher margin product than ammonia. We estimate that it will result in an approximately 50% increase in the fertilizer plant’s annual UAN production.

With respect to individual performance of Messrs. Riemann, Rens, Haugen and Daly, the compensation committee considered, among other things, management’s immediate and effective response to the June 2007 flood, the successful completion of our initial public offering in October 2007 and the expansion of our refinery’s capacity as evidenced by achievement of record throughput rates in the fourth quarter of 2007.

Each of the named executive officers has an employment agreement which sets forth his base salary. Salaries are reviewed annually by the compensation committee with periodic informal reviews throughout the year. Adjustments, if any, are usually made on January 1st of the year immediately following the review. In the fourth quarter of 2006, the compensation committee determined that Mr. ~~Haugen’s~~Haugen��s base salary should be increased from $225,000 to $275,000 due to his increased responsibilities with our Company. The base salaries of Mr. Lipinski, Mr. Riemann and Mr. Rens were not adjusted at that time. The compensation committee most recently reviewed the level of cash salary and bonus for each of the executive officers in November 2007 and noted certain changes of responsibilities and promotions. Individual performance, the practices of our peer group of companies and changes in an executive officer’s status were considered, and each measurement was given relatively equal weight. The compensation committee recommended that the board of directors increase the 2008 salaries of Messrs. Lipinski (to $700,000 from $650,000), Riemann (to $375,000 from $350,000) and Rens (to $300,000 from $250,000), respectively, effective January 1, 2008, due to the increase in the cost of living and in order align their total compensation with compensation paid by companies in our peer group. Prior to October 23, 2007, Mr. Daly did not have an employment agreement with the Company. His base salary of $215,000 for 2007 was increased to $220,000 effective January 1, 2008 pursuant to the terms of the October 23, 2007 employment agreement. Mr. Haugen’s salary for 2008 remained at $275,000.

In addition, the compensation committee determined that no equity awards should be made to the named executive officers in connection with our initial public offering in 2007. However, the compensation committee may elect to make restricted stock grants, option grants or other equity grants during 2008 in its discretion. In addition, Coffeyville Acquisition III LLC, which owns the managing general partner of the Partnership, made limited equity grants of interests in Coffeyville Acquisition III LLC to the executive officers in 2007.

Annual Bonus

We use information about total cash compensation paid by members of our peer group of companies, the composition of which is discussed above, in determining both the level of bonus award and the ratio of salary to bonus because we believe that maintaining a level of bonus and a ratio of fixed salary (which is fixed and guaranteed) to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in retaining the executives. The compensation committee also desires that a significant portion of our executive officers’ compensation package be at risk. That is, a portion of the executive officers’ overall compensation would not be guaranteed and would be

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determined based on individual and company performance. With respect to individual performance, the compensation committee considered the specific achievements of our named executive officers, as described above.

Our program provides for greater potential bonus awards as the authority and responsibility of a position increase. Our chief executive officer has the greatest percentage of his compensation at risk in the form of a discretionary bonus. Bonuses are determined based on our analysis of the total compensation packages for executive officers in our peer group. Our named executive officers retain a significant percentage of their compensation package at risk in the form of potential discretionary bonuses.

Bonuses may be paid in an amount equal to the target percentage, less than the target percentage or greater than the target percentage based on current year performance as recommended by the compensation committee. The performance determination takes into account overall operational performance, financial performance, factors affecting shareholder value including growth initiatives, and the individual’s personal performance. The determination of whether the target bonus amount should be paid is not based on specific metrics, but rather a general assessment of how the business performed as compared to the business plan developed for the year. Due to the nature of the business, financial performance alone may not dictate or be a fair indicator of the performance of the executive officers. Conversely, financial performance may exceed all expectations, but it could be due to outside forces in the industry rather than true performance by an executive that exceeds expectations. In order to take this mismatch into consideration and to assess the executive officers’ performance on their own merits, the compensation committee makes an assessment of the executive officer’s performance separate from the actual financial performance of the company, although such measurement is not based on any specific metrics.

The compensation committee reviewed the individualized performance and company performance as compared to expectations for the year ended December 31, 2007. Under their employment agreements, the 2007 target bonuses were the following percentages of salary for each of the following: Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann (200%), Mr. Haugen (120%) and Mr. Daly (80%). The bonuses in respect of 2007 performance were greater than target for Messrs. Lipinski and Rens due to their significant and continuous involvement in our initial public offering, which was consummated in October 2007, and due to their effective leadership role in and their coordination of the effective response to the flood that occurred during the weekend of June 30, 2007. Bonuses in respect of 2007 performance were less than target for Messrs. Riemann and Haugen because of a review of how the business performed as compared to our business plan developed for the year. Mr. Daly’s bonus was approximately equivalent to his target bonus amount. Under their employment agreements, the 2008 target bonuses will be the following percentages of salary for each of the following: Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann (200%), Mr. Haugen (120%) and Mr. Daly (80%).

Annual cash incentive bonuses for our named executive officers are established as part of their respective individual employment agreements. Each of these employment agreements provides that the executive will receive an annual cash performance bonus determined in the discretion of the board of directors, with a target bonus amount specified as a percentage of salary for that executive officer based on individualized performance goals and company performance goals. In connection with the review of peer company compensation practices with respect to total cash compensation paid as described above, in November 2007, the compensation committee did not adjust the future target percentage for the performance-based annual cash bonus for executive officers as the Committee felt such targets were comparable to, and appropriate with respect to, its peer companies.

Equity

We use equity incentives to reward long-term performance. The issuance of equity to executive officers is intended to generate significant future value for each executive officer if the company’s

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performance is outstanding and the value of the company’s equity increases for all stockholders. The compensation committee believes that this also promotes long-term retention of the executive. The equity incentives were negotiated to a large degree at the time of the acquisition of our business in June 2005 (with additional units that were not originally allocated in June 2005 issued in December 2006) in order to bring the executive officers’ compensation package in line with executives at private equity portfolio companies, based on the private equity market practices at that time.

The greatest share of total compensation to the chief executive officer and other named executive officers (as well as selected senior executives and key employees) is in the form of equity: common units in our two largest stockholders, Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, override units within Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and common and override units in Coffeyville Acquisition III LLC, the entity which owns the managing general partner of the Partnership which holds the nitrogen fertilizer business. Any financial obligations related to such common units and override units reside with the issuer of such units and not with CVR Energy. Separately, Coffeyville Resources, LLC, a subsidiary of CVR Energy, issued phantom points to certain members of management, and any financial obligations related to such phantom points are the obligations of CVR Energy. The total number of such awards is detailed in this prospectus and was approved by the board of directors.

The limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC provide the methodology for payouts for most of this equity based compensation. In general terms, the agreements provide for two classes of interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC: (1) common units and (2) profits interests, which are called override units (and consist of both operating units and value units). Each of the named executive officers has a capital account under which his balance is increased or decreased to reflect his allocable share of net income and gross income of Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, the capital that the named executive officer contributed in exchange for his common units, distributions paid to such named executive officer and his allocable share of net loss and items of gross deduction. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC may make distributions to their members to the extent that the cash available to them is in excess of the business’ reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds. All cash payable pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC will be paid by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively, and will not be paid by CVR Energy. Although CVR Energy is required to recognize a compensation expense with respect to such awards, CVR Energy also records a contribution to capital with respect to these awards, and as a result, there is no cash effect on CVR Energy.

The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) (which we refer to as the Phantom Unit Plan I) works in correlation with the methodology established by the Coffeyville Acquisition LLC limited liability company agreement and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (which we refer to as the Phantom Unit Plan II) works in correlation with the methodology established by the Coffeyville Acquisition II LLC limited liability company agreement.

The limited liability company agreement of Coffeyville Acquisition III LLC provides for two classes of interests in Coffeyville Acquisition III LLC: (1) common units and (2) profits interests, which are called override units. Each of the named executive officers has a capital account under which his balance is increased or decreased to reflect his allocable share of net income and gross income of Coffeyville Acquisition III LLC, the capital that the named executive officer contributed, distributions paid to such named executive officer and his allocable share of net loss and items of gross deduction. Coffeyville Acquisition III LLC may make distributions to its members to the extent that the cash available to it is in excess of the business’ reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds.

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All issuances of override units and phantom points made through December 31, 2007 were made at what the board of directors determined to be their fair value on their respective grant dates. For a more detailed description of these plans, please see “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC,” “— Executive Officers’ Interests in Coffeyville Acquisition III LLC,” and “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II),” below.

Additionally, there was a pool of override units under the Coffeyville Acquisition LLC limited liability company agreement that had not been issued as of December 2006. It was the intent that, upon a filing of a registration statement, the unallocated override units in the pool would be issued. The compensation committee recommended that all remaining override units in the pool available be issued to John J. Lipinski on December 29, 2006. The compensation committee made its decision and recommendation to the board of directors to grant Mr. Lipinski these additional units based on his accomplishments (and made the decision and recommendation without any input from Mr. Lipinski). Mr. Lipinski has been and will continue to be instrumental in positioning the company to become more competitive and in increasing the capacity of the refinery operations through his negotiating and obtaining favorable crude oil pricing, as well as in helping to gain access to capital in order to expand overall operations of both segments of our business. The increased value and growth of the business is directly attributable to the actions and leadership that Mr. Lipinski has provided for the overall executive management group.

Additionally, due to the significant contributions of Mr. Lipinski as reflected above, in December 2006 the compensation committee awarded him for his services 0.1044200 shares in Coffeyville Refining & Marketing, Inc. and 0.2125376 shares in Coffeyville Nitrogen Fertilizers, Inc. This approximated 0.31% and 0.64% of each company’s total shares outstanding, respectively, at that time. The shares were issued to compensate him for his exceptional performance related to the operations of the business. In connection with the formation of Coffeyville Refining & Marketing Holdings, Inc. in August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. Prior to our becoming a public company in October 2007, these shares were exchanged for 247,471 shares of common stock in CVR Energy at an equivalent fair market value.

We also established a stock incentive plan in connection with our initial public offering in October 2007. No awards have been established at this time for the chief executive officer or other named executive officers. In keeping with the compensation committee’s stated philosophy, such awards will be intended to help achieve the compensation goals necessary to run our business. As stated above, the compensation committee may elect to make awards under this plan in 2008 at its discretion.

Other Forms of Compensation

Each of our executive officers has a provision in his employment agreement providing for certain severance benefits in the event of termination without cause. These severance provisions are described in the “Employment Agreements and Other Arrangements” section below. The severance arrangements were all negotiated with the original employment agreements between the executive officer and the company. There are no change of control arrangements, but the compensation committee believed that there needed to be some form of compensation upon certain events of termination of services as is customary for similar companies.

As a general matter, we do not provide a significant number of perquisites to named executive officers.

Compensation Policies and Philosophy

Ours is a commodity business with high volatility and risk where earnings are not only influenced by margins, but also by unique, innovative and aggressive actions and business practices on the part of the executive team. The compensation committee routinely reviews financial and operational

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performance compared to our business plan, positive and negative industry factors, and the response of the senior management team in dealing with and maximizing operational and financial performance in the face of otherwise negative situations. Due to the nature of our business, performance of an individual or the business as a whole may be outstanding; however, our financial performance may not depict this same level of achievement. The financial performance of the company is not necessarily reflective of individual operational performance. These are some of the factors used in setting executive compensation. Specific performance levels or benchmarks are not necessarily used to establish compensation; however, the compensation committee takes into account all factors to make a subjective determination of related compensation packages for the executive officers.

The compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is equity compensation. The decision is strictly made on a subjective and individual basis considering all relevant facts.

For compensation decisions, including decisions regarding the grant of equity compensation relating to executive officers (other than our chief executive officer and chief operating officer), the compensation committee typically considers the recommendations of our chief executive officer.

In recommending compensation levels and practices, our management reviews peer group compensation practices based on publicly available data. The analysis is done in-house in its entirety and is reviewed by executive officers who are not members of the compensation committee. The analysis is based on public information available through proxy statements and similar sources. Because the analysis is almost always performed based on prior year public information, it may often be somewhat outdated. We have not historically and at this time do not intend to hire or rely on independent consultants to analyze or prepare formal surveys for us. We do receive certain unsolicited executive compensation surveys; however, our use of these is limited as we believe we need to determine our baseline based on practices of other companies in our industry.

Because we are now a public company, Section 162(m) of the Internal Revenue Code limits the deductibility of compensation in excess of $1 million paid out to our executive officers unless specific and detailed criteria are satisfied. We believe that it is in our best interest to deduct compensation paid to our executive officers. We will consider the anticipated tax treatment to the company and our executive officers in the review and determination of the compensation payments and incentives. No assurance, however, can be given that the compensation will be fully deductible under Section 162(m).

Nitrogen Fertilizer Limited Partnership

A number of our executive officers, including our chief executive officer, chief operating officer, chief financial officer, general counsel, executive vice president/general manager for nitrogen fertilizer, and vice president, environmental, health and safety, serve as executive officers for both our company and the Partnership. These executive officers receive all of their compensation and benefits from us, including compensation related to services for the Partnership, and are not paid by the Partnership or its managing general partner. However, the Partnership or the managing general partner must reimburse us pursuant to a services agreement for the time our executive officers spend working for the Partnership. The percentage of each named executive officer’s compensation that represents the services provided to the Partnership in 2007 are approximately as follows: John J. Lipinski (25%), Stanley A. Riemann (40%), James T. Rens (35%), Robert W. Haugen (5%) and Daniel J. Daly, Jr. (10%).

We have entered into a services agreement with the Partnership and its managing general partner in which we have agreed to provide management services to the Partnership for the operation of the nitrogen fertilizer business. Under this agreement, any of the Partnership, its managing general partner or Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, are required

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to pay us (i) all costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share must be determined by us on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs; and (iv) various other administrative costs in accordance with the terms of the agreement. Either we or the managing general partner of the Partnership may terminate the agreement upon at least 90 days notice.

Summary Compensation Table

The following table sets forth certain information with respect to compensation for the years ended December 31, 2006 and December 31, 2007 earned by our chief executive officer, our chief financial officer and our three other most highly compensated executive officers as of December 31, 2007. In this prospectus, we refer to these individuals as our named executive officers.


										Non-Equity
Name and								Stock		Incentive Plan		All Other
Principal Position	Year		Salary		Bonus(1)			Awards(3)		Compensation(1)(4)		Compensation(5)			Total

John J. Lipinski		2007	$	650,000	$	1,850,000			—		—	$	12,189,955	(6)	$	14,689,955
Chief Executive Officer		2006	$	650,000	$	1,331,790		$	4,326,188	$	487,500	$	5,007,935	(7)	$	11,803,413
James T. Rens		2007	$	250,000	$	400,000			—		—	$	2,761,144	(8)	$	3,411,144
Chief Financial Officer		2006	$	250,000	$	205,000			—	$	130,000	$	695,316	(9)	$	1,280,316
Stanley A. Riemann		2007	$	350,000	$	722,917	(2)		—		—	$	4,911,011	(10)	$	5,983,928
Chief Operating Officer		2006	$	350,000	$	772,917	(2)		—	$	210,000	$	943,789	(11)	$	2,276,706
Robert W. Haugen		2007	$	275,000	$	230,000			—		—	$	2,822,978	(12)	$	3,327,978
Executive Vice President,		2006	$	225,000	$	205,000			—	$	117,000	$	695,471	(13)	$	1,242,471
Refining Operations
Daniel J. Daly, Jr.		2007	$	215,000	$	200,000			—		—	$	2,355,059	(14)	$	2,770,059
Executive Vice President,		2006	$	185,000	$	175,000			—	$	96,200	$	714,705	(15)	$	1,170,905
Strategy


(1)		Bonuses are reported for the year in which they were earned, though they may have been paid the following year.

(2)		Includes a retention bonus in the amount of $122,917.

(3)		Reflects the amount recognized for financial statement reporting purposes for the fiscal years ended December 31, 2006 and December 31, 2007 with respect to shares of common stock of each of Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc. granted to Mr. Lipinski effective December 28, 2006. In connection with the formation of Coffeyville Refining & Marketing Holdings, Inc. in August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. In connection with our initial public offering in October 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. were exchanged by Mr. Lipinski for 247,471 shares of our common stock.

(4)		Reflects cash awards to the named individuals in respect of 2006 performance pursuant to our Variable Compensation Plan. Beginning in 2007, our executive officers no longer participated in this plan.

(5)		The amounts shown represent grants of profits interests in Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and grants of phantom points in Phantom Unit Plan I and Phantom Unit Plan II and reflect the dollar amounts recognized for financial statement reporting purposes for the years ended December 31, 2006 and December 31, 2007 in accordance with SFAS 123(R). For the 2006 amounts, assumptions used in the calculation are

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		included in footnote 5 to our audited financial statements for the year ended December 31, 2006 included in the Company’s registration statement onForm S-1/A filed on October 16, 2007. For the 2007 amounts, assumptions used in the calculation are included in footnote 3 to our audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. The profits interests in Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and the phantom points in Phantom Unit Plan I and Phantom Unit Plan II are more fully described below under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC,” “— Executive Officers’ Interests in Coffeyville Acquisition III LLC,” and “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II).”

(6)		Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC that were granted in 2005 in the amount of $8,057,632, (e) profits interests in Coffeyville Acquisition LLC that were granted on December 29, 2006 in the amount of $1,595,428, (f) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $1,080 and (g) phantom points granted during the period ending December 31, 2006 in the amount of $2,519,640.

(7)		Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) forgiveness of a note that Mr. Lipinski owed to Coffeyville Acquisition LLC in the amount of $350,000, (d) forgiveness of accrued interest related to the forgiven note in the amount of $17,989, (e) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $630,059, (f) a cash payment in respect of taxes payable on his December 28, 2006 grant of subsidiary stock in the amount of $2,481,346, (g) profits interests in Coffeyville Acquisition LLC that were granted on December 29, 2006 in the amount of $20,510 and (h) phantom points granted during the period ending December 31, 2006 in the amount of $1,495,211.

(8)		Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,836,087, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $201 and (f) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $911,768.

(9)		Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $279,670 and (d) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $651,299.

(10)		Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $3,576,617, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $393, (f) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $1,097,527 and (g) a relocation bonus of $222,099.

(11)		Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and

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		(d) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $541,061.

(12)		Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,836,087, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $201, (f) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $911,768 and (g) a relocation bonus of $61,500.

(13)		Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and (d) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $541,061.

(14)		Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,324,168, (d) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $144 and (e) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $1,016,972.

(15)		Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $103,543 and (d) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $603,491.

Employment Agreements 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, which was subsequently assumed by CVR Energy and amended and restated effective as of December 29, 2007. The agreement has a rolling term of three years so that at the end of each month it automatically renews for one additional month, unless otherwise terminated by CVR Energy or Mr. Lipinski. Mr. Lipinski receives an annual base salary of $700,000. Mr. Lipinski is eligible to receive a performance-based annual cash bonus with a target payment equal to 250% of his annual base salary to be based upon individual and/or company performance criteria as established by our board of directors for each fiscal year.

Mr. Lipinski’s agreement provides for certain severance payments that may be due following the termination of his employment. These benefits are described below under “— Potential Payments Upon Termination or Change-of-Control.”

Stanley A. Riemann, James T. Rens, Robert W. Haugen and Daniel J. Daly, Jr. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Mr. Riemann, Mr. Rens, and Mr. Haugen. The agreements were subsequently assumed by CVR Energy and amended and rested effective as of December 29, 2007. The agreements have a term of three years and expire in December 2010, unless otherwise terminated earlier by the parties. CVR Energy entered into an employment agreement with Mr. Daly on October 23, 2007 and amended that agreement as of November 30, 2007. The agreements provide for an annual base salary of $375,000 for Mr. Riemann, $300,000 for Mr. Rens, $275,000 for Mr. Haugen and $220,000 for Mr. Daly. Each executive officer is eligible to receive a performance-based annual cash bonus to be based upon individual and/or company performance criteria as established by the board of directors of Coffeyville Resources, LLC

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for each fiscal year. The target annual bonus percentages are as follows: Mr. Riemann (200%), Mr. Rens (120%), Mr. Haugen (120%) and Mr. Daly (80%).

These agreements provide for certain severance payments that may be due following the termination of the executive officers’ employment. These benefits are described below under “— Potential Payments Upon Termination or Change of Control.”

Long Term Incentive Plan

The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP, permits the grant of options, stock appreciation rights, or SARs, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). Individuals who are eligible to receive awards and grants under the LTIP include our and our subsidiaries’ employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below. As of December 31, 2007, no awards had been made under the LTIP to any of our executive officers.

Shares Available for Issuance. The LTIP authorizes a share pool of 7,500,000 shares of our common stock, 1,000,000 of which may be issued in respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available for issuance under the LTIP shall be increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of the award. As of December 31, 2007, 7,463,600 shares of common stock were available for issuance under the LTIP.

Administration and Eligibility. The LTIP is administered by a committee, which is currently the compensation committee. The committee determines who is eligible to participate in the LTIP, determines the types of awards to be granted, prescribes the terms and conditions of all awards, and construes and interprets the terms of the LTIP. All decisions made by the committee are final, binding and conclusive.

Award Limits. In any three calendar year period, no participant may be granted awards in respect of more than 6,000,000 shares in the form of (i) stock options, (ii) SARs, (iii) performance-based restricted stock and (iv) performance share units, with the above limit subject to the adjustment provisions discussed below. The maximum dollar amount of cash or the fair market value of shares that any participant may receive in any calendar year in respect of performance units may not exceed $3,000,000.

Type of Awards. Below is a description of the types of awards available for grant pursuant to the LTIP.

Stock Options. The compensation committee is authorized to grant stock options to participants. The stock options may be either nonqualified stock options or incentive stock options. The exercise price of any stock option must be equal to or greater than the fair market value of a share on the date the stock option is granted. The term of a stock option cannot exceed 10 years (except that options may be exercised for up to 1 year following the death of a participant even, with respect to nonqualified stock options, if such period extends beyond the 10 year term). Subject to the terms of the LTIP, the option’s terms and conditions, which include but are no limited to, exercise price, vesting, treatment of the award upon termination of employment, and expiration of the option, are determined by the committee and will be set forth in an award agreement. Payment for shares purchased upon exercise of an option must be made in full at the time of purchase. The exercise price may be paid (i) in cash or its equivalent (e.g., check), (ii) in shares of our common stock already owned by the participant, on terms determined by the committee, (iii) in the form of other property as determined by the committee, (iv) through participation in a “cashless exercise” procedure involving a broker or (v) by a combination of the foregoing.

~~205~~207

SARs. The compensation committee may, in its discretion, either alone or in connection with the grant of an option, grant a SAR to a participant. The terms and conditions of the award will be set forth in an award agreement. SARs may be exercised at such times and be subject to such other terms, conditions, and provisions as the committee may impose. SARs that are granted in tandem with an option may only be exercised upon the surrender of the right to purchase an equivalent number of shares of our common stock under the related option and may be exercised only with respect to the shares of our common stock for which the related option is then exercisable. The committee may establish a maximum amount per share that would be payable upon exercise of a SAR. A SAR entitles the participant to receive, on exercise of the SAR, an amount equal to the product of (i) the excess of the fair market value of a share of our common stock on the date preceding the date of surrender over the fair market value of a share of our common stock on the date the SAR was issued, or, if the SAR is related to an option, the per-share exercise price of the option and (ii) the number of shares of our common stock subject to the SAR or portion thereof being exercised. Subject to the discretion of the committee, payment of a SAR may be made (i) in cash, (ii) in shares of our common stock or (iii) in a combination of both (i) and (ii).

Dividend Equivalent Rights. The compensation committee may grant dividend equivalent rights either in tandem with an award or as a separate award. The terms and conditions applicable to each dividend equivalent right would be specified in an award agreement. Amounts payable in respect of dividend equivalent rights may be payable currently or, if applicable, deferred until the lapsing of restrictions on the dividend equivalent rights or until the vesting, exercise, payment, settlement or other lapse of restrictions on the award to which the dividend equivalent rights relate.

Service Based Restricted Stock and Restricted Stock Units. The compensation committee may grant awards of time-based restricted stock and restricted stock units. Restricted stock and restricted stock units may not be sold, transferred, pledged or otherwise transferred until the time, or until the satisfaction of such other terms, conditions and provisions, as the committee may determine. When the period of restriction on restricted stock terminates, unrestricted shares of our common stock will be delivered. Unless the committee otherwise determines at the time of grant, restricted stock carries with it full voting rights and other rights as a stockholder, including rights to receive dividends and other distributions. At the time an award of restricted stock is granted, the committee may determine that the payment to the participant of dividends be deferred until the lapsing of the restrictions imposed upon the shares and whether deferred dividends are to be converted into additional shares of restricted stock or held in cash. The deferred dividends would be subject to the same forfeiture restrictions and restrictions on transferability as the restricted stock with respect to which they were paid. Each restricted stock unit represents the right of the participant to receive a payment upon vesting of the restricted stock unit or on any later date specified by the committee. The payment will equal the fair market value of a share of common stock as of the date the restricted stock unit was granted, the vesting date or such other date as determined by the committee at the time the restricted stock unit was granted. At the time of grant, the committee may provide a limitation on the amount payable in respect of each restricted stock unit. The committee may provide for a payment in respect of restricted stock unit awards (i) in cash or (ii) in shares of our common stock having a fair market value equal to the payment to which the participant has become entitled.

Share Awards. The compensation committee may award shares to participants as additional compensation for service to us or a subsidiary or in lieu of cash or other compensation to which participants have become entitled. Share awards may be subject to other terms and conditions, which may vary from time to time and among participants, as the committee determines to be appropriate.

Performance Share Units and Performance Units. Performance share unit awards and performance unit awards may be granted by the compensation committee under the LTIP. Performance share units are denominated in shares and represent the right to receive a payment in an amount based on the fair market value of a share on the date the performance share units were granted, become vested or any other date specified by the committee, or a percentage of such amount depending on the level of performance goals attained. Performance units are denominated in a

~~206~~208

specified dollar amount and represent the right to receive a payment of the specified dollar amount or a percentage of the specified dollar amount, depending on the level of performance goals attained. Such awards would be earned only if performance goals established for performance periods are met. A minimum one-year performance period is required. At the time of grant the committee may establish a maximum amount payable in respect of a vested performance share or performance unit. The committee may provide for payment (i) in cash, (ii) in shares of our common stock having a fair market value equal to the payment to which the participant has become entitled or (iii) by a combination of both (i) and (ii).

Performance-Based Restricted Stock. The compensation committee may grant awards of performance-based restricted stock. The terms and conditions of such award will be set forth in an award agreement. Such awards would be earned only if performance goals established for performance periods are met. Upon the lapse of the restrictions, the committee will deliver a stock certificate or evidence of book entry shares to the participant. Awards of performance-based restricted stock will be subject to a minimum one-year performance cycle. At the time an award of performance-based restricted stock is granted, the committee may determine that the payment to the participant of dividends will be deferred until the lapsing of the restrictions imposed upon the performance-based restricted stock and whether deferred dividends are to be converted into additional shares of performance-based restricted stock or held in cash.

Performance Objectives. Performance share units, performance units and performance-based restricted stock awards under the LTIP may be made subject to the attainment of performance goals based on one or more of the following business criteria: (i) stock price; (ii) earnings per share; (iii) operating income; (iv) return on equity or assets; (v) cash flow; (vi) earnings before interest, taxes, depreciation and amortization, or EBITDA; (vii) revenues; (viii) overall revenue or sales growth; (ix) expense reduction or management; (x) market position; (xi) total stockholder return; (xii) return on investment; (xiii) earnings before interest and taxes, or EBIT; (xiv) net income; (xv) return on net assets; (xvi) economic value added; (xvii) stockholder value added; (xviii) cash flow return on investment; (xix) net operating profit; (xx) net operating profit after tax; (xxi) return on capital; (xxii) return on invested capital; or (xxiii) any combination, including one or more ratios, of the foregoing.

Performance criteria may be in respect of our performance, that of any of our subsidiaries, that of any of our divisions or any combination of the foregoing. Performance criteria may be absolute or relative (to our prior performance or to the performance of one or more other entities or external indices) and may be expressed in terms of a progression within a specified range. The compensation committee may, at the time performance criteria in respect of a performance award are established, provide for the manner in which performance will be measured against the performance criteria to reflect the effects of extraordinary items, gain or loss on the disposal of a business segment (other than the provisions for operating losses or income during the phase-out), unusual or infrequently occurring events and transactions that have been publicly disclosed, changes in accounting principles, the impact of specified corporate transactions (such as a stock split or stock dividend), special charges and tax law changes, all as determined in accordance with generally accepted accounting principles (to the extent applicable).

Amendment and Termination of the LTIP. Our board of directors has the right to amend the LTIP except that our board of directors may not amend the LTIP in a manner that would impair or adversely affect the rights of the holder of an award without the award holder’s consent. In addition, our board of directors may not amend the LTIP absent stockholder approval to the extent such approval is required by applicable law, regulation or exchange requirement. The LTIP will terminate on the tenth anniversary of the date of stockholder approval. The board of directors may terminate the LTIP at any earlier time except that termination cannot in any manner impair or adversely affect the rights of the holder of an award without the award holder’s consent.

~~207~~209

Repricing of Options or SARs. Unless our stockholders approve such adjustment, the compensation committee will not have authority to make any adjustments to options or SARs that would reduce or would have the effect of reducing the exercise price of an option or SAR previously granted under the LTIP.

Change in Control. The effect, if any, of a change in control on each of the awards granted under the LTIP may be set forth in the applicable award agreement.

Adjustments. In the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off,split-up, stock dividend, stock split or reverse stock split, or similar transaction or other change in corporate structure affecting our common stock, adjustments and other substitutions will be made to the LTIP, including adjustments in the maximum number of shares subject to the LTIP and other numerical limitations. Adjustments will also be made to awards under the LTIP as the compensation committee determines appropriate. In the event of our merger or consolidation, liquidation or dissolution, outstanding options and awards will either be treated as provided for in the agreement entered into in connection with the transaction (which may include the accelerated vesting and cancellation of the options and SARs or the cancellation of options and SARs for payment of the excess, if any, of the consideration paid to stockholders in the transaction over the exercise price of the options or SARs), or converted into options or awards in respect of the same securities, cash, property or other consideration that stockholders received in connection with the transaction.

Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC

The following is a summary of the material terms of the Coffeyville Acquisition LLC Second Amended and Restated Limited Liability Company Agreement and the Coffeyville Acquisition II LLC Agreement as they relate to the limited liability company interests granted to our named executive officers pursuant to those agreements as of December 31, 2007. We refer to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC collectively as the LLC Agreements. The terms of the two limited liability company agreements which relate to the interests granted to our named executive officers are identical to each other.

General. The LLC Agreements provide for two classes of interests in the respective limited liability companies: (i) common units and (ii) profits interests, which are called override units (which consist of both operating units and 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 and Coffeyville Acquisition II LLC, as applicable. Such voting rights cease, however, if the executive officer holding common units ceases to provide services to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, as applicable, or one of its or their subsidiaries. The common units were issued to our named executive officers in the following amounts (as subsequently adjusted) in exchange for capital contributions in the following amounts: Mr. Lipinski (capital contribution of $650,000 in exchange for 57,446 units), Mr. Riemann (capital contribution of $400,000 in exchange for 35,352 units), Mr. Rens (capital contribution of $250,000 in exchange for 22,095 units), Mr. Haugen (capital contribution of $100,000 in exchange for 8,838 units) and Mr. Daly (capital contribution of $50,000 in exchange for 4,419 units). These named executive officers were also granted override units, which consist of operating units and value units, in the following amounts: Mr. Lipinski (an initial grant of 315,818 operating units and 631,637 value units and a December 2006 grant of 72,492 operating units and 144,966 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. Haugen (71,965 operating units and 143,931 value units) and Mr. Daly (51,901 operating units and 103,801 value units). Override units have no voting rights attached to them, but have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable. 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 agreed to provide services to Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable.

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In addition, common units were issued to the following executive officers in the following amounts (as subsequently adjusted) in exchange for the following capital contributions: Mr. Kevan Vick (capital contribution of $250,000 in exchange for 22,095 units), Mr. Edmund Gross (capital contribution of $30,000 in exchange for 2,651 units), Mr. Christopher Swanberg (capital contribution of $25,000 in exchange for 2,209 units) and Mr. Wyatt Jernigan (capital contribution of $100,000 in exchange for 8,838 units). Also, Mr. Vick was granted 71,965 operating units and 143,931 value units and Mr. Jernigan was granted 71,965 operating units and 143,931 value units.

If all of the shares of common stock of our Company held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at ~~$16.04~~$14.31 per share, which was the price of our common stock on ~~July 15,~~August 14, 2008, and cash was distributed to members pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, our named executive officers would receive a cash payment in respect of their override units in the following approximate amounts: Mr. Lipinski ($~~40.8~~35.8 million), Mr. Riemann ($~~16.6~~14.8 million), Mr. Rens ($~~8.5~~7.6 million), Mr. Haugen ($~~8.5~~7.6 million), and Mr. Daly ($~~6.1~~5.5 million).

Forfeiture of Override Units Upon Termination of Employment. If the executive officer ceases to provide services to Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, or a subsidiary due to a termination for “cause” (as such term is defined in the LLC Agreements), the executive officer will forfeit all of his override units. If the executive officer 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 Agreements) 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 officer’s death or “disability” (as that term is defined in the LLC Agreements), 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 executive officers 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 or Coffeyville Acquisition II LLC, as applicable, the capital that the executive officer contributed, distributions paid to such executive officer and his allocable share of net loss and items of gross deduction.

Value units owned by the executive officers do not participate in distributions under the LLC Agreements until the “Current Value” is at least two times the “Initial Price” (as these terms are defined in the LLC Agreements), 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. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC may make distributions to their members to the extent that the cash available to them is in excess of the applicable business’ 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., $11.31 for override units granted on July 25, 2005 and $34.72 for Mr. Lipinski’s later grant). The boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC will determine the “Benchmark Amount” with respect to each override unit at the time of its grant. There is also acatch-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.

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Other Provisions Relating to Units. The executive officers are subject to transfer restrictions on their units, although they may make certain transfers of their units for estate planning purposes.

Executive Officers’ Interests in Coffeyville Acquisition III LLC

Coffeyville Acquisition III LLC, the sole owner of the managing general partner of the Partnership, is owned by the Goldman Sachs Funds, the Kelso Funds, our executive officers, Mr. Wesley Clark, Magnetite Asset Investors III L.L.C. and certain members of our senior management team. The following is a summary of the material terms of the Coffeyville Acquisition III LLC limited liability company agreement as they relate to the limited liability company interests held by our executive officers.

General. The Coffeyville Acquisition III LLC limited liability company agreement provides for two classes of interests in Coffeyville Acquisition III LLC: (i) common units and (ii) profits interests, which are called override units.

The common units provide for voting rights and have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition III LLC. Such voting rights cease, however, if the executive officer holding common units ceases to provide services to Coffeyville Acquisition III LLC or one of its subsidiaries. In October 2007, CVR Energy’s executive officers made the following capital contributions to Coffeyville Acquisition III LLC and received a number of Coffeyville Acquisition III LLC common units equal to their pro rata portion of all contributions: Mr. Lipinski ($68,146), Mr. Riemann ($16,360), Mr. Rens ($10,225), Mr. Haugen ($4,090), Mr. Daly ($2,045), Mr. Jernigan ($4,090), Mr. Gross ($1,227), Mr. Vick ($10,225) and Mr. Swanberg ($1,022).

Override units have no voting rights attached to them, but have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition III LLC. The override units have the following terms:


	•	Approximately 25% of all of the override units have been awarded to members of our management team. These override units automatically vested. These units will be owned by the members of our management team even if they no longer perform services for us or are no longer employed by us. The following executive officers received the following grants of this category of override units: Mr. Lipinski (81,250), Mr. Riemann (30,000), Mr. Rens (16,634), Mr. Haugen (16,634), Mr. Jernigan (14,374), Mr. Gross (8,786), Mr. Vick (13,405), Mr. Swanberg (8,786) and Mr. Daly (13,269).

	•	Approximately 75% of the override units have been awarded to members of our management team responsible for the growth of the nitrogen fertilizer business. Some portion of these units may be awarded to members of management added in the future. These units vest on a five-year schedule, with 33.3% vesting on the third anniversary of the closing date of the Partnership’s initial public offering (if any such offering occurs), an additional 33.4% vesting on the fourth anniversary of the closing date of such an offering, and the remaining 33.3% vesting on the fifth anniversary of the closing date of such an offering. Override units are entitled to distributions whether or not they have vested. Management members will forfeit unvested units if they are no longer employed by us; however, if a management member has three full years of service with the Partnership following the completion of an initial public offering of the Partnership, such management member may retire at age 62 and will be entitled to permanently retain all of his or her units whether or not they have vested pursuant to the vesting schedule described above. Units forfeited will be either retired or reissued to others (with a catchup payment provision); retired units will increase the unit values of all other units on a pro rata basis. The following executive officers received the following grants of this category of override units: Mr. Lipinski (219,378), Mr. Riemann (75,000), Mr. Rens (48,750), Mr. Haugen (13,125), Mr. Jernigan (11,250), Mr. Gross (22,500), Mr. Vick (45,000), Mr. Swanberg (11,250) and Mr. Daly (18,750).

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The override units granted to management are entitled to 15% of all distributions made by Coffeyville Acquisition III LLC. All vested and unvested override units are entitled to distributions. To the extent that at any time not all override units have yet been granted, the override units that have been granted will be entitled to the full 15% of all distributions (e.g., if only 90% of the override units have been granted, the holders of these 90% are entitled to 15% of all distributions).

A portion of the override units may be granted in the future to new members of management. A catch up payment will be made to new members of management who receive units at a time when the current unit value has increased from the initial unit value.

The value of the common units and override units in Coffeyville Acquisition III LLC depends on the ability of the Partnership’s managing general partner to make distributions. The managing general partner will not receive any distributions from the Partnership until the Partnership’s aggregate adjusted operating surplus through December 31, 2009 has been distributed. Based on the Partnership’s current projections, the Partnership believes that the executive officers will not begin to receive distributions on their common and override units until after December 31, 2010.

Adjustments to Capital Accounts; Distributions. Each of the executive officers 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 III LLC, the capital that the executive officer contributed, distributions paid to such executive officer and his allocable share of net loss and items of gross deduction.

Override units owned by the executive officers do not participate in distributions under the Coffeyville Acquisition III LLC limited liability company agreement until the “Current Value” is at least equal to the “Initial Price” (as these terms are defined in the Coffeyville Acquisition III LLC limited liability company agreement). Coffeyville Acquisition III LLC may make distributions to its members to the extent that the cash available to it is in excess of the business’ 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, however, will be reduced until the total reductions in proposed distributions in respect of the override units equals the aggregate capital contributions of all members.

Other Provisions Relating to Coffeyville Acquisition III LLC Units. The executive officers are subject to transfer restrictions on their Coffeyville Acquisition III LLC units, although they may make certain transfers of their units for estate planning purposes.

Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)

The following is a summary of the material terms of the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), or the Phantom Unit Plan I, and the Coffeyville Resources LLC Phantom Unit Appreciation Plan (Plan II), or the Phantom Unit Plan II, as they relate to our named executive officers. Payments under the Phantom Unit Plan I are tied to distributions made by Coffeyville Acquisition LLC, and payments under the Phantom Unit Plan II are tied to distributions made by Coffeyville Acquisition II LLC. We refer to the Phantom Unit Plan I and Phantom Unit Plan II collectively as the Phantom Unit Plans.

General. The Phantom Unit Plan I and Phantom Unit Plan II are administered by the compensation committees of the boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, as applicable. The Phantom Unit Plans provide for two classes of interests: phantom service points and phantom performance points (collectively referred to as 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 Agreements in respect of operating units and value units, respectively. The phantom points represent a contractual right to receive a payment

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when payment is made in respect of certain profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, as applicable.

Phantom points have been granted under each of the Phantom Unit Plans 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 approximately 14% of the total phantom points awarded), Mr. Riemann (596,133 phantom service points and 596,133 phantom performance points, which represents approximately 6% of the total phantom points awarded), Mr. Rens (495,238 phantom service points and 495,238 phantom performance points, which represents approximately 5% of the total phantom points awarded), Mr. Haugen (495,238 phantom service points and 495,238 phantom performance points, which represents approximately 5% of the total phantom points awarded) and Mr. Daly (552,381 phantom service points and 552,381 phantom performance points, which represents approximately 6% of the total phantom points awarded).

If all of the shares of common stock of our company held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at ~~$16.04~~$14.31 per share, which was the closing price of our common stock on ~~July 15,~~August 14, 2008, and cash was distributed to members pursuant to the LLC Agreement and the Coffeyville Acquisition II LLC Agreement, our named executive officers would receive a cash payment in respect of their phantom points in the following amounts: Mr. Lipinski ($~~5.7~~5.0 million), Mr. Riemann ($~~2.5~~2.2 million), Mr. Rens ($~~2.0~~1.8 million), Mr. Haugen ($~~2.0~~1.8 million) and Mr. Daly ($~~2.3~~2.0 million). The compensation committees of the boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC have authority to make additional awards of phantom points under the Phantom Unit Plans.

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 Agreements 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 Agreements in respect of value units (i.e., not until the “Current Value” is at least two times the “Initial Price” (as such terms are defined in the LLC Agreements), 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 also acatch-up provision with respect to phantom performance points for which no cash payment was made because no distribution pursuant to the LLC Agreements was made with respect to value units.

Other Provisions Relating to the Phantom Points. The boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC may, at any time or from time to time, amend or terminate the Phantom Unit Plans. If a participant’s employment is terminated prior to an “Exit Event” (as such term is defined in the LLC Agreements), all of the participant’s phantom points are forfeited. Phantom points 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 “cut back” only if that reduction would be more beneficial to the participant on an after-tax basis than if there were no reduction.

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Outstanding Equity Awards at 2007 Fiscal Year-End


	Stock Awards
	Number of Shares			Market Value of
	or Units of Stock			Shares or Units of
	That Have Not			Stock That Have Not
Name	Vested (#)(1)(2)			Vested ($)(3)

John J. Lipinski		118,431.7	(4)	$	6,139,499
		315,818.5	(5)	$	16,372,031
		36,246.0	(6)	$	1,878,993
		72,483.0	(7)	$	2,366,570
		118,431.7	(8)	$	6,139,499
		315,818.5	(9)	$	16,372,031
		36,246.0	(10)	$	1,878,993
		72,483	(11)	$	2,366,570
		1,368,571	(12)	$	1,241,568
		1,368,571	(13)	$	2,483,136
		1,368,571	(14)	$	1,241,568
		1,368,571	(15)	$	2,483,136
James T. Rens		26,986.9	(16)	$	1,399,001
		71,965.5	(17)	$	3,730,692
		26,986.9	(18)	$	1,399,001
		71,965.5	(19)	$	3,730,692
		495,238	(20)	$	449,271
		495,238	(21)	$	898,569
		495,238	(22)	$	449,271
		495,238	(23)	$	898,569
Stanley A. Riemann		52,569.4	(24)	$	2,725,198
		140,185.5	(25)	$	7,267,216
		52,569.4	(26)	$	2,725,198
		140,185.5	(27)	$	7,267,216
		596,133	(28)	$	540,821
		596,133	(29)	$	1,081,616
		596,133	(30)	$	540,821
		596,133	(31)	$	1,081,616
Robert W. Haugen		26,986.9	(32)	$	1,399,001
		71,965.5	(33)	$	3,730,692
		26,986.9	(34)	$	1,399,001
		71,965.5	(35)	$	3,730,692
		495,238	(36)	$	449,271
		495,238	(37)	$	898,569
		495,238	(38)	$	449,271
		495,238	(39)	$	898,569
Daniel J. Daly, Jr.		19,462.9	(40)	$	1,008,957
		51,900.5	(41)	$	2,690,522
		19,462.9	(42)	$	1,008,957
		51,900.5	(43)	$	2,690,522
		552,381	(44)	$	501,111
		552,381	(45)	$	1,002,249
		552,381	(46)	$	501,111
		552,381	(47)	$	1,002,249

~~213~~215


(1)		The profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC generally vest as follows: operating units generally become non-forfeitable in 25% annual increments beginning on the second anniversary of the date of grant, and value units are generally forfeitable upon termination of employment. The profits interests are more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.”

(2)		The phantom points granted pursuant to the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) are generally forfeitable upon termination of employment. The phantom points are more fully described above under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II).”

(3)		The dollar amount shown reflects the fair value as of December 31, 2007, based upon an independent third-party valuation performed as of December 31, 2007 using the December 31, 2007 CVR Energy common stock closing price on the NYSE to determine the equity value of CVR Energy. Assumptions used in the calculation of these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus.

(4)		Represents 118,431.7 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(5)		Represents 315,818.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(6)		Represents 36,246.0 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(7)		Represents 72,483.0 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(8)		Represents 118,431.7 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(9)		Represents 315,818.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(10)		Represents 36,246.0 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(11)		Represents 72,483 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(12)		Represents 1,368,571 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(13)		Represents 1,368,571 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(14)		Represents 1,368,571 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

~~214~~216


(15)		Represents 1,368,571 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(16)		Represents 26,986.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(17)		Represents 71,965.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(18)		Represents 26,986.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(19)		Represents 71,965.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(20)		Represents 495,238 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(21)		Represents 495,238 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(22)		Represents 495,238 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(23)		Represents 495,238 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(24)		Represents 52,569.4 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(25)		Represents 140,185.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(26)		Represents 52,569.4 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(27)		Represents 140,185.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(28)		Represents 596,133 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(29)		Represents 596,133 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(30)		Represents 596,133 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(31)		Represents 596,133 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(32)		Represents 26,986.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(33)		Represents 71,965.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(34)		Represents 26,986.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(35)		Represents 71,965.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

~~215~~217


(36)		Represents 495,238 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(37)		Represents 495,238 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(38)		Represents 495,238 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(39)		Represents 495,238 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(40)		Represents 19,462.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(41)		Represents 51,900.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(42)		Represents 19,462.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(43)		Represents 51,900.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(44)		Represents 552,381 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(45)		Represents 552,381 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006.

(46)		Represents 552,381 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

(47)		Represents 552,381 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006.

Equity Awards at 2007 Fiscal Year-End That Have Vested


	Stock Awards
	Number of
	Shares Acquired			Value Realized
	on Vesting			on Vesting
Name	(#)(1)(2)(3)			($)(4)

John J. Lipinski		39,477.3	(5)	$	1,516,323
		39,477.3	(6)	$	1,516,323
		53,921	(7)	$	1,078
James T. Rens		8,995.6	(8)	$	345,521
		8,995.6	(9)	$	345,521
		10,066	(10)	$	201
Stanley A. Riemann		17,523.1	(11)	$	673,062
		17,523.1	(12)	$	673,062
		19,650	(13)	$	393
Robert W. Haugen		8,995.6	(14)	$	345,521
		8,995.6	(15)	$	345,521
		10,066	(16)	$	201
Daniel J. Daly, Jr.		6,487.6	(17)	$	249,189
		6,487.6	(18)	$	249,189
		7,190	(19)	$	144

~~216~~218


(1)		The profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC generally vest as follows: operating units generally become non-forfeitable in 25% annual increments beginning on the second anniversary of the date of grant, and value units are generally forfeitable upon termination of employment. The profits interests are more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.”

(2)		The profits interests in Coffeyville Acquisition III LLC described in this table were granted on October 24, 2007 and automatically vested on the date of grant, as more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition III LLC.”

(3)		The phantom points granted pursuant to the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) are generally forfeitable upon termination of employment. The phantom points are more fully described above under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II).”

(4)		The dollar amounts shown are based on a valuation determined for purposes of SFAS 123(R) at the relevant vesting date of the respective override units.

(5)		Represents 39,477.3 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(6)		Represents 39,477.3 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family.

(7)		Represents profits interests in Coffeyville Acquisition III LLC (53,921 override units) granted to the executive on October 24, 2007.

(8)		Represents 8,995.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(9)		Represents 8,995.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(10)		Represents profits interests in Coffeyville Acquisition III LLC (10,066 override units) granted to the executive on October 24, 2007.

(11)		Represents 17,523.1 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(12)		Represents 17,523.1 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(13)		Represents profits interests in Coffeyville Acquisition III LLC (19,650 override units) granted to the executive on October 24, 2007.

(14)		Represents 8,995.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

(15)		Represents 8,995.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(16)		Represents profits interests in Coffeyville Acquisition III LLC (10,066 override units) granted to the executive on October 24, 2007.

(17)		Represents 6,487.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005.

~~217~~219


(18)		Represents 6,487.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005.

(19)		Represents profits interests in Coffeyville Acquisition III LLC (7,190 override units) granted to the executive on October 24, 2007.

Potential Payments Upon Termination or Change of Control

Under the terms of their respective employment agreements, the named executive officers may be entitled to severance and other benefits following the termination of their employment. These benefits are summarized below. The amounts of potential post-employment payments assume that the triggering event took place on December 31, 2007.

If Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in Mr. Lipinski’s employment 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. The estimated total amounts of these payments are set forth in the table below. As a condition to receiving the salary continuation and continuation of medical benefits, Mr. Lipinski must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. If Mr. Lipinski’s employment is terminated 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 (the estimated total amount of this payment is set forth in the table below). Such supplemental disability payments will be made in installments for a period of 36 months from the date of disability. If Mr. Lipinski’s employment is terminated at any time by reason of his death, then Mr. Lipinski’s beneficiary (or his estate) will be paid the base salary Mr. Lipinski would have received had he remained employed through the remaining term of his contract. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski’s supplemental disability payments or the payments due to Mr. Lipinski’s beneficiary or estate by reason of his death. Mr. Lipinski will be required to cooperate in obtaining such insurance. 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 “cut back” only if that reduction would be more beneficial to him on an after-tax basis than if there were no reduction.

The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure. The agreement also includes covenants relating to non-solicitation and non-competition during Mr. Lipinski’s employment term and, following the end of term, for as long as he is receiving severance or supplemental disability payments or one year if he is receiving none.

If the employment of Mr. Riemann, Mr. Rens, Mr. Haugen or Mr. Daly is terminated either by CVR Energy without cause and other than for disability or by the executive officer for good reason (as such terms are defined in the respective employment agreements), then the executive officer 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 officer becomes eligible for medical benefits from a subsequent employer. The amount of these payments is set forth in the table below. As a condition to receiving the salary, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code, as amended, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction.

~~218~~220

The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include covenants relating to non-solicitation and non-competition during their employment and, following termination of employment, for one year (for Mr. Riemann, the applicable period is during his employment and, following termination of employment, for as long as he is receiving severance, or one year if he is receiving none).

Below is a table setting forth the estimated aggregate amount of the payments discussed above assuming a December 31, 2007 termination date (and, where applicable, no offset due to eligibility to receive medical benefits from a subsequent employer). The table assumes that the executive officers’ termination was by CVR Energy without cause or by the executive officers for good reason, and in the case of Mr. Lipinski also provides information assuming his termination was due to his disability.


			Estimated Dollar
	Total Severance		Value of Medical
Name	Payments		Benefits

John J. Lipinski (severance if terminated without cause or resigns for good reason)	$	1,950,000	$	25,106
John J. Lipinski (supplemental disability payments if terminated due to disability)	$	650,000		—
Stanley A. Riemann (severance if terminated without cause or resigns for good reason)	$	525,000	$	12,553
James T. Rens (severance if terminated without cause or resigns for good reason)	$	250,000	$	11,998
Robert W. Haugen (severance if terminated without cause or resigns for good reason)	$	275,000	$	11,998
Daniel J. Daly, Jr. (severance if terminated without cause or resigns for good reason)	$	215,000	$	3,899

Equity Compensation Plan Information

The following table shows the total number of outstanding options and shares available for future issuances under our equity compensation plans as of December 31, 2007.

Number of Securities

Number of

Remaining Available

Securities to Be

for Future Issuance

Issued Upon

Weighted-Average

Under Equity

Exercise of

Exercise Price of

Compensation Plans

Outstanding

(Excluding Securities

Options, Warrants

Reflected in Lefthand

Plan Category

and Rights

Column)

Equity Compensation Plans Approved by Security Holders

18,900

21.61

7,463,600

Equity Compensation Plans Not Approved by Security Holders

—

Total

18,900

21.61

7,463,600

~~219~~221

Director Compensation for 2007

The following table provides compensation information for the year ended December 31, 2007 for each non-management director of our board.


	Fees
	Earned or		Stock		Option		All Other
Name	Paid in Cash		Awards(1)(2)		Awards(3)(4)(5)		Compensation			Total

Wesley K. Clark*	$	60,000		—		—	$	449,290(6	)	$	509,290
Regis B. Lippert	$	35,000	$	11,885	$	7,737		—		$	54,662
Mark E. Tomkins	$	75,000	$	29,714	$	7,737		—		$	112,451
Scott L. Lebovitz,George E. Matelich,Stanley de J. Osborne and Kenneth A. Pontarelli		—		—		—		—			—


*		Wesley K. Clark, who was first elected to the board of Coffeyville Acquisition LLC in 2006, advised the board that due to his various outside interests and responsibilities he did not want to be nominated for reelection. Steve A. Nordaker replaced Mr. Clark on our board effective June 6, 2008.


(1)		Mr. Lippert and Mr. Tomkins were awarded 5,000 and 12,500 shares of restricted stock, respectively, on October 22, 2007. The dollar amounts in the table reflect the dollar amounts recognized for financial statement reporting purposes for the fiscal year ended December 31, 2007 in accordance with SFAS 123(R). Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus.

(2)		The grant date fair value of stock awards granted during 2007, calculated in accordance with SFAS 123(R), was $104,400 for Mr. Lippert and $261,000 for Mr. Tomkins. Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus.

(3)		Mr. Lippert and Mr. Tomkins were awarded stock options in respect of (x) 5,150 shares each on October 22, 2007 and (y) 4,300 shares each on December 21, 2007. The amounts in the table reflect the dollar amount recognized for financial statement reporting purposes for the fiscal year ended December 31, 2007, in accordance with SFAS 123(R). Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus.

(4)		The grant date fair value of Mr. Lippert’s and Mr. Tomkins’ option awards granted during 2007, calculated in accordance with FAS 123(R), was $117,881 for each director. Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus.

(5)		The aggregate number of shares subject to option awards outstanding on December 31, 2007 was 9,450 for each of Messrs. Lippert and Tomkins.


(6)		Mr. Clark was awarded 244,038 phantom service points and 244,038 phantom performance points under the Coffeyville Resources, LLC Phantom Unit Plan (Plan I) in September 2005 for his services as a director. Collectively, Mr. Clark’s phantom points represent 2.44% of the total phantom points awarded. The value of the interest was $71,234 on the grant date. In accordance with SFAS 123(R), we apply a fair-value-based measurement method in accounting for share-based issuance of the phantom points. An independent third-party valuation was performed as of December 31, 2007 using the December 31, 2007 CVR Energy common stock closing price on the NYSE to determine the equity value of CVR Energy. Assumptions used in the calculation of these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. The phantom points are more fully described ~~below~~above under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II).”

~~220~~222

Non-employee directors who do not work principally for entities affiliated with us were entitled to receive an annual retainer of $60,000 for 2007. In addition, all directors are reimbursed for travel expenses and other out-of-pocket costs incurred in connection with their attendance at meetings. Effective January 1, 2007, Mark Tomkins joined our board of directors. Mr. Tomkins was elected as the chairman of the audit committee and in that role he receives an additional annual retainer of $15,000. Messrs. Lebovitz, Matelich, Osborne and Pontarelli received no compensation in respect of their service as directors in 2007.

In addition to the annual retainer described above, we granted to each of Mr. Tomkins and Mr. Lippert options to purchase 5,150 shares of CVR Energy with an exercise price equal to the initial public offering price ($19.00) on October 22, 2007. These options generally vest in one-third annual increments beginning on the first anniversary of the date of grant. We also granted 12,500 restricted shares of CVR Energy to Mr. Tomkins and 5,000 restricted shares of CVR Energy to Mr. Lippert on October 24, 2007. These shares of restricted stock generally vest in one-third annual increments beginning on the first anniversary of the date of grant, although the holder has the right to vote the shares whether or not they have vested. We also granted to each of Mr. Tomkins and Mr. Lippert options to purchase 4,300 shares of CVR Energy with an exercise price of $24.73 on December 21, 2007.

In connection with his election to our board of directors, we granted Mr. Nordaker options to purchase 4,350 shares of CVR Energy stock with an exercise price of $24.96 on June 10, 2008.

All grants were made pursuant to our 2007 Long Term Incentive Plan.

~~221~~223

PRINCIPAL STOCKHOLDERS

The following table presents information regarding beneficial ownership of our common stock 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; 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 the date of this prospectus are deemed to be outstanding and to be beneficially owned by the person holding such 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.

Shares Beneficially

Beneficial Owner
Owned
Name and Address

Number

Percent

Coffeyville Acquisition LLC(1) 31,433,360 36.5 %
Kelso Investment Associates VII, L.P.(1) 31,433,360 36.5 %
KEP Fertilizer, LLC(1) 31,433,360 36.5 %
320 Park Avenue, 24th Floor
New York, New York 10022
Coffeyville Acquisition II LLC(2) 31,433,360 36.5 %
The Goldman Sachs Group, Inc.(2) 31,433,360 36.5 %
85 Broad Street
New York, New York 10004
John J. Lipinski(3) 247,471 *
Stanley A. Riemann(4) — —
James T. Rens(5) — —
Robert W. Haugen(6) 5,000 *
Daniel J. Daly, Jr.(7) — —
Scott L. Lebovitz(2) 31,433,360 36.5 %
Regis B. Lippert(8) 7,500 *
George E. Matelich(1) 31,433,360 36.5 %
Steve A. Nordaker(9) — —
Stanley de J. Osborne(1) 31,433,360 36.5 %
Kenneth A. Pontarelli(2) 31,433,360 36.5 %
Mark Tomkins(10) 12,500 *
All directors and executive officers, as a group (16 persons)(11) 63,145,691 73.3 %


	Shares Beneficially
Beneficial Owner	Owned
Name and Address	Number		Percent

Coffeyville Acquisition LLC(1)		31,433,360		36.5	%
Kelso Investment Associates VII, L.P.(1)		31,433,360		36.5	%
KEP VI, LLC(1)		31,433,360		36.5	%
320 Park Avenue, 24th Floor New York, New York 10022
Coffeyville Acquisition II LLC(2)		31,433,360		36.5	%
The Goldman Sachs Group, Inc.(2)		31,433,360		36.5	%
85 Broad Street New York, New York 10004
John J. Lipinski(3)		247,471		*
Stanley A. Riemann(4)		—		—
James T. Rens(5)		—		—
Robert W. Haugen(6)		5,000		*
Daniel J. Daly, Jr.(7)		—		—
Scott L. Lebovitz(2)		31,433,360		36.5	%
Regis B. Lippert(8)		7,500		*
George E. Matelich(1)		31,433,360		36.5	%
Steve A. Nordaker(9)		—		—
Stanley de J. Osborne(1)		31,433,360		36.5	%
Kenneth A. Pontarelli(2)		31,433,360		36.5	%
Mark Tomkins(10)		12,500		*
All directors and executive officers, as a group (16 persons)(11)		63,145,691		73.3	%


*		Less than 1%.


(1)		Coffeyville Acquisition LLC directly owns 31,433,360 shares of common stock. Kelso Investment Associates VII, L.P. (“KIA VII”), a Delaware limited partnership, owns a number of common units in Coffeyville Acquisition LLC that corresponds to 24,557,883 shares of common stock, and KEP ~~Fertilizer,~~VI, LLC (“KEP ~~Fertilizer”~~VI”), a Delaware limited liability company, owns a number of common units in Coffeyville Acquisition LLC that corresponds to 6,081,000 shares of common stock. The Kelso Funds may be deemed to beneficially own indirectly, in the aggregate, all of the common stock of the Company owned by Coffeyville Acquisition LLC because the Kelso Funds control Coffeyville Acquisition LLC and have the power to vote or dispose of the common stock of the Company owned by Coffeyville Acquisition LLC. KIA VII and KEP ~~Fertilizer,~~VI, due to their common control, could be deemed to beneficially own each of the other’s shares but each disclaims such beneficial ownership. Messrs. Nickell, Wall, Matelich, Goldberg,

~~222~~224


		~~Matelich, Goldberg,~~ Bynum, Wahrhaftig, Berney, Loverro, Connors, Osborne and Moore may be deemed to share beneficial ownership of shares of common stock owned of record or beneficially owned by KIA VII, KEP ~~Fertilizer~~VI and Coffeyville Acquisition LLC by virtue of their status as managing members of KEP ~~Fertilizer~~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, Bynum, Wahrhaftig, Berney, Loverro, Connors, Osborne and Moore share investment and voting power with respect to the ownership interests owned by KIA VII, KEP ~~Fertilizer~~VI and Coffeyville Acquisition LLC but disclaim beneficial ownership of such interests.


(2)		Coffeyville Acquisition II LLC directly owns 31,433,360 shares of common stock. GS Capital Partners V Fund, L.P., GS Capital Partners V Offshore Fund, L.P., GS Capital Partners V GmbH & Co. KG and GS Capital Partners V Institutional, L.P. (collectively, the “Goldman Sachs Funds”) are members of Coffeyville Acquisition II LLC and own common units of Coffeyville Acquisition II LLC. The Goldman Sachs Funds’ common units in Coffeyville Acquisition II LLC correspond to 31,125,918 shares of common stock. The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. may be deemed to beneficially own indirectly, in the aggregate, all of the common stock owned by Coffeyville Acquisition II LLC through the Goldman Sachs Funds because (i) affiliates of Goldman, Sachs & Co. and The Goldman Sachs Group, Inc. are the general partner, managing general partner, managing partner, managing member or member of the Goldman Sachs Funds and (ii) the Goldman Sachs Funds control Coffeyville Acquisition II LLC and have the power to vote or dispose of the common stock of the Company owned by Coffeyville Acquisition II LLC. Goldman, Sachs & Co. is a direct and indirect wholly owned subsidiary of The Goldman Sachs Group, Inc. Goldman, Sachs & Co. is the investment manager of certain of the Goldman Sachs Funds. Shares that may be deemed to be beneficially owned by the Goldman Sachs Funds consist of: (1) 16,389,665 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Fund, L.P. and its general partner, GSCP V Advisors, L.L.C., (2) 8,466,218 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Offshore Fund, L.P. and its general partner, GSCP V Offshore Advisors, L.L.C., (3) 5,620,242 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Institutional, L.P. and its general partner, GSCP V Advisors, L.L.C., and (4) 649,793 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V GmbH & Co. KG and its general partner, Goldman, Sachs Management GP GmbH. Kenneth A. Pontarelli is a partner managing director of Goldman, Sachs & Co. and Scott L. Lebovitz is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, Mr. Lebovitz, 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.

(3)		Mr. Lipinski owns 247,471 shares of common stock directly. In addition, Mr. Lipinski owns 158,285 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Lipinski does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Lipinski also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested.” Such interests do not give Mr. Lipinski beneficial ownership of any shares of our common stock because they do not give Mr. Lipinski the power to vote or dispose of any such shares.

(4)		Mr. Riemann owns no shares of common stock directly. Mr. Riemann owns 97,408 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Riemann does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Riemann also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and

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		“Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested.” Such interests do not give Mr. Riemann beneficial ownership of any shares of our common stock because they do not give Mr. Riemann the power to vote or dispose of any such shares.

(5)		Mr. Rens owns no shares of common stock directly. Mr. Rens owns 60,879 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Rens does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Rens also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested.” Such interests do not give Mr. Rens beneficial ownership of any shares of our common stock because they do not give Mr. Rens the power to vote or dispose of any such shares.

(6)		Mr. Haugen owns 5,000 shares of common stock directly. Mr. Haugen owns 24,352 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Haugen does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Haugen also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested.” Such interests do not give Mr. Haugen beneficial ownership of any shares of our common stock because they do not give Mr. Haugen the power to vote or dispose of any such shares.

(7)		Mr. Daly owns no shares of common stock directly. Mr. Daly owns 12,176 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Daly does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Daly also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested.” Such interests do not give Mr. Daly beneficial ownership of any shares of our common stock because they do not give Mr. Daly the power to vote or dispose of any such shares.

(8)		In connection with our initial public offering, our board awarded 5,000 shares of non-vested restricted stock to Mr. Lippert. The date of grant for these shares of restricted stock was October 24, 2007. Under the terms of the restricted stock agreement, Mr. Lippert has the right to vote his shares of restricted stock after the date of grant. However, the transfer restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. Because Mr. Lippert has the right to vote his non-vested shares of restricted stock, he is deemed to have beneficial ownership of such shares. In addition, our board awarded Mr. Lippert options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price of our common stock, which was $19.00 per share. The date of grant for these options was October 22, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, our board awarded Mr. Lippert options to purchase 4,300 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.73. The date of grant for these options was December 21, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, members of Mr. Lippert’s immediate family own 2,500 shares of our common stock directly. Mr. Lippert disclaims beneficial ownership of shares of our common stock owned by members of his immediate family.

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(9)		In connection with joining our board in June 2008, our board awarded Mr. Nordaker options to purchase 4,350 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.96. The date of grant for these options was June 10, 2008. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant.

(10)		In connection with our initial public offering, our board awarded 12,500 shares of non-vested restricted stock to Mark Tomkins. The date of grant for these shares of restricted stock was October 24, 2007. Under the terms of the restricted stock agreement, Mr. Tomkins has the right to vote his shares of restricted stock after the date of grant. However, the transfer restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. Because Mr. Tomkins has the right to vote his non-vested shares of restricted stock, he is deemed to have beneficial ownership of such shares. In addition, our board awarded Mr. Tomkins options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price of our common stock, which was $19.00 per share. The date of grant for these options was October 22, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, our board awarded Mr. Tomkins options to purchase 4,300 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.73. The date of grant for these options was December 21, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant.

(11)		The number of shares of common stock owned by all directors and executive officers, as a group, reflects the sum of (1) all shares of common stock directly owned by Coffeyville Acquisition LLC, with respect to which Messrs. George Matelich and Stanley de J. Osborne may be deemed to share beneficial ownership, (2) all shares of common stock directly owned by Coffeyville Acquisition II LLC, with respect to which Messrs. Kenneth A. Pontarelli and Scott L. Lebovitz may be deemed to share beneficial ownership, (3) the 247,471 shares of common stock owned directly by Mr. John J. Lipinski, the 1,000 shares of common stock owned directly by Mr. Gross, the 5,000 shares of common stock owned directly by Mr. Haugen, the 3,500 shares of common stock owned directly by Mr. Jernigan, the 1,000 shares of common stock owned directly by Mr. Vick and the 1,000 shares of common stock owned directly by Mr. Swanberg, (4) the 12,500 shares owned by Mr. Tomkins and (5) the 5,000 shares owned by Mr. Lippert and the 2,500 shares owned by members of Mr. Lippert’s family.

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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

This section describes related party transactions between CVR Energy (and its predecessors) and its directors, executive officers and 5% stockholders. For a description of transactions between CVR Energy and the Partnership, whose managing general partner is owned by our controlling stockholders and senior management, see “The Nitrogen Fertilizer Limited Partnership.”

Transactions with the Goldman Sachs Funds and the Kelso Funds

Investments in Coffeyville Acquisition LLC

Prior to our initial public offering in October 2007, 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, or the Kelso Funds, were the majority owners of Coffeyville Acquisition LLC. Other members of Coffeyville Acquisition LLC were 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 our management team.

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.

On December 28, 2006, the directors of Coffeyville Acquisition LLC approved a cash dividend of $244,710,000 to companies related to the Goldman Sachs Funds and the Kelso Funds and $3,360,393 to certain members of our management team, including John J. Lipinski ($914,844), Stanley A. Riemann ($548,070), James T. Rens ($321,180), Kevan A. Vick ($321,180), Robert W. Haugen ($164,680) and Wyatt E. Jernigan ($164,680), as well as Wesley Clark ($241,205).

Split of Coffeyville Acquisition LLC

As part of the restructuring transactions that occurred immediately prior to our initial public offering, Coffeyville Acquisition LLC redeemed all of its outstanding common units held by the Goldman Sachs Funds in exchange for the same number of common units in Coffeyville Acquisition II LLC, a newly formed limited liability company to which Coffeyville Acquisition LLC transferred half of its interests in each of Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy. In addition, half of the common units and override units in Coffeyville Acquisition

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LLC held by each executive officer and Wesley Clark were redeemed in exchange for an equal number of common units and override units in Coffeyville Acquisition II LLC. As a result of these restructuring transactions, the Kelso Funds became the majority owner of Coffeyville Acquisition LLC and the Goldman Sachs Funds became the majority owner of Coffeyville Acquisition II LLC, and management and Wesley Clark retained an equivalent interest in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.

Stockholders Agreement

In October 2007, we entered into a stockholders agreement with Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Pursuant to the agreement, for so long as Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC collectively beneficially own in the aggregate an amount of our common stock that represents at least 40% of our outstanding common stock, Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC each have the right to designate two directors to our board of directors so long as that party holds an amount of our common stock that represents 20% or more of our outstanding common stock and one director to our board of directors so long as that party holds an amount of our common stock that represents less than 20% but more than 5% of our outstanding common stock. If Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC cease to collectively beneficially own in the aggregate an amount of our common stock that represents at least 40% of our outstanding common stock, the foregoing rights become a nomination right and the parties to the stockholders agreement are not obligated to vote for each other’s nominee. In addition, the stockholders agreement contains certain tag-along rights with respect to certain transfers (other than underwritten offerings to the public) of shares of common stock by the parties to the stockholders agreement. For so long as Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC beneficially own in the aggregate at least 40% of our common stock, (i) each such stockholder that has the right to designate at least two directors will have the right to have at least one of its designated directors on any committee (other than the audit committee and conflicts committee), to the extent permitted by SEC or NYSE rules, (ii) directors designated by the stockholders will be a majority of each such committee (at least 50% in the case of the compensation committee and the nominating committee), and (iii) the chairman of each such committee will be a director designated by such stockholder.

Registration Rights Agreements

In October 2007 we entered into a registration rights agreement with Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC pursuant to which we may be required to register the sale of our shares held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and permitted transferees. Under the registration rights agreement, the Goldman Sachs Funds and the Kelso Funds each have the right to request that we register the sale of shares held by Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, on their behalf on three occasions including requiring 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 Goldman Sachs Funds and the Kelso Funds have the ability to exercise certain piggyback registration rights with respect to their own securities if we elect to register any of our equity securities. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of our shares held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC are entitled to these registration rights.

Dividend

In connection with our initial public offering in October 2007, the directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively, approved a special dividend of approximately $10.6 million to their members, including $5,227,584 to the Goldman Sachs Funds, $5,145,787 to the Kelso Funds, $81,798 to Magnetite Asset Investors III L.L.C. and $103,269 to certain members of our senior management team and Wesley K. Clark. The common unitholders receiving this special dividend then contributed approximately $10.6 million collectively to Coffeyville

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Acquisition III LLC, which used such amounts to acquire CVR GP, LLC, the managing general partner of the Partnership, from us.

J. Aron & Company

In June 2005 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 “Cash Flow Swap”). These agreements were assigned to Coffeyville Resources, LLC, a subsidiary of the Company, on June 24, 2005. Based on crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility (the “Credit Facility”), upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, ~~so long as~~ at which time the ~~time of reduction or termination, we pay the amount of~~ unrealized ~~losses associated with the amount reduced or terminated.~~loss would become a fixed obligation. The Cash Flow Swap has resulted in unrealized gains (losses) of approximately $(235.9) million, $126.8 million and $(103.2) million for the years ended December 31, 2005, 2006 and 2007, respectively. We paid J. Aron $52.4 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2008. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Critical Accounting Policies — Derivative Instruments and Fair Value of Financial Instruments” and “Description of Our Indebtedness and the Cash Flow Swap — Cash Flow Swap.”

As a result of the flood and the temporary cessation of our Company’s operations on June 30, 2007, Coffeyville Resources, LLC ~~was required to enter~~entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 and then to August 31, 2008 the payment of approximately $123.7 million plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008) which we owed to J. Aron. We ~~are required to use 37.5% of our consolidated excess cash flow for any quarter after January 31,~~entered into a letter agreement with J. Aron on July 29, 2008 to ~~prepay~~defer until December 15, 2008 the ~~deferred amounts, but as of March 31, 2008 we were not required to prepay any portion of the deferred amount. We are in the process of negotiating a deferral~~payment of $87.5 million of ~~these amounts owed~~the $123.7 million plus accrued interest we owe to J. ~~Aron until~~Aron. Interest will accrue on the deferred amounts from August 31, 2008 to the date of payment at a rate of LIBOR plus 2.75%, and we are required to prepay the deferral amount each quarter with the greater of 50% of the Company’s free cash flow or $5.0 million. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at our option). If we consummate this notes offering before December 15, 2008, the $87.5 million deferral will automatically extend to July 31, 2009. Under the terms of the ~~proposed~~ deferral of $87.5 million of the amounts owed to J. Aron, we ~~will be~~are required to use the substantial majority of any gross proceeds from any indebtedness we incur during the deferral period in excess of $125.0 million, including all of the gross proceeds received from the sale of ~~this offering,~~notes issued in connection with the exercise by the underwriters of the over-allotment option net of fees, to prepay a portion of the deferred ~~amounts. We cannot assure you that~~amounts owed to J. Aron.

In June 2005 Coffeyville Acquisition LLC also entered into three interest-rate swap agreements with J. Aron (the “Interest Rate Swap”). Under the ~~new deferral agreement will be consummated.~~Interest Rate Swap, we pay a fixed rate of 4.195% and receive floating rates based on three-month LIBOR rates, with payments calculated on a notional amount of $250.0 million through March 30, 2009, $180.0 million from March 31, 2009 through March 30, 2010 and $110.0 million from March 31, 2010 through June 29, 2011. The Interest Rate Swap has resulted in gain (loss) on derivatives of approximately $3.8 million, $1.8 million and $(2.4) million for the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.

During 2007 we were party to a crude oil supply agreement with J. Aron. On December 31, 2007, we entered into an amended and restated crude oil supply agreement with J. Aron. The terms of the agreement provide that we will obtain all of the crude oil for our refinery through J. Aron, other than crude oil that we acquire in Kansas, Missouri, Oklahoma, Wyoming and all states adjacent thereto. Pursuant to the agreement, we identify crude oil and pricing terms that meet our requirements and from time to time notify J. Aron of sourcing opportunities that we deem acceptable. We and/or J.

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Aron negotiate the cost of each barrel of crude oil that is purchased from third party crude oil suppliers. J. Aron executes all third party sourcing transactions and provides transportation and other logistical services for the crude oil it delivers to us. We generally pay J. Aron a fixed supply service fee per barrel over the negotiated cost of each barrel of crude oil purchased. In some cases, J. Aron will sell crude oil directly to us without having executed a specific third party sourcing transaction.

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 a gain (loss) on derivatives for the 233 days ended December 31, 2005.

As a result of the refinery turnaround in early 2007, we needed to delay the processing of quantities of crude oil that we purchased from various small independent producers. In order to facilitate this anticipated delay, we entered into a purchase, storage and sale agreement for gathered

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crude oil, dated March 20, 2007, with J. Aron. Pursuant to the terms of the agreement, J. Aron agreed to purchase gathered crude oil from us, store the gathered crude oil and sell us the gathered crude oil on a forward basis. This agreement is no longer in effect.

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. Payments relating to the consulting and advisory agreements include $1,310,416, $2,315,937 and $1,703,990 which was expensed in selling, general, and administrative expenses for the 233 days ended December 31, 2005, the year ended December 31, 2006 and the year ended December 31, 2007, respectively. These agreements were terminated in connection with our initial public offering in October 2007 and each of Goldman, Sachs & Co. and Kelso & Company, L.P. received a one-time fee of $5 million by reason of such termination in conjunction with the offering.

Credit Facilities

Goldman Sachs Credit Partners L.P., an affiliate of Goldman, Sachs & Co., or Goldman Sachs, is one of the lenders under the Credit Facility. Goldman Sachs Credit Partners is also a joint lead arranger and bookrunner under the Credit Facility. In addition, Goldman Sachs Credit Partners L.P. was the sole arranger and sole bookrunner of the $25.0 million secured facility, the $25.0 million unsecured facility, and the $75.0 million unsecured facility, each of which was terminated in connection with the consummation of our initial public offering in October 2007. Goldman Sachs Credit Partners was also a lender, sole lead arranger, sole bookrunner and syndication agent under our first lien credit agreement and a lender and joint lead arranger, joint bookrunner and syndication agent under our second lien credit agreement. The first lien credit agreement and second lien credit agreement were entered into in connection with the acquisition of Coffeyville Group Holdings, LLC and its subsidiaries by Coffeyville Acquisition LLC in June 2005. At that time, we paid this Goldman Sachs affiliate a $22.1 million fee included in deferred financing costs. In conjunction with the financing that occurred on December 28, 2006, we paid approximately $8.1 million to a Goldman Sachs affiliate. Additionally, in conjunction with entering into the $25.0 million secured facility, the $25.0 million unsecured facility, and the $75.0 million unsecured facility on August 23, 2007, we paid approximately $1.3 million in fees and associated expense reimbursement to a Goldman Sachs affiliate. 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.”

Guarantees

During 2007 one of the Goldman Sachs Funds and one of the Kelso Funds each guaranteed 50% of our payment obligations under the Cash Flow Swap in the amount of $123.7 million, plus accrued interest ($~~6.2~~6.7 million as of ~~July~~August 1, 2008). These guarantees were reaffirmed in connection

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with the $87.5 million deferral agreement we entered into on July 29, 2008 and remain in effect as of the date of this prospectus. ~~The new deferral agreement we are in the process of negotiating with J. Aron will require that these guarantees remain in effect until the deferred amounts have been repaid.~~

In addition, in August 2007 these funds also guaranteed our obligations under the $25.0 million secured facility, the $25.0 million unsecured facility and the $75.0 million unsecured facility. These guarantees were terminated when the credit facilities were repaid and terminated in connection with the consummation of our initial public offering in October 2007.

Initial Public Offering and Proposed Common Stock Offering

Goldman, Sachs & Co. was the lead underwriter of our initial public offering in October 2007. Goldman, Sachs & Co. was paid a customary underwriting discount for serving as underwriter. Goldman, Sachs & Co. is also the lead underwriter for the proposed secondary offering by certain of our stockholders, who have elected not to proceed with that offering at this time but may do so in the future.

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Transactions with Directors and Senior Management

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. Mr. Lipinski repaid $150,000 of principal and paid $17,643.84 in interest on January 13, 2006. The unpaid loan balance of $350,000, together with accrued and unpaid interest of $17,989, was forgiven in full in September 2006.

On December 28, 2006, the directors of Coffeyville Nitrogen Fertilizers, Inc. approved the issuance of shares of common stock of Coffeyville Nitrogen Fertilizers, Inc., par value $0.01 per share, to John J. Lipinski in exchange for $10.00 pursuant to a Subscription Agreement. Mr. Lipinski also entered into a Stockholders Agreement with Coffeyville Nitrogen Fertilizers, Inc. and Coffeyville Acquisition LLC at the same time he entered into the Subscription Agreement. Pursuant to the Stockholders Agreement, among other things, Coffeyville Acquisition LLC had the right to exchange all shares of common stock in Coffeyville Nitrogen Fertilizers, Inc. held by Mr. Lipinski for such number of common units of Coffeyville Acquisition LLC or equity interests of a wholly-owned subsidiary of Coffeyville Acquisition LLC, in each case having a fair market value equal to the fair market value of the common stock in Coffeyville Nitrogen Fertilizers, Inc. held by Mr. Lipinski.

On December 28, 2006, the directors of Coffeyville Refining & Marketing, Inc. approved the issuance of shares of common stock of Coffeyville Refining & Marketing, Inc., par value $0.01 per share, to John J. Lipinski in exchange for $10.00 pursuant to a Subscription Agreement. Mr. Lipinski entered into a stockholders agreement with Coffeyville Refining & Marketing, Inc. similar to the agreement he entered into with Coffeyville Nitrogen Fertilizers, Inc.

In August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. Mr. Lipinski also entered into a Stockholders Agreement with Coffeyville Refining & Marketing Holdings, Inc. and Coffeyville Acquisition LLC at the time of the exchange. Pursuant to the Stockholders Agreement, among other things, Coffeyville Acquisition LLC had the right to exchange all shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. held by Mr. Lipinski for such number of common units of Coffeyville Acquisition LLC or equity interests of a wholly-owned subsidiary of Coffeyville Acquisition LLC, in each case having a fair market value equal to the fair market value of the common stock in Coffeyville Refining & Marketing Holdings, Inc. held by Mr. Lipinski.

In October 2007, prior to our initial public offering, we entered into a subscription agreement with Mr. Lipinski pursuant to which Mr. Lipinski agreed to exchange his shares of common stock of Coffeyville Nitrogen Fertilizers, Inc. and Coffeyville Refining & Marketing Holdings, Inc. for shares of our common stock. In accordance with this agreement, we issued 247,471 shares of common stock to Mr. Lipinski. Prior to that stock issuance, Mr. Lipinski owned approximately 0.3128% of Coffeyville Refining and Marketing Holdings, Inc. and approximately 0.6401% of Coffeyville Nitrogen Fertilizer, Inc. These two companies owned all of the interests which became owned by CVR Energy upon the

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completion of its initial public offering. The allocation of value as of September 30, 2007 between Coffeyville Refining and Marketing Holdings, Inc. and Coffeyville Nitrogen Fertilizer, Inc. was 75.7717% and 24.2283%, respectively. The allocation of value was based on the two entities respective ownership interest in their subsidiaries taking into effect liabilities and receivables existing between the two companies. The number of shares issued to Mr. Lipinski was determined by grossing up the shares after our stock split by the weighted average percentage ownership of Mr. Lipinski in the two entities and multiplying the result by Mr. Lipinski’s weighted average percentage ownership. The table below illustrates the calculations of the shares issued to Mr. Lipinski.

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	Relative ownership in all interests contributed to CVR Energy
A	Coffeyville Refining and Marketing Holdings, Inc.	75.7717	%
B	Coffeyville Nitrogen Fertilizer, Inc.	24.2283	%
	Mr. Lipinski’s Interests in the subsidiaries
D	Coffeyville Refining and Marketing Holdings, Inc.	0.3128	%
E	Coffeyville Nitrogen Fertilizer, Inc.	0.6401	%
	Weighted average ownership in all assets
F: = A x D	Coffeyville Refining and Marketing Holdings, Inc.	0.23701	%
G: = B x E	Coffeyville Nitrogen Fertilizer, Inc.	0.15509	%
H: = F + G	Mr. Lipinski’s weighted average ownership interest	0.3921	%
I	Original shares	100.00
J	Stock split	628,667.20
K: = I x J	Shares to members of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC	62,866,720.00
L: = H x ( K/(1-H))	Mr. Lipinski’s shares	247,471.00
M: = K + L	Total shares before director shares, our initial public offering and employee shares	63,114,191
N: = L/M	Mr. Lipinski’s percentage of pre-offering shares	0.3921	%

As a record holder of CVR Energy common stock on October 16, 2007, Mr. Lipinski received a dividend of $41,562 as part of a $10.6 million dividend approved by CVR Energy’s board of directors in October 2007.

All decisions concerning Mr. Lipinski’s compensation were approved by the compensation committee of Coffeyville Acquisition LLC without Mr. Lipinski’s participation.

Registration Rights Agreement

In October 2007, we entered into a registration rights agreement with John J. Lipinski. Under the registration rights agreement, Mr. Lipinski will have the ability to exercise certain piggyback registration rights with respect to his own securities if any of our equity securities are offered to the public pursuant to a registration statement. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of the shares in our company held directly by John J. Lipinski are entitled to these registration rights.

Wesley Clark Consulting Agreement

In connection with his retirement from our board of directors, we entered into a consulting agreement with General Wesley Clark whereby Mr. Clark will provide consulting and advisory services to us for a two year period in exchange for a monthly retainer of $2,000. As a member of the board of directors, Mr. Clark had been granted 244,038 Phantom Performance Points and 244,038 Phantom Services Points (together, the “Points”) under the Coffeyville Resources, LLC Phantom Unit Plan. Upon his leaving the board, Mr. Clark forfeited these Points. As additional compensation for his services as a consultant, Mr. Clark will receive a payment equal to the amounts that would have been distributed to Mr. Clark in respect of 65% of his Points had he continued to hold them during the period beginning on the annual meeting date and ending on the earlier of (i) December 1, 2010 or (ii) the date of the consummation of an Exit Event (as defined in the Coffeyville Acquisition LLC Limited Liability Company Agreement) (but no earlier than January 15, 2009) (the “Payment Date”). In addition, Mr. Clark will receive the amount that would have been distributed in respect of 65% of his

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Points on the Payment Date assuming that (i) Mr. Clark remained on the board, (ii) all of the common stock of the Company then held by Coffeyville Acquisition LLC and Coffeyville Acquisition LLC II was sold at the closing price of common stock on the New York Stock Exchange on such Payment Date and (iii) the proceeds were distributed to the members of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC on such Payment Date pursuant to the LLC Agreements of each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.

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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 $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 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

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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

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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

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.

Other Transactions

We paid INTERCAT, Inc. $525,507 during 2006 for chemical additives. Mr. Regis B. Lippert, a director of our company, is the principal shareholder and chief executive officer of INTERCAT, Inc. Mr. John J. Lipinski, the chief executive officer and president of our company and a member of our board of directors, is a director and member of the compensation committee of INTERCAT, Inc.

Related Party Transaction Policy

Our board of directors has adopted a Related Party Transaction Policy, which is designed to monitor and ensure the proper review, approval, ratification and disclosure of related party transactions involving us. This policy applies to any transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) in which we were, are or will be a participant and the amount involved exceeds $100,000, and in which any related party had, has or will have a direct or indirect material interest. The audit committee of our board of directors must review, approve and

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ratify a related party transaction if such transaction is consistent with the Related Party Transaction Policy and is on terms, taken as a whole, which the audit committee believes are no less favorable to us than could be obtained in an arms-length transaction with an unrelated third party, unless the audit committee otherwise determines that the transaction is not in our best interests. Any related party transaction or modification of such transaction which our board of directors has approved or ratified by the affirmative vote of a majority of directors, who do not have a direct or indirect material interest in such transaction, does not need to be approved or ratified by our audit committee. In addition, related party transactions involving compensation will be approved by our compensation committee in lieu of our audit committee.

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Conflicts of Interests Policy for Transactions between the Partnership and Us

Our board of directors has also adopted a Conflicts of Interests Policy, which is designed to monitor and ensure the proper review, approval, ratification and disclosure of transactions between the Partnership and us. The policy applies to any transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) between us or any of our subsidiaries, on the one hand, and the Partnership, its managing general partner and any subsidiary of the Partnership, on the other hand. According to the policy, all such transactions must be fair and reasonable to us. If such transaction is expected to involve a value, over the life of such transaction, of less than $1 million, no special procedures will be required. If such transaction is expected to involve a value of more than $1 million but less than $5 million, it is deemed to be fair and reasonable to us if (i) such transaction is approved by the conflicts committee of our board of directors, (ii) the terms of such transaction are no less favorable to us than those generally being provided to or available from unrelated third parties or (iii) such transaction, taking into account the totality of any other such transaction being entered into at that time between the parties involved (including other transaction that may be particularly favorable or advantageous to us), is equitable to CVR Energy. If such transaction is expected to involve a value, over the life of such transaction, of $5 million or more, it is deemed to be fair and reasonable to us if it has been approved by the conflicts committee of our board of directors.

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THE NITROGEN FERTILIZER LIMITED PARTNERSHIP

Background

In June 2007, we created a new limited partnership, CVR Partners, LP, or the Partnership. In October 2007, prior to our initial public offering, we transferred our nitrogen fertilizer business to this Partnership. The Partnership initially had three partners: a managing general partner, CVR GP, LLC, which we owned; a special general partner, CVR Special GP, LLC, which we owned; and a limited partner, Coffeyville Resources, LLC. We sold the managing general partner for $10.6 million to Coffeyville Acquisition III LLC, a newly created entity owned by the Goldman Sachs Funds, the Kelso Funds, our executive officers, Mr. Wesley Clark, Magnetite Asset Investors III L.L.C. and other members of our senior management team.

In connection with the creation of the Partnership, CVR GP, LLC, as the managing general partner, Coffeyville Resources, LLC, as the limited partner, and CVR Special GP, LLC, as a general partner, entered into a limited partnership agreement which set forth the various rights and responsibilities of the partners in the Partnership. In addition, we entered into a number of intercompany agreements with the Partnership and the managing general partner which regulate certain business relations among us, the Partnership and the managing general partner.

Contribution, Conveyance and Assumption Agreement

In October 2007, the Partnership entered into a contribution, conveyance and assumption agreement, or the contribution agreement, with the Partnership’s managing general partner, CVR Special GP, LLC (our subsidiary that holds a general partner interest in the Partnership), and Coffeyville Resources, LLC (our subsidiary that holds a limited partner interest in the Partnership). Pursuant to the contribution agreement, Coffeyville Resources, LLC transferred our subsidiary that owns the nitrogen fertilizer business to the Partnership in exchange for (1) the issuance to CVR Special GP, LLC of 30,303,000 special GP units, representing a 99.9% general partner interest in the Partnership, (2) the issuance to Coffeyville Resources, LLC of 30,333 special LP units, representing a 0.1% limited partner interest in the Partnership, (3) the issuance to the managing general partner of the managing general partner interest in the Partnership and (4) the agreement by the Partnership, contingent upon the Partnership consummating an initial public or private offering, to reimburse us for capital expenditures we incurred during the two year period prior to the sale of the managing general partner to Coffeyville Acquisition III LLC, in connection with the operations of the fertilizer plant (currently estimated to be $18.4 million). The Partnership assumed all liabilities arising out of or related to the ownership of the nitrogen fertilizer business to the extent arising or accruing on and after the date of transfer.

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Sale of Managing General Partner to Coffeyville Acquisition III LLC

Following formation of the Partnership pursuant to the contribution agreement in October 2007, the following entities and individuals contributed the following amounts in cash to Coffeyville Acquisition III LLC, a newly formed entity owned by our controlling stockholders and executive officers. Coffeyville Acquisition III LLC used these contributions to purchase the managing general partner of the Partnership from us:


Contributing Parties	Amount Contributed

The Goldman Sachs Funds	$	5,227,584
The Kelso Funds		5,145,787
John J. Lipinski		68,146
Stanley A. Riemann		16,359
James T. Rens		10,225
Edmund S. Gross		1,227
Robert W. Haugen		4,090
Wyatt E. Jernigan		4,090
Kevan A. Vick		10,225
Christopher G. Swanberg		1,022
Daniel J. Daly, Jr.		2,045
Wesley Clark		10,225
Others		98,975
Total Contribution	$	10,600,000

Coffeyville Acquisition III purchased the managing general partner from us for $10.6 million, which our board of directors determined, after consultation with management, represented the fair market value of the managing general partner of the Partnership at that time. The valuation of the managing general partner interest was based on a discounted cash flow analysis, using a discount rate commensurate with the risk profile of the managing general partner interest. The key assumptions underlying the analysis were commodity price projections, which were used to estimate the Partnership’s raw material costs and output revenues. Other business expenses of the Partnership were estimated based on management’s projections. The Partnership’s cash distributions were assumed to be flat at expected forward fertilizer prices, with cash reserves developed in periods of high prices and cash reserves reduced in periods of lower prices. The Partnership’s projected cash distributions to the managing general partner under the terms of the Partnership’s partnership agreement used for the valuation were modeled based on the structure of the Partnership, the managing general partner’s incentive distribution rights (“IDRs”) and management’s expectations of the Partnership’s operations, including production volumes and operating costs, which were developed by management based on historical experience. As commodity price curve projections were key assumptions in the discounted cash flow analysis, alternative price curve projections were considered in order to test the reasonableness of these assumptions, which gave management an added level of assurance as to such reasonableness. Price projections were based on information received from Blue Johnson and Associates, a fertilizer industry consultant in the United States which we routinely use for fertilizer market analysis. There can be no assurance that the value of the managing general partner will not differ in the future from the amount initially paid for it.

February 2008 Filing ofForm S-1 by CVR Partners, LP

On February 28, 2008, the Partnership filed aForm S-1 registration statement (the “PartnershipS-1”) with the SEC for an initial public offering (the “Partnership Offering”) of common units representing limited partner interests in the Partnership. On June 13, 2008, the Company announced that the managing general partner of the Partnership had decided that it would postpone indefinitely the Partnership’s initial public offering. The Partnership may elect to move forward with a public or private offering in the future.

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Description of Partnership Interests Initially Following Formation

The partnership agreement provides that initially the Partnership has three types of partnership interests: (1) special GP units, representing special general partner interests, which are owned by the special general partner, (2) special LP units, representing a limited partner interest, which are owned by Coffeyville Resources, LLC, and (3) a managing general partner interest which has associated IDRs which are held by the managing general partner.

Special Units. The special units include special GP units and special LP units. We indirectly own all 30,303,000 special GP units and all 30,333 special LP units. The special GP units are special general partner interests giving the holder thereof specified joint management rights (which we refer to as special GP rights), including rights with respect to the appointment, termination and compensation of the chief executive officer and the chief financial officer of the managing general partner, and entitling the holder to participate in Partnership distributions and allocations of income and loss. Special LP units have identical voting and distribution rights as the special GP units, but represent limited partner interests in the Partnership and do not give the holder thereof the special GP rights.

In accordance with the partnership agreement, the special units are entitled to payment of a set target distribution of $0.4313 per unit ($13.1 million in the aggregate for all our special units each quarter), or $1.7252 per unit on an annualized basis ($52.3 million in the aggregate for all our special units annually), prior to the payment of any quarterly distribution in respect of the IDRs. For more information on cash distributions to the special units and the IDRs please see “— Cash Distributions by the Partnership”. We are permitted to sell the special units at any time without the consent of the managing general partner, subject to compliance with applicable securities laws, but upon any sale of special GP units to an unrelated third party the special GP rights will no longer apply to such units.

Managing General Partner Interest. The managing general partner interest, which is held solely by the managing general partner, entitles the holder to manage (subject to our special GP rights) the business and operations of the Partnership, but does not entitle the holder to participate in Partnership distributions or allocations except in respect of associated IDRs. IDRs represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the target distribution ($0.4313 per unit per quarter) has been paid and following distribution of the aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 to the special unitsand/or the common and subordinated units (if issued). In addition, there can be no distributions paid on the managing general partner’s IDRs for so long as the Partnership or its subsidiaries are guarantors under our Credit Facility. The IDRs are not transferable apart from the general partner interest. The managing general partner can be sold without the consent of other partners in the Partnership.

Provisions Regarding an Initial Offering by the Partnership

Under the partnership agreement, the managing general partner has the sole discretion to cause the Partnership to undertake an initial private or public offering, subject to our joint management rights (as holder of the special GP rights, described below) if the offering involves the issuance of more than $200 million of the Partnership’s interests (exclusive of the underwriters’ option, if any). There is no assurance that the Partnership will undertake or consummate a public or private offering.

Under the contribution agreement, if Fertilizer GP elects to cause the Partnership to undertake an initial private or public offering (in either case, the Partnership’s “initial offering”), Fertilizer GP must give prompt notice to us of such election and the proposed terms of the offering. We have agreed to use our commercially reasonable efforts to take such actions as Fertilizer GP reasonably requests in order to effectuate and permit the consummation of the offering. We have agreed that Fertilizer GP may structure the initial offering to include (1) a secondary offering of interests by us or (2) a primary offering of interests by the Partnership, possibly together with an incurrence of indebtedness by the Partnership, where a use of proceeds is to redeem units from us (with aper-unit redemption price equal to the price at which each unit is purchased from the Partnership, net of sales commissions or underwriting discounts) (a “special GP offering”), provided that in either case the number of units

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associated with the special GP offering is reasonably expected by Fertilizer GP to generate no more than $100 million in net proceeds to us (exclusive of the underwriters’ option, if any). The special GP offering may not be consummated without our consent if the net proceeds to us are less than $10 per unit. If the initial public offering includes a special GP offering, unless we otherwise agree with the Partnership, the special GP offering will be increased to cover our pro rata portion of any exercise of the underwriters’ option, if any.

Under the contribution agreement, if Fertilizer GP reasonably determines that, in order to consummate the initial offering, it is necessary or appropriate for the Partnership and its subsidiaries to be released from their obligations under our Credit Facility and our swap arrangements with J. Aron, then Fertilizer GP must give prompt written notice to us describing the requested amendments. The notice must be given 90 days prior to the anticipated closing date of the initial offering. We will be required to use our commercially reasonable efforts to effect the releases or amendments. We will not be considered to have made “commercially reasonable efforts” if we do not effect such requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested modifications, we may require that (1) the initial offering include a special GP offering generating at least $140 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering.

If the Partnership consummates an initial public or private offering and we sell units, or our units are redeemed, in a special GP offering, or the Partnership makes a distribution to us of proceeds of the offering or debt financing, such sale, redemption or distribution would likely result in taxable gain to us and such taxable gain could be significant. If the Partnership consummates an initial public or private offering, regardless of whether we sell units, the distributions that we receive from the Partnership could decrease because the Partnership’s distributions will be shared with the new limited partners. Additionally, when the Partnership issues units or engages in certain other transactions, the Partnership will determine the fair market value of its assets and allocate any unrealized gain or loss attributable to those assets to the capital accounts of the existing partners. As a result of this revaluation and the Partnership’s adoption of the remedial allocation method under Section 704(c) of the Internal Revenue Code (i) new unitholders will be allocated deductions as if the tax basis of the Partnership’s property were equal to the fair market value thereof at the time of the offering, and (ii) we will be allocated “reverse Section 704(c) allocations” of income or loss over time consistent with our allocation of unrealized gain or loss.

If the Partnership consummates an initial offering as either a primary or secondary offering, our special units, other than those sold or redeemed in a special GP offering, if any, will be converted into a combination of (1) common units and (2) subordinated units. The special units will be converted into common units and subordinated units, on a one-for-one basis, such that the lesser of (1) 40% of all outstanding units after the initial offering (prior to the exercise of the underwriters’ option, if any) and (2) all of the units owned by us, will be subordinated. For a description of the common units and subordinated units please see “— Description of Partnership Interests Following Initial Offering”. The special GP units will convert into common GP units or subordinated GP units and the special LP units will convert into common LP units or subordinated LP units.

The following table sets forth the number of special GP units and special LP units that are currently outstanding and illustrates the number of common GP units, subordinated GP units, common LP units and subordinated LP units we will own, as well as the number of common LP units that public unitholders will own, assuming the Partnership’s initial offering involves a total of 10 million common LP units, 7 million of which are our special units (converted into common LP units immediately prior to sale directly in the initial offering, or redeemed using the proceeds from the issuance of common LP

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units by the Partnership) and 3 million of which are new common LP units. The following table assumes that the 7 million of our special units sold or redeemed reduce our special LP units and special GP units pro rata (i.e., 99.9% from our special GP units and 0.1% from our special LP units). This information is presented for illustrative purposes only. There can be no assurance the Partnership will undertake an initial offering consistent with these assumptions or at all.


	Initial	Following Partnership Initial Offering
	Special Units	Common Units	Subordinated Units

Owned by us	30,303,000	9,990,000	13,320,000
	special GP	common GP	subordinated GP
	units	units	units
	30,333	10,000	13,333
	special LP	common LP	subordinated LP
	units	units	units
Owned by public	—	10,000,000	—
		common LP
		units

The partnership agreement prohibits Fertilizer GP from causing the Partnership to undertake or consummate an initial offering unless the board of directors of Fertilizer GP determines, after consultation with us, that the Partnership will likely be able to earn and pay the minimum quarterly distribution (which is currently set at $0.375 per unit) on all units for each of the two consecutive, nonoverlapping four-quarter periods following the initial offering. As an illustration, the Partnership would need to earn and pay $50 million during each of the two consecutive, nonoverlapping four-quarter periods based upon the number of units (i.e., 33,333,333 total units) in the hypothetical illustrated in the table above. If Fertilizer GP determines that the Partnership is not likely to be able to earn and pay the minimum quarterly distribution for such periods, Fertilizer GP may, in its sole discretion and effective upon closing of the initial offering, reduce the minimum quarterly distribution to an amount it determines to be appropriate and likely to be earned and paid during such periods.

The contribution agreement also provides that if the initial offering is not consummated by October 24, 2009, Fertilizer GP can require us to purchase the managing general partner interest. This put right expires on the earlier of (1) October 24, 2012 and (2) the closing of the Partnership’s initial offering. If the Partnership’s initial offering is not consummated by October 24, 2012, we have the right to require Fertilizer GP to sell the managing general partner interest to us. This call right expires on the closing of the Partnership’s initial offering. In the event of an exercise of a put right or a call right, the purchase price will be the fair market value of the managing general partner interest at the time of purchase. The fair market value will be determined by an independent investment banking firm selected by us and Fertilizer GP. The independent investment banking firm may consider the value of the Partnership’s assets, the rights and obligations of Fertilizer GP and other factors it may deem relevant but the fair market value shall not include any control premium. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — If the Partnership does not consummate an initial offering by October 24, 2009, Fertilizer GP can require us to purchase its managing general partner interest in the Partnership. We may not have requisite funds to do so.”

Description of Partnership Interests Following Initial Offering

Common Units. The common units, if issued, will be comprised of common GP units and common LP units. The common GP units will be special general partner interests giving the holder special GP rights (described above), including rights with respect to the appointment, termination and compensation of the chief executive officer and the chief financial officer of the managing general partner, and entitling the holder to participate in Partnership distributions and allocations on a pro rata basis with common LP units. Common LP units will have identical voting and distribution rights as the common GP units, but will represent limited partner interests in the Partnership and will not give the

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holder thereof special GP rights. The common units will be entitled to payment of the minimum quarterly distribution prior to the payment of any quarterly distribution on the subordinated units or the IDRs. For more information of the rights and preferences of holders of the common units, subordinated units and IDRs in the Partnership’s distributions, please see “— Cash Distributions by the Partnership.”

We will be permitted to sell the common units we own at any time without the consent of the managing general partner, subject to compliance with applicable securities laws. The common GP units will automatically convert to common LP units immediately prior to sale thereof to an unrelated third party. The common GP units will automatically convert into common LP units (with no special GP rights) immediately if the holder of the common GP units, together with all of its affiliates, ceases to own 15% or more of all units of the Partnership (not including the managing general partner interest).

Subordinated Units. The subordinated units, if issued, will be comprised of subordinated GP units and subordinated LP units. The subordinated GP units will be special general partner interests giving the holder special GP rights. Subordinated LP units will have identical voting and distribution rights as the subordinated GP units, but will represent limited partner interests in the Partnership and will not give the holder thereof special GP rights. The subordinated units will entitle the holder to participate in Partnership distributions and allocations on a subordinated basis to the common units (as described in “— Cash Distributions by the Partnership”). During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the set minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. As a result, if the Partnership consummates an initial offering, the portion of our special units that are converted into subordinated units will be subordinated to the common units and may not receive distributions unless and until the common units have received the minimum quarterly distribution, plus any accrued and unpaid arrearages in the minimum quarterly distribution from prior quarters. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest In the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest In the Nitrogen Fertilizer Business — If the Partnership completes a public offering or private placement of limited partner interests, our voting power in the Partnership would be reduced and our rights to distributions from the Partnership could be materially adversely affected.”

We will be permitted to sell the subordinated units we own at any time without the consent of the managing general partner, subject to compliance with applicable securities laws. The subordinated units will automatically convert into common units on the second day after the distribution of cash in respect of the last quarter in the subordination period (which will end no earlier than five years after the initial offering), although up to 50% may convert earlier. The subordinated GP units will automatically convert to subordinated LP units immediately prior to sale thereof to an unrelated third party. The subordinated GP units will automatically convert into subordinated LP units immediately if the holder of the subordinated GP units, together with all of its affiliates, ceases to own 15% or more of all units of the Partnership.

Managing General Partner Interest. The managing general partner interest will continue to be outstanding following the initial offering.

Management of the Partnership

The managing general partner manages the Partnership’s operations and activities, subject to our joint management rights, as specified in the partnership agreement. Among other things, the managing general partner has sole authority to effect an initial public or private offering of the Partnership, including the right to determine the timing, size (subject to our consent rights for any initial offering in excess of $200 million, exclusive of the underwriters’ option, if any) and underwriters or initial purchasers, if any, for any initial offering. The Partnership’s managing general partner is wholly-owned by an entity controlled by the Goldman Sachs Funds, the Kelso Funds and certain members of our senior management team. The operations of the managing general partner, in its

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capacity as the managing general partner of the Partnership, are managed by its board of directors. As of the date of this prospectus, the board of directors of the managing general partner consisted of Donna R. Ecton, John J. Lipinski, Scott L. Lebovitz, George E. Matelich, Frank M. Muller, Jr., Stanley de J. Osborne and Kenneth A. Pontarelli. Actions by the managing general partner that are made in its individual capacity will be made by the sole member of the managing general partner and not by its board of directors. The managing general partner is not elected by the unitholders or us and is not subject to re-election on a regular basis in the future. The officers of the managing general partner manage the day-to-day affairs of the Partnership’s business.

The special general partner, which we own, has special management rights. The special management rights will terminate if we cease to own 15% of more of all units of the Partnership. Our management rights include:


	•	appointment rights and consent rights for the termination of employment and compensation of the chief executive officer and chief financial officer of the managing general partner, not to be exercised unreasonably (our approval for appointment of an officer is deemed given if the officer is an executive officer of CVR Energy);

	•	the right to appoint two directors to the board of directors of the managing general partner and one such director to any committee thereof (subject to certain exceptions);

	•	consent rights over any merger by the Partnership into another entity where:


	•	for so long as we own 50% or more of all units of the Partnership immediately prior to the merger, less than 60% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership;

	•	for so long as we own 25% or more of all units of the Partnership immediately prior to the merger, less than 50% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; and

	•	for so long as we own more than 15% of all of the units of the Partnership immediately prior to the merger, less than 40% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership;


	•	consent rights over any purchase or sale, exchange or other transfer of assets or entities with a purchase/sale price equal to 50% or more of the Partnership’s asset value; and

	•	consent rights over any incurrence of indebtedness or issuance of Partnership interests with rights to distribution or in liquidation ranking prior or senior to the common units, in either case in excess of $125 million ($200 million in the case of the Partnership’s initial public or private offering, exclusive of the underwriters’ option, if any), increased by 80% of the purchase price for assets or entities whose purchase was approved by us as described in the immediately preceding bullet point.

As of the date of this prospectus, the board of directors of the managing general partner consists of seven directors, including two representatives of the Goldman Sachs Funds, two representatives of the Kelso Funds, Donna R. Ecton and Frank M. Muller, Jr., who are independent directors and John J. ~~Lipinksi,~~Lipinski, chief executive officer and president of the managing general partner and CVR Energy. If the Partnership effects an initial public offering in the future, the board of directors of the managing general partner will be required, subject to phase-in requirements of any national securities exchange upon which the Partnership’s common units are listed for trading, to have at least three members who are not officers or employees, and are otherwise independent, of the entity which owns the managing general partner, and its affiliates, including CVR Energy and the Partnership’s general partners. In addition, if an initial public offering of the Partnership occurs, the board of directors of the managing general partner will be required to maintain an audit committee comprised of at least three independent directors.

The partnership agreement permits the board of directors of the managing general partner to establish a conflicts committee, comprised of at least one independent director, that may determine if

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the resolution of a conflict of interest with the Partnership’s general partners or their affiliates is fair and reasonable to the Partnership. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to the Partnership, approved by all of the Partnership’s partners and not a breach by the general partners of any duties they may owe the Partnership or the unitholders of the Partnership.

Cash Distributions by the Partnership

Available Cash. The partnership agreement requires the Partnership to make quarterly distributions of 100% of its “available cash.” Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter


	•	less the amount of cash reserves established by the managing general partner to:


	•	provide for the proper conduct of the Partnership’s business (including the satisfaction of obligations in respect of pre-paid fertilizer contracts, future capital expenditures, anticipated future credit needs and the payment of expenses and fees, including payments to the managing general partner);

	•	comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Partnership or any of its subsidiaries is a party or by which the Partnership is bound or its assets are subject; and

	•	provide funds for distributions in respect of any one or more of the next eight quarters, provided, however, that following an initial public offering of the Partnership, the managing general partner may not establish cash reserves pursuant to this clause if the effect of such reserves would be that the Partnership would be unable to distribute the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon with respect to any such quarter;


	•	plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are used solely for working capital purposes or to make distributions to partners.

Cash distributions will be made within 45 days after the end of each quarter. The amount of distributions paid by the Partnership and the decision to make any distribution will be determined by the managing general partner, taking into consideration the terms of the partnership agreement.

Prior to the earlier to occur of (i) such time as the limitations described below in “— Non-IDR surplus amount” no longer apply, after which time available cash from operating surplus could be distributed in respect of the IDRs, assuming each unit has received at least the first target distribution, as described below, and (ii) an initial offering by the Partnership, after which there will be limited partners to whom available cash could be distributed, all available cash is distributed to us, as holder of the special units. Because all available cash is currently distributed to us, the board of directors of Fertilizer GP has not adopted a formal distribution policy.

Operating Surplus and Capital Surplus. All cash distributed by the Partnership will be characterized either as operating surplus or capital surplus. The Partnership will distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus. Operating surplus for any period generally consists of:


	•	$60 million (as described below); plus

	•	all of the Partnership’s cash receipts after formation (reset to the date of the Partnership’s initial offering if an initial offering occurs), excluding cash from “interim capital transactions” (as described below); plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus

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	•	cash distributions paid on equity interests issued by the Partnership to finance all or any portion of the construction, expansion or improvement of the Partnership’s facilities during the period from such financing until the earlier to occur of the date the capital asset is put into service or the date it is abandoned or disposed of; plus

	•	cash distributions paid on equity interests issued by the Partnership to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the construction, expansion and improvement projects referred to above; less

	•	all of the Partnership’s “operating expenditures” (as defined below) after formation (reset to the date of closing of the Partnership’s initial offering if an initial offering occurs); less

	•	the amount of cash reserves established by the managing general partner to provide funds for future operating expenditures (which does not include expansion capital expenditures).

If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

As described above, operating surplus does not reflect actual cash on hand that is available for distribution to unitholders. For example, it includes a provision that will enable the Partnership, if it chooses, to distribute as operating surplus up to $60 million of cash from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus would be to increase operating surplus by the amount of any such cash distributions.

“Operating expenditures” generally means all of the Partnership’s expenditures, including its expenses, taxes, reimbursements or payments of expenses to its managing general partner, repayment of working capital borrowings, debt service payments and capital expenditures, provided that operating expenditures will not include:


	•	repayments of working capital borrowings, if such working capital borrowings were outstanding for twelve months, not repaid, but deemed repaid, thus decreasing operating surplus at such time;

	•	payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings;

	•	expansion capital expenditures;

	•	investment capital expenditures;

	•	payment of transaction expenses relating to “interim capital transactions”; or

	•	distributions to partners.

Where capital expenditures are made in part for expansion and in part for other purposes, the managing general partner shall determine the allocation between the amounts paid for each.

“Interim capital transactions” means the following transactions if they occur prior to liquidation of the Partnership: (a) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business); (b) sales of equity interests and debt securities; and (c) sales or other voluntary or involuntary dispositions of any assets other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements of assets.

Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the Partnership’s operating

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capacity (or productivity) or capital base. Maintenance capital expenditures include expenditures required to maintain equipment reliability, plant integrity and safety and to address environmental laws and regulations. Maintenance capital expenditures also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction, improvement or development of a replacement asset that is paid during the period that begins when the Partnership enters into a binding commitment or commences constructing or developing a replacement asset and ending on the earlier to occur of the date any such replacement asset commences commercial service or the date it is abandoned or disposed of.

Expansion capital expenditures include expenditures to acquire or construct assets to grow the Partnership’s business and to expand fertilizer production capacity. Expansion capital expenditures also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction of such a capital improvement during the period that commences when the Partnership enters into a binding obligation to commence construction of a capital improvement and ending on the date such capital improvement commences commercial service or the date that it is abandoned or disposed of.

Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of the Partnership’s existing operating capacity or productivity, but which are not expected to expand for the long-term the Partnership’s operating capacity or asset base.

As described above, none of the Partnership’s investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset during the period that begins when the Partnership enters into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus.

The officers and directors of the managing general partner determine how to allocate a capital expenditure for the acquisition or expansion of the Partnership’s assets between maintenance capital expenditures and expansion capital expenditures.

Definition of Capital Surplus. “Capital surplus” is generally generated only by:


	•	borrowings other than working capital borrowings;

	•	sales of debt securities and equity interests; and

	•	sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of the normal retirement or replacement of assets.

Distributions from Operating Surplus. The Partnership’s distribution structure with respect to operating surplus will change based upon the occurrence of three events: (1) distribution by the Partnership of the non-IDR surplus amount (as defined below), together with a release of the guarantees by the Partnership and its subsidiaries of our Credit Facility, (2) occurrence of an initial offering by the Partnership (following which all or a portion of our interest will be converted into subordinated units and the minimum quarterly distribution could be reduced) and (3) expiration (or early termination) of the subordination period.

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Minimum Quarterly Distributions. The minimum quarterly distribution, or MQD, represents the set quarterly distribution amount that the common units, if issued, will be entitled to prior to the payment of any quarterly distribution on the subordinated units. The amount of the MQD is set in Partnership’s partnership agreement at $0.375 per unit, or $1.50 per unit on an annualized basis. The partnership agreement prohibits the managing general partner from causing the Partnership to undertake or consummate an initial offering unless the board of directors of the managing general partner, after consultation with us, concludes that the Partnership will be likely to be able to earn and pay the MQD on all units for each of the two consecutive, nonoverlapping four-quarter periods following the initial offering. If the managing general partner determines that the Partnership is not likely to be able to earn and pay the MQD for such periods, the managing general partner may, in its sole discretion and effective upon closing of the initial offering, reduce the MQD to an amount it determines to be appropriate and likely to be earned and paid during such periods. If the Partnership were to distribute $0.375 per unit on the number of units we own, we would receive a quarterly distribution of $11.4 million in the aggregate. The MQD for any period of less than a full calendar quarter (e.g., the periods before and after the closing of an initial offering by the Partnership) will be adjusted based on the actual length of the periods. To the extent we receive such amounts from the Partnership in the form of quarterly distributions, we will generally not be able to distribute such amounts to our stockholders or use such amounts to make payments on the notes due to restrictions contained in our Credit Facility. See “Dividend Policy.”

Target Distributions. The Partnership’s partnership agreement provides for “target distribution levels.” After the limitations described below in “— Non-IDR surplus amount” no longer apply, the managing general partner’s IDRs will entitle it to receive increasing percentages of any incremental quarterly cash distributed by the Partnership as the target distribution levels for each quarter are exceeded. There are three target distribution levels set in the partnership agreement: $0.4313, $0.4688 and $0.5625, representing 115%, 125% and 150%, respectively, of the initial MQD amount. The target distribution levels for any period of less than a full calendar quarter (e.g., the periods before and after the closing of an initial offering by the Partnership) will be adjusted based on the actual length of the periods. The target distribution levels will not be adjusted in connection with any reduction of the MQD in connection with the Partnership’s initial offering unless we otherwise agree with the managing general partner.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and the Partnership’s managing general partner up to and above the various target distribution levels. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the Partnership’s managing general partner and the unitholders in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution — Target Amount,” until the available cash from operating surplus the Partnership distributes reaches the next target distribution level, if any. The percentage interests shown for the unitholders and managing general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the

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minimum quarterly distribution. The percentage interests set forth below for the managing general partner represent distributions in respect of the IDRs.

Marginal Percentage Interest in Distributions


	Total Quarterly
	Distribution — Target				Managing General
	Amount	Special Units			Partner

Minimum Quarterly Distribution	$0.375		100	%		0	%
First Target Distribution	Up to $0.4313		100	%		0	%
Second Target Distribution	Above $0.4313		87	%		13	%
	and up to $0.4688
Third Target Distribution	Above $0.4688		77	%		23	%
	and up to $0.5625
Thereafter	Above $0.5625		52	%		48	%

If legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction so that the Partnership or any of its subsidiaries becomes taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, the managing general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting the managing general partner’s estimate of the Partnership’s aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus the managing general partner’s estimate of the Partnership’s aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.

Non-IDR Surplus Amount. There will be no distributions paid on the IDRs until the aggregate “adjusted operating surplus” (as described below) generated by the Partnership during the period from October 24, 2007 through December 31, 2009, or the non-IDR surplus amount, has been distributed in respect of the special units, or, following an initial public offering of the Partnership, the common and subordinated units (if any are issued). In addition, there will be no distributions paid on the IDRs for so long as the Partnership or its subsidiaries are guarantors under our Credit Facility.

Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $60 million “basket” included as a component of operating surplus, net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period generally means:


	•	operating surplus generated with respect to that period (which does not include the $60 million basket described in the first bullet point of the definition of operating surplus above); less

	•	any net increase in working capital borrowings with respect to that period; less

	•	any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

	•	any net decrease in working capital borrowings with respect to that period; plus

	•	any net increase in cash reserves for operating expenditures with respect to that period to the extent required by any debt instrument for the repayment of principal, interest or premium.

If the Partnership consummates an initial offering, cash received by the Partnership or its subsidiaries in respect of accounts receivable existing as of the closing of such an offering will be

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deemed to not be operating surplus and thus will be disregarded when calculating adjusted operating surplus.

Distributions Prior to the Partnership’s Initial Offering (if any). Prior to the Partnership’s initial offering (if any), quarterly distributions of available cash from operating surplus (as described below) will be paid solely in respect of the special units until the non-IDR surplus amount has been distributed. After the limitations described in “— Non-IDR surplus amount” no longer apply and prior to the Partnership’s initial offering (if any), quarterly distributions of available cash from operating surplus will be paid in the following manner: (1) First, to the special units, until each special unit has received a total quarterly distribution equal to $0.4313 (the first target distribution), (2) Second,(i) 13% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to the special units until each special unit has received a total quarterly amount equal to $0.4688 (the second target distribution), (3) Third, (i) 23% to the managing general partner interest (in respect of the IDRs) and (ii) 77% to the special units, until each special unit has received a total quarterly amount equal to $0.5625 (the third target distribution), and (4) Thereafter, (i) 48% to the managing general partner interest (in respect of the IDRs) and (ii) 52% to the special units.

Distributions from Capital Surplus. Capital surplus is generally generated only by borrowings other than working capital borrowings, sales of debt securities and equity interests, and sales or other dispositions of assets for cash, other than inventory, accounts receivable and the other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

The Partnership will make distributions of available cash from capital surplus, if any, in the following manner: (1) First, to all unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below, (2) Second, to the common unitholders, if any, pro rata, until the Partnership distributes for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units, and (3) Thereafter, the Partnership will make all distributions of available cash from capital surplus as if they were from operating surplus. The preceding discussion is based on the assumptions that the Partnership does not issue additional classes of equity interests.

The partnership agreement will treat a distribution of capital surplus as the repayment of the consideration for the issuance of a unit by the Partnership, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution had in relation to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the managing general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

Once the Partnership reduces the minimum quarterly distribution and the target distribution levels to zero, the Partnership will then make all future distributions from operating surplus, with 52% being paid to the unitholders, pro rata, and 48% to the Partnership’s managing general partner.

Distributions of Cash Upon Liquidation. If the Partnership dissolves in accordance with the partnership agreement, the Partnership will sell or otherwise dispose of its assets in a process called liquidation. The Partnership will first apply the proceeds of liquidation to the payment of its creditors. The Partnership will distribute any remaining proceeds to the unitholders and the managing general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation.

The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by the unitholder to the Partnership for its units, which we refer to as the “initial unit price” for each unit. With respect to our special units, the initial unit price will be the value of the nitrogen fertilizer business we contribute to the Partnership, divided by the number of special units we receive. The initial unit price for the common units issued

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by the Partnership in the initial offering, if any, will be the price paid for the common units. If there are common units and subordinated units outstanding, the allocation is intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon the Partnership’s liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon the Partnership’s liquidation to enable the holders of units, including us, to fully recover all of the initial unit price. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the managing general partner.

The manner of the adjustment for gain is set forth in the partnership agreement. If the Partnership’s liquidation occurs after the Partnership’s initial offering, if any, and before the end of the subordination period, the Partnership will allocate any gain to the partners in the following manner: (1) First, to the managing general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances, (2) Second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of (i) the initial unit price, (ii) the amount of the minimum quarterly distribution for the quarter during which the liquidation occurs, and (iii) any unpaid arrearages in payment of the minimum quarterly distribution, (3) Third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of (i) the initial unit price and (ii) the amount of the minimum quarterly distribution for the quarter during which the liquidation occurs, (4) Fourth, to all unitholders, pro rata, until the Partnership allocates under this paragraph an amount per unit equal to (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of the Partnership’s existence, less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that the Partnership distributed to the unitholders, pro rata, for each quarter of the Partnership’s existence, (5) Fifth, 87% to all unitholders, pro rata, and 13% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to (i) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of the Partnership’s existence; less the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that the Partnership distributed 87% to the unitholders, pro rata, and 13% to the managing general partner for each quarter of the Partnership’s existence, (6) Sixth, 77% to all unitholders, pro rata, and 23% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of the Partnership’s existence, less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that the Partnership distributed 77% to the unitholders, pro rata, and 23% to the managing general partner for each quarter of the Partnership’s existence, and (7) Thereafter, 52% to all unitholders, pro rata, and 48% to the managing general partner. The percentages set forth above are based on the assumption that the Partnership has not issued additional classes of equity interests.

If the liquidation occurs before the Partnership’s initial offering, the special units will receive allocations of gain in the same manner as described above for the common units, except that the distinction between common units and subordinated units will not be relevant, so that subclause (iii) of clause (2) above and all of clause (3) above will not be applicable. If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that subclause (iii) of clause (2) above and all of the third bullet point above will no longer be applicable.

If the Partnership’s liquidation occurs after the Partnership’s initial offering, if any, and before the end of the subordination period, the Partnership will generally allocate any loss to the managing general partner and the unitholders in the following manner: (1) First, to holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the

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subordinated unitholders have been reduced to zero, (2) Second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero, and (3) Thereafter,100% to the managing general partner.

If the liquidation occurs before the Partnership’s initial offering, the special units will receive allocations of loss in the same manner as described above for the common units, except that the distinction between common units and subordinated units will not be relevant, so that all of clause (1) above will not be applicable. If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of clause (1) will no longer be applicable.

Adjustments to Capital Accounts. The Partnership will make adjustments to capital accounts upon the issuance of additional units. In doing so, the Partnership will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the managing general partner in the same manner as the Partnership allocates gain or loss upon liquidation. In the event that the Partnership makes positive adjustments to the capital accounts upon the issuance of additional units, the Partnership will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon the Partnership’s liquidation in a manner which results, to the extent possible, in the managing general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

Withdrawal or Removal of the Managing General Partner

Except as described below, the managing general partner has agreed not to withdraw voluntarily as the Partnership’s managing general partner prior to June 30, 2017 without obtaining the approval of the holders of at least a majority of the outstanding units, excluding units held by the managing general partner and its affiliates (including us), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2017, the managing general partner may withdraw as managing general partner without first obtaining approval of any unitholder by giving 90 days written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the information above, the managing general partner may withdraw without unitholder approval upon 90 days notice to the unitholders if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than the managing general partner and its affiliates. In addition, the partnership agreement permits the managing general partner in some instances to sell or otherwise transfer all of its managing general partner interest without the approval of the unitholders. See “— Transfer of Managing General Partner Interest.”

Upon withdrawal of the managing general partner under any circumstances, other than as a result of a transfer by the managing general partner of all or a part of its general partner interest in the Partnership, the holders of a majority of the outstanding classes of units voting as a single class may select a successor to that withdrawing managing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, the Partnership will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue the business of the Partnership and to appoint a successor managing general partner. See “— Termination and Dissolution.”

The managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 80% of the outstanding units, voting together as a single class, including units held by the managing general partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters. Prior to October 26, 2012, the managing general partner can only be removed for “cause.” Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the unitholders holding a majority of each class of outstanding units, voting as separate classes.

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The partnership agreement also provides that if the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by us, including our subsidiary that holds the subordinated units (if any) and our other affiliates, are voted in favor of that removal, the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis, and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished.

If the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by the managing general partner and its affiliates (which will include us until such time as we cease to be an affiliate of the managing general partner) are voted in favor of that removal, the managing general partner will have the right to convert its managing general partner interest, including the incentive distribution rights, into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.

In the event of removal of the managing general partner under circumstances where cause exists or withdrawal of the managing general partner where that withdrawal violates the partnership agreement, a successor managing general partner will have the option to purchase the managing general partner interest, including the IDRs, of the departing managing general partner for a cash payment equal to the fair market value of the managing general partner interest. Under all other circumstances where the managing general partner withdraws or is removed, the departing managing general partner will have the option to require the successor managing general partner to purchase the managing general partner interest of the departing managing general partner for its fair market value. In each case, this fair market value will be determined by agreement between the departing managing general partner and the successor managing general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing managing general partner and the successor managing general partner will determine the fair market value. If the departing managing general partner and the successor managing general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.

If the option described above is not exercised by either the departing managing general partner or the successor managing general partner, the departing managing general partner’s general partner interest, including its IDRs, will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.

In addition, the Partnership will be required to reimburse the departing managing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing managing general partner or its affiliates for the Partnership’s benefit.

Voting Rights

The partnership agreement provides that various matters require the approval of a “unit majority.” A unit majority requires (1) prior to the initial offering, the approval of a majority of the special units; (2) during the subordination period, the approval of a majority of the common units, excluding those common units held by the managing general partner and its affiliates (which will include us until such time as we cease to be an affiliate of the managing general partner), and a majority of the subordinated units, voting as separate classes; and (3) after the subordination period, the approval of a majority of the common units. In voting their units, the Partnership’s general partners and their affiliates will have no fiduciary duty or obligation whatsoever to the Partnership or the other partners, including any duty to act in good faith or in the best interests of the Partnership and its other partners.

The following is a summary of the vote requirements specified for certain matters under the partnership agreement:


	•	*Issuance of Additional Units:* no approval right.

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	•	*Amendment of the Partnership Agreement:* certain amendments may be made by the managing general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority.

	•	*Merger of the Partnership or the Sale of all or Substantially all of the Partnership’s Assets:* unit majority in certain circumstances. In addition, the holder of special GP rights has joint management rights with respect to some mergers.

	•	*Dissolution of the Partnership:* unit majority.

	•	*Continuation of the Partnership upon Dissolution:* unit majority.

	•	*Withdrawal of the Managing General Partner:* under most circumstances, a unit majority is required for the withdrawal of the managing general partner prior to June 30, 2017 in a manner which would cause a dissolution of the Partnership.

	•	*Removal of the Managing General Partner:* not less than 80% of the outstanding units, voting as a single class, including units held by the managing general partner and its affiliates (i) for cause prior to October 26, 2012 or (ii) with or without cause (as defined in the partnership agreement) on or after October 26, 2012.

	•	*Transfer of the Managing General Partner’s General Partner Interest:* the managing general partner may transfer all, but not less than all, of its managing general partner interest in the Partnership without a vote of any unitholders and without our approval, to an affiliate or to another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding units, excluding units held by the managing general partner and its affiliates, voting as a class, and our approval, is required in other circumstances for a transfer of the managing general partner interest to a third party prior to October 26, 2017.

	•	*Transfer of Ownership Interests in the Managing General Partner:* no approval required at any time.

Issuance of Additional Partnership Interests

The partnership agreement authorizes the Partnership to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by the managing general partner without the approval of the unitholders, subject to the special GP rights with respect to the issuance of equity with rights to distribution or in liquidation ranking prior to or senior to the common units.

Upon issuance of additional partnership interests, the Partnership’s managing general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, the Partnership issues those interests to persons other than the managing general partner and its affiliates, to the extent necessary to maintain its and its affiliates’ percentage interest, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. We will have similar rights to purchase common units, subordinated units or other partnership interests from the Partnership, except that our rights will not apply to any issuance of interests by the Partnership in its initial offering. For the purpose of these rights, we and the managing general partner shall be deemed not to be affiliates of one another, unless we otherwise agree. Other holders of units will not have preemptive rights to acquire additional common units or other partnership interests unless they are granted those rights in connection with the issuance of their units by the Partnership.

Amendment of the Partnership Agreement

General. Amendments to the partnership agreement may be proposed only by the managing general partner. However, the managing general partner has no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to the

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Partnership or any partner, including any duty to act in good faith or in the best interests of the Partnership or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, the managing general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.

Prohibited Amendments. No amendment may be made that would: (1) enlarge the obligations of any limited partner or us, as a general partner, without its consent, unless approved by at least a majority of the type or class of partner interests so affected or (2) enlarge the obligations of, or restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by the Partnership to any general partner or any of its affiliates without its consent, which may be given or withheld in its sole discretion. The provision of the partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting together as a single class (including units owned by the managing general partner and its affiliates). As of December 31, 2007, we own all of the outstanding units.

No Unitholder Approval. The managing general partner may generally make amendments to the partnership agreement without the approval of any unitholders to reflect (1) a change in the Partnership’s name, the location of its principal place of business, its registered agent or its registered office, (2) the admission, substitution, withdrawal or removal of partners in accordance with the partnership agreement, (3) a change that the managing general partner determines to be necessary or appropriate for the Partnership to qualify or to continue its qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither the Partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed), (4) an amendment that is necessary, in the opinion of the Partnership’s counsel, to prevent the Partnership or its general partners or their directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed, (5) an amendment that the managing general partner determines to be necessary or appropriate for the authorization of additional partnership interests or rights to acquire partnership interests, as otherwise permitted by the partnership agreement, (6) any amendment expressly permitted in our partnership agreement to be made by the Partnership’s managing general partner acting alone, (7) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement, (8) any amendment that the Partnership’s managing general partner determines to be necessary or appropriate for the formation by the Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by the partnership agreement, (9) a change in the Partnership’s fiscal year or taxable year and related changes, (10) mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance or (11) any other amendments substantially similar to any of the matters described above.

In addition, the managing general partner may make amendments to the partnership agreement without the approval of any partner if the managing general partner determines that those amendments (1) do not adversely affect in any material respect the partners (considered as a whole or any particular class of partners), (2) are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, (3) are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, (4) are necessary or appropriate for any action taken by the managing general

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partner relating to splits or combinations of units under the provisions of the partnership agreement or (5) are required to effect the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.

Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, the managing general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in the Partnership being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless the managing general partner first obtains an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of the Partnership’s limited partners. Finally, the managing general partner may consummate any merger without the prior approval of the Partnership’s unitholders if the Partnership is the surviving entity in the transaction, the transaction would not result in any amendment to the partnership agreement (other than an amendment that the managing general partner could adopt without the consent of other partners), each of the units outstanding immediately prior to the merger will be an identical unit of the Partnership following the transaction, the units to be issued do not exceed 20% of the outstanding units immediately prior to the transaction and the managing general partner has received an opinion of counsel regarding certain limited liability and tax matters.

In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.

Merger, Sale or Other Disposition of Assets

A merger or consolidation of the Partnership requires the prior consent of the managing general partner. However, the managing general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or other partners, including any duty to act in good faith or in the best interest of the Partnership or the other partners. We also have joint management rights with respect to certain mergers. Mergers and consolidations generally also require the affirmative vote or consent of the holders of a unit majority, unless the merger agreement contains any provision that, if contained in an amendment to the partnership agreement, would require for its approval the vote or consent of a greater percentage of the outstanding units or of any class of partners, in which case such greater percentage vote or consent shall be required.

In addition, the partnership agreement generally prohibits the managing general partner, without the prior approval of the holders of units representing a unit majority, from causing the Partnership to, among other things, sell, exchange or otherwise dispose of all or substantially all of the Partnership’s assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on the Partnership’s behalf the sale, exchange or other disposition of all or substantially all of the assets of the Partnership’s subsidiaries. The managing general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without that approval. The managing general partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon those encumbrances without that approval.

If the conditions specified in the partnership agreement are satisfied, the managing general partner may, without other partner approval, convert the Partnership or any of its subsidiaries into a new limited liability entity or merge the Partnership or any of its subsidiaries into, or convey some or all of its assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in its legal form into another limited liability entity, the governing instruments of the

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new entity provide the limited partners and general partners with the same rights and obligations as contained in the partnership agreement and the Partnership receives an opinion of counsel regarding certain limited liability and tax matters. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of the Partnership’s assets or any other transaction or event.

Termination and Dissolution

The Partnership will continue as a limited partnership until terminated under the partnership agreement. The Partnership will dissolve upon: (1) the election of the managing general partner to dissolve the Partnership, if approved by the holders of units representing a unit majority; (2) there being no limited partners, unless the Partnership continues without dissolution in accordance with applicable Delaware law; (3) the entry of a decree of judicial dissolution of the Partnership or (4) the withdrawal or removal of the managing general partner or any other event that results in its ceasing to be the Partnership’s managing general partner other than by reason of a transfer of its managing general partner interest in accordance with the partnership agreement or withdrawal or removal following approval and admission of a successor.

Upon a dissolution under clause (4) above, the holders of a unit majority may also elect, within specific time limitations, to continue the Partnership’s business on the same terms and conditions described in the partnership agreement by appointing as a successor managing general partner an entity approved by the holders of units representing a unit majority, subject to receipt of an opinion of counsel to the effect that (1) the action would not result in the loss of limited liability under Delaware law of any limited partner and (2) neither the Partnership nor any of its subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).

Upon dissolution of the Partnership, unless the business of the Partnership is continued, the liquidator authorized to wind up the Partnership’s affairs will, acting with all of the powers of the managing general partner that are necessary or appropriate, liquidate the Partnership’s assets and apply the proceeds of the liquidation as described in the partnership agreement. The liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.

Transfer of Managing General Partner Interest

Except for the transfer by the managing general partner of all, but not less than all, of its managing general partner interest in the Partnership to (1) an affiliate of the managing general partner (other than an individual) or (2) another entity as part of the merger or consolidation of the managing general partner with or into another entity or the transfer by the managing general partner of all or substantially all of its assets to another entity, the managing general partner may not transfer all or any part of its managing general partner interest in the Partnership to another person prior to October 26, 2017 without the approval of both (1) the holders of at least a majority of the outstanding units (excluding units held by the managing general partner and its affiliates) and (2) us. On or after October 26, 2017, the managing general partner interest will be freely transferable. As a condition of any transfer, the transferee must, among other things, assume the rights and duties of the managing general partner, agree to be bound by the provisions of the partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. The Partnership’s general partners and their affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to the Partnership.

Transfer of Ownership Interests in the Managing General Partner

At any time, the owners of the managing general partner may sell or transfer all or part of their ownership interests in the managing general partner to an affiliate or a third party without the approval of the Partnership’s unitholders.

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Change of Management Provisions

The partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove the managing general partner as the managing general partner of the Partnership or otherwise change the Partnership’s management. If any person or group other than the managing general partner and its affiliates (including us) acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from the managing general partner or its affiliates and any transferees of that person or group approved by the managing general partner or to any person or group who acquires the units with the prior approval of the board of directors of the managing general partner.

The partnership agreement also provides that if the Partnership’s managing general partner is removed without cause and no units held by us, our subsidiary that holds the subordinated units (if any) and our other affiliates are voted in favor of that removal, the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis; and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished.

If the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by the managing general partner and its affiliates (which will include us until such time as we cease to be an affiliate of the managing general partner) are voted in favor of that removal, the managing general partner will have the right to convert its managing general partner interest, including its incentive distribution rights, into common units or to receive cash in exchange for the managing general partner interest.

Limited Call Right

If at any time the managing general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, the managing general partner will have the right, which it may assign in whole or in part to any of its affiliates or to the Partnership, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by the managing general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of such an acquisition will be the greater of (1) the highest price paid by the managing general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which the managing general partner first mails notice of its election to purchase those limited partner interests, and (2) the average of the daily closing prices of the limited partner interests over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed. At any time following the Partnership’s initial offering, if any, if we fail to hold at least 20% of the units of the Partnership our common GP units will be deemed to be part of the same class of partnership interests as the common LP units for purposes of this provision. This provision will make it easier for the managing general partner to take the Partnership private in its discretion.

Indemnification

Under the partnership agreement, the Partnership will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions suits or proceedings: (1) the Partnership’s general partners; (2) any departing general partner; (3) any person who is or was a director, officer, fiduciary, trustee, manager or managing member of the Partnership or any of the Partnership’s subsidiaries, its general partners or any departing general partner; (4) any person who is or was serving as a director, officer, fiduciary, trustee, manager or managing member of another person owing a fiduciary duty to the Partnership or any of its subsidiaries at the request of a general partner or any departing general partner; (5) any person who controls a general partner; or (6) any person designated by the Partnership’s managing

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general partner. Any indemnification under these provisions will only be out of the Partnership’s assets. Unless they otherwise agree, the Partnership’s general partners will not be personally liable for, or have any obligation to contribute or loan funds or assets to the Partnership to enable the Partnership to effectuate, indemnification. The Partnership may purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under the partnership agreement.

Reimbursement of Expenses

The partnership agreement requires the Partnership to reimburse the Partnership’s managing general partner for (1) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of the managing general partner, to perform services for the Partnership or for the managing general partner in the discharge of its duties to the Partnership) and (2) all other expenses allocable to the Partnership or otherwise incurred by the managing general partner in connection with operating the Partnership’s business (including expenses allocated to the managing general partner by its affiliates). The managing general partner is entitled to determine the expenses that are allocable to the Partnership.

Conflicts of Interest

Conflicts of interest exist and may arise in the future as a result of (1) the overlap of directors and officers between us and the Partnership’s managing general partner, which may result in conflicting obligations by our directors and officers, (2) duties of the Partnership’s managing general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our noteholders and stockholders, and (3) our duties as a general partner of the Partnership to act for the benefit of all unit holders, including future unaffiliated partners, which may conflict with our interests and the interests of our noteholders and stockholders. The directors and officers of the Partnership’s managing general partner, Fertilizer GP, have fiduciary duties to manage Fertilizer GP in a manner beneficial to its owners, but at the same time, Fertilizer GP has a fiduciary duty to manage the Partnership in a manner beneficial to its unit holders, including us. In addition, because we are a general partner of the Partnership, we have a legal duty to exercise our special GP rights in a manner beneficial to the Partnership’s unit holders, who may in the future include unaffiliated partners, but at the same time our directors and officers have a fiduciary duty to act in a manner beneficial to us and our stockholders.

With respect to conflicts of interest between the Partnership and Fertilizer GP, Fertilizer GP will resolve that conflict. The partnership agreement will permit the board of directors of the managing general partner to establish a conflicts committee. See “— Management of the Partnership.” The partnership agreement contains provisions that modify and limit the fiduciary duties of Fertilizer GP and us to the unit holders. The partnership agreement also restricts the remedies available to unit holders (including us) for actions taken that, without those limitations, might constitute breaches of fiduciary duty.

Fertilizer GP, as the managing general partner, will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its unit holders (including us) if the resolution of the conflict is:


	•	approved by Fertilizer GP’s conflicts committee, although Fertilizer GP is not obligated to seek such approval;

	•	approved by the vote of a majority of the outstanding common units, excluding any common units owned by Fertilizer GP and its affiliates (including us so long as we remain an affiliate);

	•	on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or

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	•	fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to the Partnership.

Fertilizer GP may, but is not required to, seek approval from the conflicts committee of its board of directors or from the common unit holders. If Fertilizer GP does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, Fertilizer GP or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When the partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the Partnership, unless the context otherwise requires.

Conflicts of interest could arise in the situations described below, among others.

Fertilizer GP holds all of the Incentive Distribution Rights in the Partnership.

Fertilizer GP, as managing general partner of the Partnership, holds all of the incentive distribution rights in the Partnership. Incentive distribution rights will give Fertilizer GP a right to increasing percentages of the Partnership’s quarterly distributions from operating surplus after the aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 has been distributed in respect of the special unitsand/or the common and subordinated units. Fertilizer GP may have an incentive to manage the Partnership in a manner which increases these future cash flows rather than in a manner which increases current cash flows. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our noteholders and stockholders.”

Officers and Directors of Fertilizer GP also serve as officers and directors of us and have obligations to both the Partnership and our business.

All of the executive officers and five of the seven directors of Fertilizer GP also serve as directors and executive officers of CVR Energy. We have entered into a services agreement with Fertilizer GP and the Partnership pursuant to which our executive officers and other employees provide services to the Partnership. The executive officers who work for both us and Fertilizer GP, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, will divide their time between our business and the business of the Partnership. These directors and executive officers will face conflicts of interests from time to time in making decisions that may benefit either our company or the Partnership. When making decisions on behalf of Fertilizer GP they will have to take into account the interests of the Partnership and not of us.

The owners of the Partnership’s Managing General Partner may compete with us or the Partnership or own businesses that compete with us or the Partnership.

The owners of Fertilizer GP, which are our controlling stockholders and senior management, are permitted to compete with us or the Partnership or to own businesses that compete with us or the Partnership. In addition, the owners of Fertilizer GP are not required to share business opportunities with us or the Partnership. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our noteholders and stockholders.”

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Fertilizer GP is allowed to take into account the interests of parties other than the Partnership in resolving conflicts.

The partnership agreement contains provisions that reduce the standards to which its general partners would otherwise be held by state fiduciary duty law. For example, the partnership agreement permits Fertilizer GP to make a number of decisions in its individual capacity, as opposed to its capacity as managing general partner. This entitles Fertilizer GP to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, the Partnership, the Partnership’s affiliates or any partner. Examples include the exercise of Fertilizer GP’s call right and the determination of whether to consent to any merger or consolidation of the Partnership.

Fertilizer GP has limited its liability and reduced its fiduciary duties, and has also restricted the remedies available to the Partnership’s Unit Holders (including us) for actions that, without the limitations, might constitute breaches of fiduciary duty.

In addition to the provisions described above, the partnership agreement contains provisions that restrict the remedies available to the Partnership’s unit holders for actions that might otherwise constitute breaches of fiduciary duty. For example:


	•	The partnership agreement provides that Fertilizer GP shall not have any liability to the Partnership or its unit holders (including us) for decisions made in its capacity as managing general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of the Partnership.

	•	The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unit holders must be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to the Partnership, as determined by Fertilizer GP in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” Fertilizer GP may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership.

	•	The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership or its partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct.

Actions taken by Fertilizer GP may affect the amount of cash distributions to Unit Holders.

The amount of cash that is available for distribution to unit holders, including us, is affected by decisions of Fertilizer GP regarding such matters as:


	•	amount and timing of asset purchases and sales;

	•	cash expenditures;

	•	borrowings;

	•	issuance of additional units; and

	•	the creation, reduction, or increase of reserves in any quarter.

In addition, borrowings by the Partnership and its affiliates do not constitute a breach of any duty owed by Fertilizer GP to the Partnership’s unit holders, including us, including borrowings that have the purpose or effect of enabling Fertilizer GP to receive distributions on the incentive distribution rights.

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Contracts between the Partnership, on the one hand, and Fertilizer GP, on the other, will not be the result of arm’s-length negotiations.

The partnership agreement allows the Partnership’s managing general partner to determine, in good faith, any amounts to pay itself for any services rendered to the Partnership. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between the Partnership and the managing general partner are or will be the result of arm’s-length negotiations.

The partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement among the Partnership and its general partners and their affiliates, must be:


	•	on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or

	•	“fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).

Fertilizer GP intends to limit the liability of the Partnership’s General Partners regarding the Partnership’s obligations.

Fertilizer GP intends to limit the liability of the Partnership’s general partners under contractual arrangements so that the contract counterparties have recourse only to the Partnership’s assets and not against the Partnership’s general partners or their assets. The partnership agreement provides that any action taken by Fertilizer GP to limit the general partners’ liability or the Partnership’s liability is not a breach of Fertilizer GP’s fiduciary duties, even if the Partnership could have obtained terms that are more favorable without the limitation on liability.

The Partnership may choose not to retain separate counsel for itself.

The attorneys, independent accountants and others who perform services for the Partnership will be retained by Fertilizer GP or its affiliates. Attorneys, independent accountants and others who perform services for the Partnership are selected by Fertilizer GP or the conflicts committee and may perform services for Fertilizer GP and its affiliates. Fertilizer GP may cause the Partnership to retain separate counsel for itself in the event of a conflict of interest between a general partner and its affiliates, on the one hand, and the Partnership or the holders of common units, on the other, depending on the nature of the conflict, although it does not intend to do so in most cases.

Fertilizer GP, as Managing General Partner, has the power and authority to conduct the Partnership’s business (subject to our specified joint management rights).

Under the partnership agreement, Fertilizer GP, as managing general partner, has full power and authority to do all things, other than those items that require unit holder approval or our approval or with respect to which it has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct the Partnership’s business including, but not limited to, the following (subject to our specified joint management rights):


	•	the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into securities of the Partnership, and the incurring of any other obligations;

	•	the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the Partnership’s business or assets;

	•	the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the Partnership’s assets or the merger or other combination of the Partnership with or into another person;

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	•	the negotiation, execution and performance of any contracts, conveyances or other instruments;

	•	the distribution of Partnership cash;

	•	the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring;

	•	the maintenance of insurance for the Partnership’s benefit and the benefit of its partners;

	•	the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships;

	•	the control of any matters affecting the Partnership’s rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation;

	•	the indemnification of any person against liabilities and contingencies to the extent permitted by law;

	•	the purchase, sale or other acquisition or disposition of Partnership interests, or the issuance of additional options, rights, warrants and appreciation rights relating to Partnership interests; and

	•	the entering into of agreements with any affiliates to render services to the Partnership or to itself in the discharge of its duties as the Partnership’s managing general partner.

The Partnership Agreement limits the fiduciary duties of the Managing General Partner to the Partnership and to other Unit Holders.

The Partnership’s general partners are accountable to the Partnership and its unit holders as a fiduciary. Fiduciary duties owed to unit holders by the general partners are prescribed by law and the partnership agreement. The Delaware Limited Partnership Act provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to other partners and the partnership.

The partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by Fertilizer GP. The Partnership has adopted these provisions to allow the Partnership’s general partners or their affiliates to engage in transactions with the Partnership that would otherwise be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to the Partnership’s interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of the Partnership’s general partners’ state law fiduciary duty standards. We believe this is appropriate and necessary because (1) the board of directors of Fertilizer GP, the Partnership’s managing general partner, has both fiduciary duties to manage the Partnership’s managing general partner in a manner beneficial to its owners and fiduciary duties to manage the Partnership in a manner beneficial to unit holders (including CVR Energy) and (2) we, in our capacity of general partner, have both duties to exercise our special GP rights in a manner beneficial to our stockholders and fiduciary duties to exercise such rights in a manner beneficial to all of the Partnership’s unit holders. Without these modifications, the Partnership’s general partners’ ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the Partnership’s general partners to take into consideration all parties involved in the proposed action. These modifications disadvantage the unit holders because they restrict the rights and remedies that would otherwise be available to unit holders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit the Partnership’s general partners to take into account the interests of third parties in addition to the Partnership’s interests when resolving conflicts of interest.

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The following is a summary of the material restrictions of the fiduciary duties owed by the general partners:


	•	State law fiduciary duty standards are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where the general partner has a conflict of interest.

	•	The partnership agreement contains provisions that waive or consent to conduct by the Partnership’s general partners and their affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, the partnership agreement provides that when either of the general partners is acting in its capacity as a general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when either of the general partners is acting in its individual capacity, as opposed to in its capacity as a general partner, it may act without any fiduciary obligation to the Partnership or the unit holders whatsoever. These standards reduce the obligations to which the Partnership’s general partners would otherwise be held.

	•	The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unit holders and that are not approved by the conflicts committee of the board of directors of the Partnership’s managing general partner must be (1) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership).

	•	If the Partnership’s managing general partner does not seek approval from the conflicts committee or the common unit holders and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet point above, then it will be presumed that, in making its decision, the board of directors of the managing general partner, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which the Partnership’s managing general partner would otherwise be held.

	•	In addition to the other more specific provisions limiting the obligations of the Partnership’s general partners, the partnership agreement further provides that the Partnership’s general partners and their officers and directors will not be liable for monetary damages to the Partnership or its partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct.

Under the partnership agreement, the Partnership will indemnify its general partners and their respective officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by such general partners or these other persons. The Partnership must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. The Partnership also must provide this indemnification for criminal proceedings unless the general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, the Partnership’s general partners could be indemnified for their negligent acts if they meet the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to

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public policy and therefore unenforceable. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The partnership agreement limits the fiduciary duties of the managing general partner and restricts the remedies available to us for actions taken by the managing general partner that might otherwise constitute breaches of fiduciary duty.”

Intercompany Agreements

In connection with the formation of the Partnership, we entered into several other agreements with the Partnership which govern the business relations among us, the Partnership and the managing general partner.

Feedstock and Shared Services Agreement

In October 2007, we entered into a feedstock and shared services agreement with the Partnership under which we and the Partnership agreed to provide feedstock and other services to each other. These feedstocks and services are utilized in the respective production processes of our refinery and the nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas.

The Partnership is obligated to provide us with hydrogen from time to time. The agreement provides hydrogen supply and pricing terms for circumstances where the refinery requires more hydrogen than it can generate. Although we expect that the Partnership will continue to provide hydrogen to us for at least the rest of 2008 as it has done in prior years, we believe that the Partnership’s provision of hydrogen to our petroleum operations will decrease, to some extent, during 2008 because our new continuous catalytic reformer will produce hydrogen for us. Also, we expect that a project under consideration will further reduce the Partnership’s hydrogen sales to our refinery.

The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. The Partnership must make available to us any high-pressure steam produced by the nitrogen fertilizer plant that is not required for the operation of the nitrogen fertilizer plant. We must use commercially reasonable efforts to provide high-pressure steam to the Partnership for purposes of allowing the Partnership to commence and recommence operation of the nitrogen fertilizer plant from time to time, and also for use at the Linde air separation plant adjacent to our own facility. We are not required to provide such high-pressure steam if doing so would have a material adverse effect on the refinery’s operations. The price for such high pressure steam is calculated using a formula that is based on steam flow and the price of natural gas as published in “Inside F.E.R.C.’s Gas Market Report” under the heading “Prices of Spot Gas delivered to Pipelines” for Southern Star Central Gas Pipeline, Inc. for Texas, Oklahoma and Kansas.

The Partnership is also obligated to make available to us any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by the Partnership in a commercially reasonable manner. The price for the nitrogen is based on a cost of $0.035 cents per kilowatt hour, as adjusted to reflect changes in the Partnership’s electric bill.

The agreement also provides that both we and the Partnership must deliver instrument air to one another in some circumstances. The Partnership must make instrument air available for purchase by us at a minimum flow rate, to the extent produced by the Linde air separation plant and available to the Partnership. The price for such instrument air is $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in the Partnership’s electric bill. To the extent that instrument air is not available from the Linde air separation plant and is available from us, we are required to make instrument air available to the Partnership for purchase at a price of $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in our electric bill.

With respect to oxygen requirements, the Partnership is obligated to provide us with oxygen produced by the Linde air separation plant and made available to the Partnership to the extent that

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such oxygen is not required for operation of the nitrogen fertilizer plant. The oxygen is required to meet certain specifications and is to be sold at a fixed price.

The agreement also addresses the means by which we and the Partnership obtain natural gas. Currently, natural gas is delivered to both the nitrogen fertilizer plant and our refinery pursuant to a contract between us and Atmos Energy Corp., or Atmos. Under the feedstock and shared services agreement, the Partnership reimburses us for natural gas transportation and natural gas supplies purchased on behalf of the Partnership. At our request or at the request of the Partnership, in order to supply the Partnership with natural gas directly, both parties will be required to use their commercially reasonable efforts to (i) add the Partnership as a party to the current contract with Atmos or reach some other mutually acceptable accommodation with Atmos whereby both we and the Partnership would each be able to receive, on an individual basis, natural gas transportation service from Atmos on similar terms and conditions as set forth in the current contract, and (ii) purchase natural gas supplies on their own account.

The agreement also addresses the allocation of various other feedstocks, services and related costs between the parties. Sour water, water for use in fire emergencies and costs associated with security services are all allocated between the two parties by the terms of the agreement. The agreement also requires the Partnership to reimburse us for utility costs related to a sulfur processing agreement between Tessenderlo Kerley, Inc. and us. The Partnership has a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both our and the Partnership’s existing agreements with Tessenderlo Kerley are allocated equally between the two parties except in certain circumstances.

The parties may temporarily suspend the provision of feedstocks or services pursuant to the terms of the agreement if repairs or maintenance are necessary on applicable facilities. Additionally, the agreement imposes minimum insurance requirements on the parties and their affiliates.

The agreement has an initial term of 20 years, which will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding, or otherwise becomes insolvent.

Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.

Coke Supply Agreement

We entered into a coke supply agreement with the Partnership in October 2007 pursuant to which we supply pet coke to the Partnership. This agreement provides that we must deliver to the Partnership during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at our petroleum refinery or (ii) 500,000 tons of pet coke. The Partnership is also obligated to purchase this annual required amount. If during a calendar month we produce more than 41,667 tons of pet coke, then the Partnership has the option to purchase the

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excess at the purchase price provided for in the agreement. If the Partnership declines to exercise this option, we may sell the excess to a third party.

The price which the Partnership pays for the pet coke is based on the lesser of a coke price derived from the price received by the Partnership for UAN (subject to a UAN-based price ceiling and floor) and a coke index price but in no event will the pet coke price be less than zero. The Partnership also pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. The Partnership is entitled to offset any amount payable for the pet coke against any amount due from us under the feedstock and shared services agreement between the parties. If the Partnership fails to pay an invoice on time, the Partnership will pay interest on the outstanding amount payable at a rate of three percent above the prime rate.

In the event we deliver pet coke to the Partnership on a short term basis and such pet coke is off-specification on more than 20 days in any calendar year, there will be a price adjustment to compensate the Partnershipand/or capital contributions will be made to the Partnership to allow it to modify its equipment to process the pet coke received. If we determine that there will be a change in pet coke quality on a long term basis, then we will be required to notify the Partnership of such change with at least three years’ notice. The Partnership will then determine the appropriate changes necessary to its nitrogen fertilizer plant in order to process such off-specification coke. We will compensate the Partnership for the cost of making such modificationsand/or adjust the price of pet coke on a mutually agreeable commercially reasonable basis.

The terms of the coke supply agreement provide benefits both to our petroleum business and the Partnership. In return for receiving a potentially lower price for coke in periods when the coke price is impacted by lower UAN prices, we enjoy the following benefits associated with the disposition of a low value by-product of the refining process: avoiding the capital cost and operating expenses associated with coke handling; enjoying flexibility in our crude slate and operations as a result of not being required to meet a specific coke quality; avoiding the administration, credit risk and marketing fees associated with selling coke; and obtaining a contractual right of first refusal to a secure and reliable long-term source of hydrogen from the Partnership to back up our refinery’s own internal hydrogen production. We require hydrogen in order to remove sulfur from diesel fuel and gasoline.

The cost of the pet coke supplied by us to the Partnership in most cases is lower than the price which the Partnership otherwise would pay to third parties. The cost to the Partnership is lower both because the actual price paid is lower and because the Partnership pays significantly reduced transportation costs (since the pet coke is supplied by an adjacent facility which involves no freight or tariff costs). In addition, because the cost the Partnership pays is formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), the Partnership enjoys lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.

The Partnership may be obligated to provide security for its payment obligations under the agreement if in our sole judgment there is a material adverse change in the Partnership’s financial condition or liquidity position or in the Partnership’s ability to make payments. This security shall not exceed an amount equal to 21 times the average daily dollar value of pet coke purchased by the Partnership for the90-day period preceding the date on which we give notice to the Partnership that we have deemed that a material adverse change has occurred. Unless otherwise agreed by us and the Partnership, the Partnership can provide such security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If such security is not provided by the Partnership, we may require the Partnership to pay for future deliveries of pet coke on acash-on-delivery basis, failing which we may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days’ prior written notice. Additionally, the Partnership may terminate the agreement within 60 days of providing security, so long as the Partnership provides five days prior written notice.

The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of

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the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or our refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.

The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.

Raw Water and Facilities Sharing Agreement

We entered into a raw water and facilities sharing agreement with the Partnership in October 2007 which (i) provides for the allocation of raw water resources between our refinery and the nitrogen fertilizer plant and (ii) provides for the management of the water intake system (consisting primarily of a water intake structure, water pumps, meters, and a short run of piping between the intake structure and the origin of the separate pipes that transport the water to each facility) which draws raw water from the Verdigris River for both our facility and the nitrogen fertilizer plant. This agreement provides that a water management team consisting of one representative from each party to the agreement will manage the Verdigris River water intake system. The water intake system is owned and operated by us. The agreement provides that both companies have an undivided one-half interest in the water rights which will allow the water to be removed from the Verdigris River for use at our refinery and the nitrogen fertilizer plant.

The agreement provides that both the nitrogen fertilizer plant and our refinery are entitled to receive sufficient amounts of water from the Verdigris River each day to enable them to conduct their businesses at their appropriate operational levels. However, if the amount of water available from the Verdigris River is insufficient to satisfy the operational requirements of both facilities, then such water shall be allocated between the two facilities on a prorated basis. This prorated basis will be determined by calculating the percentage of water used by each facility over the two calendar years prior to the shortage, making appropriate adjustments for any operational outages involving either of the two facilities.

Costs associated with operation of the water intake system and administration of water rights will be allocated on a prorated basis, calculated by us based on the percentage of water used by each facility during the calendar year in which such costs are incurred. However, in certain circumstances, such as where one party bears direct responsibility for the modification or repair of the water pumps, one party will bear all costs associated with such activity. Additionally, the Partnership must reimburse us for electricity required to operate the water pumps on a prorated basis that is calculated monthly.

Either we or the Partnership are entitled to terminate the agreement by giving at least three years’ prior written notice. Between the time that notice is given and the termination date, we must cooperate with the Partnership to allow the Partnership to build its own water intake system on the Verdigris River to be used for supplying water to its nitrogen fertilizer plant. We will be required to grant easements and access over our property so that the Partnership can construct and utilize such new water intake system, provided that no such easements or access over our property shall have a material adverse affect on our business or operations at the refinery. The Partnership will bear all costs and expenses for such construction if it is the party that terminated the original water sharing agreement. If we terminate the original water sharing agreement, the Partnership may either install a new water intake system at its own expense, or require us to sell the existing water intake system to

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the Partnership for a price equal to the depreciated book value of the water intake system as of the date of transfer.

Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The parties may obtain injunctive relief to enforce their rights under the agreement. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.

The term of the agreement is perpetual unless (1) the agreement is terminated by either party upon three years’ prior written notice in the manner described above or (2) the agreement is otherwise terminated by the mutual written consent of the parties.

Real Estate Transactions

Land Transfer. We have transferred certain parcels of land to the Partnership, including land where the Partnership expects to expand the nitrogen fertilizer facility.

Cross-Easement Agreement. We entered into a cross-easement agreement with the Partnership in October 2007 so that both we and the Partnership can access and utilize each other’s land in certain circumstances in order to operate our respective businesses. The agreement grants easements for the benefit of both parties and establishes easements for operational facilities, pipelines, equipment, access, and water rights, among other easements. The intent of the agreement is to structure easements which provides flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party’s property.

The agreement provides that facilities located on each party’s property will generally be owned and maintained by the property-owning party; provided, however, that in certain specified cases where a facility that benefits one party is located on the other party’s property, the benefited party will have the right to use, and will be responsible for operating and maintaining, the overlapping facility.

The easements granted under the agreement are non-exclusive to the extent that future grants of easements do not interfere with easements granted under the agreement. The duration of the easements granted under the agreement varies, and some are perpetual. Easements pertaining to certain facilities that are required to carry out the terms of our other agreements with the Partnership terminate upon the termination of such related agreements. We also granted a water rights easement to the Partnership which is perpetual in duration. See “— Raw Water and Facilities Sharing Agreement.”

The agreement contains an obligation to indemnify, defend and hold harmless the other party against liability arising from negligence or willful misconduct by the indemnifying party. The agreement also requires the parties to carry minimum amounts of employer’s liability insurance, commercial general liability insurance, and other types of insurance. If either party transfers its fee simple ownership interest in the real property governed by the agreement, the new owner of the real property will be deemed to have assumed all of the obligations of the transferring party under the agreement, except that the transferring party will retain liability for all obligations under the agreement which arose prior to the date of transfer.

Lease Agreement. We have entered into a five-year lease agreement with the Partnership under which we lease certain office and laboratory space to the Partnership. This agreement expires in October 2012.

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Environmental Agreement

We entered into an environmental agreement with the Partnership in October 2007 which provides for certain indemnification and access rights in connection with environmental matters affecting our refinery and the nitrogen fertilizer plant. Generally, both we and the Partnership agreed to indemnify and defend each other and each other’s affiliates against liabilities associated with certain hazardous materials and violations of environmental laws that are a result of or caused by the indemnifying party’s actions or business operations. This obligation extends to indemnification for liabilities arising out of off-site disposal of certain hazardous materials. Indemnification obligations of the parties will be reduced by applicable amounts recovered by an indemnified party from third parties or from insurance coverage.

To the extent that one party’s property experiences environmental contamination due to the activities of the other party and the contamination is known at the time the agreement was entered into, the contaminating party is required to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for expenses incurred in connection with implementing such measures.

To the extent that liability arises from environmental contamination that is caused by us but is also commingled with environmental contamination caused by the Partnership, we may elect in our sole discretion and at our own cost and expense to perform government-mandated environmental activities relating to such liability, subject to certain conditions and provided that we will not waive any rights to indemnification or compensation otherwise provided for in the agreement.

The agreement also addresses situations in which a party’s responsibility to implement such government-mandated environmental activities as described above may be hindered by the property-owning party’s creation of capital improvements on the property. If a contaminating party bears such responsibility but the property-owning party desires to implement a planned and approved capital improvement project on its property, the parties must meet and attempt to develop a soil management plan together. If the parties are unable to agree on a soil management plan 30 days after receiving notice, the property-owning party may proceed with its own commercially reasonable soil management plan. The contaminating party is responsible for the costs of disposing of hazardous materials pursuant to such plan.

If the property-owning party needs to do work that is not a planned and approved capital improvement project but is necessary to protect the environment, health, or the integrity of the property, other procedures will be implemented. If the contaminating party still bears responsibility to implement government-mandated environmental activities relating to the property and the property-owning party discovers contamination caused by the other party during work on the capital improvement project, the property-owning party will give the contaminating party prompt notice after discovery of the contamination, and will allow the contaminating party to inspect the property. If the contaminating party accepts responsibility for the contamination, it may proceed with government-mandated environmental activities relating to the contamination, and it will be responsible for the costs of disposing of hazardous materials relating to the contamination. If the contaminating party does not accept responsibility for such contamination or fails to diligently proceed with government-mandated environmental activities related to the contamination, then the contaminating party must indemnify and reimburse the property-owning party upon the property-owning party’s demand for costs and expenses incurred by the property-owning party in proceeding with such government-mandated environmental activities.

The agreement also provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement is entered into to the extent such contamination or releases are identified in reasonable detail during the period ending five years after the date of the agreement. The agreement further provides for indemnification in the case of contamination or releases which occur subsequent to the date the agreement is entered into. If one party causes such contamination or release on the other party’s property, the latter party must notify the contaminating party, and the contaminating party must take steps to implement all government-

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mandated environmental activities relating to the contamination, or else indemnify the property-owning party for the costs associated with doing such work.

The agreement also grants each party reasonable access to the other party’s property for the purpose of carrying out obligations under the agreement. However, both parties must keep certain information relating to the environmental conditions on the properties confidential. Furthermore, both parties are prohibited from investigating soil or groundwater conditions except as required for government-mandated environmental activities, in responding to an accidental or sudden contamination of certain hazardous materials, or in connection with implementation of a comprehensive coke management plan as discussed below.

In accordance with the agreement, the parties developed a comprehensive coke management plan after the execution of the environmental agreement. The plan established procedures for the management of pet coke and the identification of significant pet coke-related contamination. Also, the parties agreed to indemnify and defend one another and each other’s affiliates against liabilities arising under the coke management plan or relating to a failure to comply with or implement the coke management plan.

Either party will be entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The term of the agreement is for at least 20 years, or for so long as the feedstock and shared services agreement is in force, whichever is longer. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain of its affiliates.

We have entered into a supplement to the environmental agreement confirming that we remain responsible for existing environmental conditions on land that we transferred to the Partnership.

Omnibus Agreement

We entered into an omnibus agreement with the managing general partner and the Partnership in October 2007. The following discussion describes the material terms of the omnibus agreement.

Under the omnibus agreement the Partnership has agreed not to, and will cause its controlled affiliates not to, engage in, whether by acquisition or otherwise, (i) the ownership or operation within the United States of any refinery with processing capacity greater than 20,000 barrels per day whose primary business is producing transportation fuels or (ii) the ownership or operation outside the United States of any refinery, regardless of its processing capacity or primary business, or a refinery restricted business, in either case, for so long as we continue to own at least 50% of the Partnership’s outstanding units. The restrictions will not apply to:


	•	any refinery restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a refinery restricted business, as determined in good faith by the managing general partner’s board of directors; however, if at any time the Partnership completes such an acquisition, the Partnership must, within 365 days of the closing of the transaction, offer to sell the refinery-related assets to us for their fair market value plus any additional tax or other similar costs that would be required to transfer the refinery-related assets to us separately from the acquired business or package of assets;

	•	engaging in any refinery restricted business subject to the offer to us described in the immediately preceding bullet point pending our determination whether to accept such offer and pending the closing of any offers we accept;

	•	engaging in any refinery restricted business if we have previously advised the Partnership that our board of directors has elected not to cause us to acquire or seek to acquire such business; or

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	•	acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any refinery restricted business.

Under the omnibus agreement, we have agreed not to, and will cause our controlled affiliates other than the Partnership not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as we and certain of our affiliates continue to own at least 50% of the Partnership’s outstanding units. The restrictions do not apply to:


	•	any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by our board of directors, as applicable; however, if at any time we complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to the Partnership for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to the Partnership separately from the acquired business or package of assets;

	•	engaging in any fertilizer restricted business subject to the offer to the Partnership described in the immediately preceding bullet point pending the Partnership’s determination whether to accept such offer and pending the closing of any offers the Partnership accepts;

	•	engaging in any fertilizer restricted business if the Partnership has previously advised us that it has elected not to acquire such business; or

	•	acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any fertilizer restricted business.

Under the omnibus agreement we have also agreed that the Partnership has a preferential right to acquire any assets or group of assets that do not constitute (i) assets used in a refinery restricted business or (ii) assets used in a fertilizer restricted business. In determining whether to cause the Partnership to exercise any preferential right under the omnibus agreement, the managing general partner will be permitted to act in its sole discretion, without any fiduciary obligation to the Partnership or the unitholders whatsoever (including us). These obligations will continue until such time as we and certain of our affiliates cease to own at least 50% of the Partnership’s outstanding units.

Services Agreement

We entered into a services agreement with the Partnership and the managing general partner of the Partnership in October 2007 pursuant to which we provide certain management and other services to the Partnership and the managing general partner of the Partnership. Under this agreement, the managing general partner of the Partnership engaged us to conduct the day-to-day business operations of the Partnership. We provide the Partnership with the following services under the agreement, among others:


	•	services by our employees as the Partnership’s corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve the Partnership on a shared, part-time basis only, unless we and the Partnership agree otherwise;

	•	administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs;

	•	management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business;

	•	recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions;

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	•	managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice;

	•	recommending the payment of distributions; and

	•	managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time.

As payment for services provided under the agreement, the Partnership, the managing general partner of the Partnership, or Coffeyville Resources Nitrogen Fertilizers, LLC, the Partnership’s operating subsidiary, must pay us (i) all costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by us on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including payroll, office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges. The Partnership must pay us within 15 days for invoices we submit under the agreement.

The Partnership and its managing general partner are not required to pay any compensation, salaries, bonuses or benefits to any of our employees who provide services to the Partnership or its managing general partner on a full-time or part-time basis; we will continue to pay their compensation. However, personnel performing the actual day-to-day business and operations at the nitrogen fertilizer plant level will be employed directly by the Partnership and its subsidiaries, and the Partnership will bear all personnel costs for these employees.

Either we or the managing general partner of the Partnership may temporarily or permanently exclude any particular service from the scope of the agreement upon 90 days notice. We also have the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of our affiliates or any other person or entity, though such delegation does not relieve us from our obligations under the agreement. Either we or the managing general partner of the Partnership may terminate the agreement upon at least 90 days’ notice, but not more than one year’s notice. Furthermore, the managing general partner of the Partnership may terminate the agreement immediately if we become bankrupt, or dissolve and commence liquidation orwinding-up.

In order to facilitate the carrying out of services under the agreement, we and our affiliates, on the one hand, and the Partnership, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.

The agreement also contains an indemnity provision whereby the Partnership, its managing general partner, and Coffeyville Resources Nitrogen Fertilizers, LLC, as indemnifying parties, agree to indemnify us and our affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by us or other misconduct on our part, as provided in the agreement. The agreement also contains a provision stating that we are an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by us, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from us or certain affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement, or fraudulent or dishonest acts on our part.

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For the year ended December 31, 2007, the total amount paid or payable to us pursuant to the services agreement was $1.8 million.

Registration Rights Agreement

We entered into a registration rights agreement with the Partnership in October 2007 pursuant to which the Partnership may be required to register the sale of our units (as well as any common units issuable upon conversion of units held by us). Under the registration rights agreement, following any initial offering, we will have the right to request that the Partnership register the sale of units held by us (and the common units issuable upon conversion of units held by us) on our behalf on three occasions including requiring the Partnership to make available shelf registration statements permitting sales of common units into the market from time to time over an extended period. In addition, we have the ability to exercise certain piggyback registration rights with respect to our own securities if the Partnership elects to register any of its equity interests. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of the Partnership’s units held by us will be entitled to these registration rights.

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DESCRIPTION OF OUR INDEBTEDNESS AND THE CASH FLOW SWAP

Second Amended and Restated Credit and Guaranty Agreement

On December 28, 2006, 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 Second Amended and Restated Credit and Guaranty Agreement with Goldman Sachs Credit Partners L.P. and Credit Suisse Securities (USA) LLC, as Joint Lead Arrangers and Joint Bookrunners, Credit Suisse, as Administrative Agent, Collateral Agent, Funded LC Issuing Bank and Revolving Issuing Bank, Deutsche Bank Trust Company Americas, as Syndication Agent, and ABN Amro Bank N.V., as Documentation Agent.

If the managing general partner of the Partnership elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Any such amendments could result in changes to the Credit Facility’s pricing, mandatory prepayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice. However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend the Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering.

The following summary of the material terms of the 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 Credit Facility.

The Credit Facility provides financing of up to $1.075 billion, consisting of $775.0 million of tranche D term loans, a $150.0 million revolving credit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap.

The revolving loan facility of $150.0 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 $75.0 million sub-limit. The revolving loan commitment expires on December 28, 2012. 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 December 28, 2013.

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 funded letter of credit facility expires on December 28, 2010.

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Coffeyville Resources, LLC initially entered into a first lien credit facility and a second lien credit facility on June 24, 2005 in connection with the acquisition of all of the subsidiaries of Coffeyville Group Holdings, LLC by the Goldman Sachs Funds and the Kelso Funds. The first lien credit facility consisted of $225.0 million of term loans, $50.0 million of delayed draw term loans, a $100.0 million revolving loan facility and a funded letter of credit facility of $150.0 million, and the second lien credit facility included a $275.0 million term loan. The first lien credit facility was subsequently amended and restated on June 29, 2006 on substantially the same terms as the original agreement, as amended. The primary reason for the June 2006 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. On December 28, 2006, Coffeyville Resources, LLC repaid all indebtedness then outstanding under the first lien credit facility and second lien credit facility and entered into the Credit Facility.

Interest Rate and Fees. The tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25% or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds effective rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). The revolving loan facility borrowings bear interest at either (a) the greater of the prime rate and the Federal funds effective rate plus 0.5%, plus in either case 2.25% or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds effective rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). Letters of credit issued under the $75.0 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% per annum 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% per annum 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 Credit Facility requires the borrower to pay 0.50% in commitment fees on the unused portion of the revolving loan facility. The interest rate on the term loans under the Credit Facility on December 31, 2006 and December 31, 2007 was 8.36% and 7.98%, respectively.

Prepayments. The Credit Facility requires 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% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 and 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00;

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Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.

Amortization. The tranche D term loans are repayable in quarterly installments in a principal amount equal to the principal amount of the tranche D term loans outstanding on the quarterly installment date multiplied by 0.25% for each quarterly installment made prior to April 1, 2013 and 23.5% for each quarterly installment made during the period commencing on April 1, 2013 through maturity on December 28, 2013.

Collateral and Guarantors. All obligations under the 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, including the Partnership and CVR Special GP, LLC. Indebtedness under the 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.

Certain Covenants and Events of Default. The Credit Facility contains 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 stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The Credit Facility provides 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 December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap, the Partnership’s partnership agreement or the management agreements with Goldman, Sachs & Co. and Kelso & Company, L.P. without the prior written approval of the lenders.

The Credit Facility requires the borrower to maintain a minimum interest coverage ratio and a maximum total leverage ratio. These financial covenants are set forth in the table below:


	Minimum Interest		Maximum
Fiscal Quarter Ending	Coverage Ratio		Leverage Ratio

June 30, 2008		3.25:1.00	3.00:1.00
September 30, 2008		3.25:1.00	2.75:1.00
December 31, 2008		3.25:1.00	2.50:1.00
March 31, 2009 and thereafter		3.75:1.00	2.25:1.00 to December 31, 2009, 2.00:1.00 thereafter

In addition, the Credit Facility also requires the borrower to maintain a maximum capital expenditures limitation of $125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and $50.0 million in 2011 and thereafter. If the actual amount of capital expenditures made in any fiscal year 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 capital expenditures limitation will not apply to any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe that the limitations on our capital expenditures imposed by the Credit Facility should 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 Credit Facility.

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The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20 million 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 $20 million, events relating to employee benefit plans resulting in liability in excess of $20 million, the guarantees, collateral documents or the Credit Facility 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 Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.

The Credit Facility also contains an event of default upon the occurrence of a change of control. Under the Credit Facility, a “change of control” means (1) the Goldman Sachs Funds and the Kelso Funds cease to beneficially own and control, directly or indirectly, 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), (2) any person or group other than the Goldman Sachs Fundsand/or the Kelso Funds (a) acquires beneficial ownership of 35% or more on a fully diluted basis of the votingand/or economic interest in the capital stock of Parent and the percentage votingand/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 Credit Facility is subject to an intercreditor agreement among the lenders and the provider of the Cash Flow Swap, which relates to, among other things, priority of liens, payments and proceeds of sale of collateral.

August 2007 Credit Facilities

In August 2007, our subsidiaries entered into three new credit facilities.


	•	*$25.0 Million Secured Facility.* Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%.

	•	*$25.0 Million Unsecured Facility.* Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%.

	•	*$75.0 Million Unsecured Facility.* Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility.

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Cash Flow Swap

In connection with the Subsequent Acquisition and as required under our then-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.

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 $150.0 million funded letter of credit issued under the Credit Facility in favor of J. Aron; and

	•	to the extent J. Aron’s exposure under the derivative transaction exceeds $150.0 million, secured by the same collateral that secures our 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 Credit Facility;

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	•	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 $150.0 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 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 Credit Facility. In addition, pursuant to the Intercreditor Agreement, J. Aron is entitled to vote together as a class with the lenders under the 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 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 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~~$75.0 million.

Payment Deferrals Related to Cash Flow Swap

As a result of the flood and the temporary cessation of our Company’s operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 and then to August 31, 2008 the payment of approximately $123.7 million plus accrued interest ($~~6.2~~6.7 million as of ~~July 15,~~August 1, 2008) which we owed to J. Aron. We entered into a letter agreement with J. Aron ~~agreed~~on July 29, 2008 to ~~further~~ defer ~~these payments~~until December 15, 2008 the payment of $87.5 million of the $123.7 million plus accrued interest we owe to J. Aron. Interest will accrue on the deferred amounts from August 31, 2008 ~~but~~to the date of payment at a rate of LIBOR plus 2.75%, and we are required ~~that we use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008~~ to prepay the ~~deferred amounts, but as~~deferral amount each quarter with the greater of ~~March~~50% of the Company’s free cash flow or $5.0 million. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at our option). If we ~~were not~~consummate this notes offering before December 15, 2008, the $87.5 deferral will automatically extend to July 31, 2009. Under the terms of the deferral of $87.5 million of the amounts owed to J. Aron, we are required to use the substantial majority of any gross proceeds from any indebtedness we incur during the deferral period in excess of $125.0 million, including all of the gross proceeds received from the sale of the notes issued in connection with the sale by the underwriters of the over-allotment option net of fees, to prepay ~~any~~a portion of the deferred ~~amount.~~amounts owed to J. Aron.


	•	On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%.

	•	On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

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	•	On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half

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		of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.


	•	On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%.


	•	On July 29, 2008, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to December 15, 2008 the payment of $87.5 million of the $123.7 million (plus accrued interest) we owe to J. Aron under the Cash Flow Swap and had previously deferred to August 31, 2008. The remaining $36.2 million plus accrued interest will continue to be due on August 31, 2008 (or earlier at the company’s option). If we consummate this notes offering before December 15, 2008, the $87.5 million deferral will automatically extend to July 31, 2009. J. Aron deferred this $87.5 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. reaffirmed their guarantees of one half of the payments and (b) interest accrued on the deferred amounts from August 31, 2008 to the date of payment at the rate of LIBOR plus 2.75%.

We are in the process of negotiating a deferral of $87.5 million of these amounts owed to J. Aron until July 31, 2009. Interest will accrue on the amounts to the date of payment at the rate of LIBOR plus 2.75%. It is expected that the new deferral agreement will require the deferral amount to be prepaid each quarter with the greater of 50% of cash flow or $5 million. Any failure to make these quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts. The agreement will also require that we prepay a portion of the deferred amounts with the substantial majority of the gross proceeds from any indebtedness we incur in excess of $125.0 million, including the proceeds of this offering. We cannot assure you that the new deferral agreement will be consummated.

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DESCRIPTION OF THE NOTES

We will issue the notes under an indenture to be dated as of , 2008 (the “indenture”) between us and Wells Fargo Bank, N.A., as trustee (the “trustee”). The terms of the notes include those expressly set forth in the indenture and the notes and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the “Trust Indenture Act”).

The following description is a summary of the material provisions of the notes, the indenture and the pledge and escrow agreement and does not purport to be complete. This summary is subject to and is qualified by reference to all the provisions of the notes, the indenture and the pledge and escrow agreement, including the definitions of certain terms used in these documents. Wherever particular provisions or defined terms of the indenture, the form of note or the pledge and escrow agreement are referred to, these provisions or defined terms are incorporated in this prospectus by reference. You may request a copy of these documents from us as set forth in “Where You Can Find More Information.” We urge you to read these documents because they, and not this description, define your rights as a holder of the notes.

For purposes of this description, references to the “Company,” “we,” “our” and “us” refer only to CVR Energy, Inc. and not to any of its subsidiaries.

General

The notes:


	•	will be:


	•	our general unsecured obligations, except as described under “— Interest Escrow”;

	•	equal in right of payment to all of our other senior unsecured indebtedness;

	•	senior in right of payment to all indebtedness that is contractually subordinated to the notes;

	•	structurally subordinated to (i) all existing and future claims of our subsidiaries’ creditors, including trade creditors, and (ii) any preferred stock which our subsidiaries may issue to the extent of its liquidation preference;

	•	effectively subordinated to any of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness; and


	•	will initially be limited to an aggregate principal amount of $125 million (or $143.75 million if the underwriters exercise in full their over-allotment option to purchase additional notes), except as set forth below;

	•	will mature on , 2013 (the “maturity date”), unless earlier converted or repurchased;

	•	will be issued in denominations of $1,000 principal amount and integral multiples of $1,000 above that amount;


	•	will bear interest at a rate of % per year, payable semi-annually in arrears in cash on and of each year, beginning on , 2009 as described under “— Interest”;


	•	will be subject to optional repurchase by us at your request in connection with a fundamental change (as defined below); and

	•	will initially be represented by one or more registered notes in global form, but in certain limited circumstances described under the heading “— Global Notes, Book-Entry Form” below may be represented by notes in definitive form.

In addition, we are a holding company, and our subsidiaries conduct all of our operations and own substantially all of our assets. As a result, we are dependent on the cash flow of our subsidiaries to meet our debt obligations. Our subsidiaries are separate and distinct legal entities and none of our subsidiaries will guarantee our obligations under, or have any obligation to pay any amounts due on, the notes. As a result, the notes will be effectively subordinated to all existing and future liabilities of

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our subsidiaries, including trade payables, and to any preferred stock of our subsidiaries, to the extent of its liquidation preference. Our rights and the rights of our creditors, including holders of the notes, to participate in the assets of any of our subsidiaries upon their liquidation or recapitalization will generally be subject to the existing and future claims of those subsidiaries’ creditors. In addition, our subsidiaries are not prohibited from incurring additional debt or other liabilities. If our subsidiaries were to incur additional debt or liabilities, our ability to pay our obligations on the notes, including cash payments upon repurchase, could be adversely affected. At June 30, 2008, we had no debt outstanding. At June 30, 2008, our subsidiaries had $508.3 million aggregate principal amount of long-term debt outstanding (all of which was secured) and could borrow an additional $91.1 million under our credit facility. See “Risk Factors — Risks Related to the Notes — We will be dependent on dividends from our subsidiaries to make future payments on the notes.”

Subject to the satisfaction of certain conditions and during the periods described below, the notes may be converted into shares of common stock or cash or a combination of cash and shares of our common stock, as we so elect, at an initial ~~base~~ conversion rate ~~(as defined below)~~ of shares of our common stock per $1,000 in principal amount of notes (equivalent to an initial ~~base~~ conversion price ~~(as defined below)~~ of approximately $ per share of our common stock). If the price of our common stock at the time of determination is greater than the base conversion price, the applicable conversion rate (as defined below) will be equal to the base conversion rate plus an additional number of shares. See “— Settlement Upon Conversion.” In addition, the ~~base~~ conversion rate is subject to adjustment if certain events described below occur. See “— Conversion Rights — ~~Base~~ Conversion Rate Adjustments” and “Adjustments to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change.” You will not receive any separate cash payment for interest accrued and unpaid to the “conversion date” (as defined below), except under the limited circumstances described below. At any time on or prior to the 35th scheduled trading day prior to the maturity date of the notes, we may irrevocably elect net share settlement of the notes. If we make such an election, we will pay an amount in cash, calculated as described below, with respect to the principal amount of any notes tendered for conversion on a conversion date that follows the date of our net share settlement election, together with shares of our common stock, cash or a combination of cash and common stock, as we so elect, to the extent that our payment obligations in respect of the notes exceed the principal portion.

We use the term “note” in this “Description of the Notes” to refer to each $1,000 in principal amount of notes.

We may, without the consent of the holders, issue additional notes in an unlimited aggregate principal amount under the indenture with the same terms and with the same CUSIP numbers as the notes offered hereby;providedthat such additional notes are fungible with the notes offered hereby for U.S. federal income tax purposes. We may also from time to time repurchase the notes in open market purchases or negotiated transactions without prior notice to holders.

The registered holder of a note will be treated as the owner of it for all purposes.

The indenture will not contain any financial covenants or any restrictions on the payment of dividends, the making of investments, the incurrence of indebtedness, the granting of liens or the issuance, redemption or repurchase of securities by us. Other than the restrictions described under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes” and “— Consolidation, Merger and Sale of Assets” below, and except for the provisions set forth under “— Conversion Rights — Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change,” the indenture does not contain any covenants or other provisions designed to afford holders of the notes protection in the event of a highly leveraged transaction involving us or in the event of a decline in our credit rating as the result of a takeover, recapitalization, highly leveraged transaction or similar restructuring involving us that could adversely affect such holders. See “Risk

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Factors — Risks Related to the Notes — Some significant restructuring transactions may not constitute a fundamental change, in which case we would not be obligated to offer to repurchase the notes.”

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No sinking fund is provided for the notes, which means that the indenture does not require us to redeem or retire the notes periodically.

Transfer and Exchange

A holder of notes may transfer or exchange notes at the office of the registrar in accordance with the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents. No service charge will be imposed by us, the trustee or the registrar for any registration of transfer or exchange of notes, but we, the trustee or registrar may require a holder to pay a sum sufficient to cover any transfer tax or other similar governmental charge required by law or permitted by the indenture. We are not required to transfer or exchange any note selected or surrendered for conversion.

Interest

The notes will bear interest at a rate of % per year from the date of original issuance, expected to be , 2008, or from the most recent date to which interest has been paid or duly provided for. Interest will be payable semiannually in arrears on and of each year, beginning on , . Interest will be paid to the person in whose name a note is registered at the close of business on or , as the case may be, immediately preceding the relevant interest payment date. Interest on the notes will be computed on the basis of a360-day year composed of twelve30-day months.

Interest Escrow

Until , 2011, our interest payment obligations under the notes will be secured in part by a pledge of the escrow account described below and the assets therein pursuant to a pledge and escrow agreement. From the proceeds of this offering, the underwriters will, on our behalf, purchase and deposit with the escrow agent on the closing date of this offering “government securities” (as defined in the pledge and escrow agreement). Approximately $ million (plus an additional approximately $ million if the underwriters’ over-allotment option to purchase additional notes is exercised in full) of the proceeds from this offering will be used to purchase government securities to be deposited in the escrow account and pledged to the trustee as security for our obligations under the notes and the indenture. The government securities with respect to each of the six scheduled semi-annual interest payment dates on or prior to , 2011 will comprise interest or principal strips of U.S. Treasury securities that mature on or prior to the business day prior to such semi-annual interest payment date in an aggregate amount equal to the aggregate interest payment that would be due on such semi-annual interest payment date on the aggregate principal amount of the notes.

The pledge and escrow agreement provides for the grant by us to the trustee of security interests in the escrow account and the assets therein for the benefit of the trustee and the ratable benefit of the holders of the notes. The security interests will secure the payment and performance when due of our obligations under the notes and the indenture. The ability of holders of the notes to realize upon the funds or securities in the escrow account may be subject to certain bankruptcy law limitations in the event of our bankruptcy.

We will be required to ensure that the escrow account contains an amount of government securities and cash sufficient to fund, when due, the total aggregate amount of the first six scheduled interest payments on the notes at the time such interest payments are due. Funds will be disbursed from the escrow account to pay interest on the notes or, at our option, we may elect to make the interest payments from our available funds. If the escrow account contains government securitiesand/or cash sufficient to fund payments in excess of the remaining interest payments on the notes scheduled to occur on or prior to , 2011, such excess government securities or funds will be released to us. Upon the acceleration of the maturity of the notes or our failure to pay principal at maturity, the pledge and escrow agreement will provide for the foreclosure by the trustee upon the net

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proceeds of the escrow account. In the event of such a foreclosure, the proceeds of the escrow account will be applied:


	•	first, to all amounts due to the trustee; and


	•	second, to the payment of the amounts then due and unpaid for principal of and interest on the notes, ratably according to the amounts due and payable on such notes for principal and interest, respectively.

Our failure to pay interest on the notes within ten business days of an interest payment date through and including , 2011 will constitute an event of default under the indenture governing the notes. See “— Events of Default.”

Conversion Rights

General

Upon the occurrence of any of the conditions described under the headings “— Conversion upon Satisfaction of Trading Price Condition,” “— Conversion Based on Common Stock Price” and “— Conversion upon Specified Corporate Events,” holders may convert their notes, in whole or in part, into shares of our common stock, cash or a combination of cash and common stock, as we so elect, at an initial ~~base~~ conversion rate of shares of common stock per $1,000 in principal amount of notes, which is equivalent to an initial ~~base~~ conversion price of approximately $ per share of common stock, at any time prior to the close of business on the “scheduled trading day” (as defined below) immediately preceding , 2013. In addition, on and after , 2013, holders may convert their notes at any time prior to the close of business on the scheduled trading day immediately preceding the maturity date of the notes, regardless of the conditions described under the headings “— Conversion upon Satisfaction of Trading Price Condition,” “— Conversion Based on Common Stock Price” and “— Conversion upon Specified Corporate Events.”

“Scheduled trading day” means a day that is scheduled to be a trading day on the principal U.S. national or regional securities exchange or market on which our common stock is listed or admitted for trading or, if our common stock is not listed or admitted for trading on any exchange or market, a business day.

“Trading day” means a day during which (i) trading in our common stock generally occurs and (ii) there is no “market disruption event” (as defined below).

“Market disruption event” means the occurrence or existence on any scheduled trading day for our common stock of any suspension or limitation imposed on trading (by reason of movements in price exceeding limits permitted by the stock exchange or otherwise) in our common stock or in any options contracts or futures contracts relating to our common stock, and such suspension or limitation occurs or exists at any time within the 30 minutes prior to the closing time of the relevant exchange on such day.

“Business day”means any calendar day that is not a Saturday, Sunday or legal holiday in New York, New York and on which commercial banks are open for business in New York, New York.

If the price of shares of our common stock at the time of determination is greater than the base conversion price, the applicable conversion rate will be equal to the base conversion rate plus an additional number of shares. For a discussion of the U.S. federal income tax consequences of a change in the applicable conversion rate of the notes as a result of the price of shares of our common stock in excess of the base conversion price, see “Material United States Federal Income Tax Considerations.” In addition, the base conversion rate is subject to adjustment if certain events described below occur.

The conversion rate and the equivalent conversion price in effect at any given time isare referred to as the “applicable conversion rate.” and the “applicable conversion price,” respectively. The ~~base~~applicable conversion price at any given time will be computed by dividing $1,000 by the ~~base~~applicable conversion rate at such time. A holder may convert fewer than all of such holder’s notes so long as the notes converted are an integral multiple of $1,000 in principal amount.

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Upon conversion, you will not receive any separate payment in cash or common stock or other adjustment for accrued and unpaid interest unless such conversion occurs between a regular record date and the interest payment date to which it relates. Our settlement of conversions as described below under “— Settlement upon Conversion” will be deemed to satisfy our obligation to pay:


	•	the principal amount of the note; and

	•	accrued and unpaid interest on the note to, but not including, the conversion date.

As a result, accrued and unpaid interest to, but not including, the conversion date will be deemed to be paid in full rather than cancelled, extinguished or forfeited.

Notwithstanding the preceding paragraph, if notes are converted after 5:00 p.m., New York City time, on a record date, holders of such notes at 5:00 p.m., New York City time, on the record date will receive the interest payable on such notes on the corresponding interest payment date notwithstanding the conversion. Notes surrendered for conversion during the period from and after 5:00 p.m., New York City time, on any regular record date to 9:00 a.m., New York City time, on the immediately following interest payment date must be accompanied by funds in cash equal to the amount of interest payable on the notes so converted, except that no such payment need be made:


	•	if we have specified a “fundamental change repurchase date” (as defined below) that is after a record date and prior to the next scheduled trading day following the corresponding interest payment date;

	•	to the extent of any overdue interest, if any overdue interest remains unpaid at the time of conversion with respect to such notes; or

	•	in respect of any conversions that occur after the record date immediately preceding the maturity date.

Upon conversion, we will deliver shares of our common stock, cash, or a combination of cash and shares of our common stock, if any, as we so elect, as described under “— Settlement upon Conversion” below.

If a holder converts notes, we will pay any documentary, stamp or similar issue or transfer tax due on the issue of any shares of our common stock upon the conversion, unless the tax is due because the holder requests any shares to be issued in a name other than the holder’s name, in which case the holder will pay that tax. We will not be required to make any payment with respect to any other tax, assessment or governmental charge imposed by any other government or any political subdivision or taxing authority thereof.

~~Holders~~

If we elect to settle any conversion of notes ~~who~~entirely in our common stock, holders of such notes will not be entitled to receive any dividends payable to holders of shares of our common stock as of any record time or date before the conversion date. If we elect to ~~convert their~~settle any conversion of notes entirely in cash or using combination settlement, holders of such notes will not be entitled to receive any dividends payable to holders of shares of our common stock as of any record time or date applicable to our common stock before the last VWAP trading day of the applicable observation period (as defined below).

Conversion upon Satisfaction of Trading Price Condition

Prior to , 2013, a holder may surrender notes for conversion during the five business day period after any five consecutive trading day period (the “measurement period”) during which the “trading price” (as defined below) per $1,000 in principal amount of the notes for each day of the measurement period was less than 98% of the product of the “last reported sale price” (as defined below) of our common stock and ~~the “trading price~~applicable conversion ~~rate” (as defined below)~~rate for the notes for such date, as determined by us (or at our request the conversion agent) and subject to compliance with the procedures and conditions described below concerning the conversion agent’s obligation to make such determination (the “trading price condition”).

285

The conversion agent will have no obligation to determine the trading price of the notes unless we have requested such determination in writing; and we will have no obligation to determine the trading price of the notes unless a holder provides us with written notice which includes reasonable evidence that the trading price per $1,000 in principal amount of the notes would be less than 98% of

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the product of the last reported sale price of our common stock and the ~~trading price~~applicable conversion rate. Promptly after receiving such evidence, we will instruct the conversion agent to determine the trading price of the notes in the manner described below beginning on the next trading day and on each successive trading day until the trading price per $1,000 in principal amount of the notes is greater than or equal to 98% of the product of the last reported sale price of our common stock and the ~~trading price~~applicable conversion rate. If we do not, when we are obligated to, make a written request to the conversion agent to determine the trading price of the notes, or if we make such request to the conversion agent and the conversion agent does not make such determination, then the trading price per $1,000 in principal amount of the notes will be deemed to be less than 98% of the product of the last reported sale price of our common stock and the ~~trading price~~applicable conversion rate for such day.

If the trading price condition has been met, we will so notify the trustee and the holders of the notes. If, at any time after the trading price condition has been met, the trading price per $1,000 in principal amount of the notes is greater than or equal to 98% of the product of the last reported sale price of our common stock and the ~~trading price~~applicable conversion rate for such date, we will so notify the trustee and the holders of the notes.

The “trading price”of the notes on any date of determination means the average of the secondary market bid quotations obtained by us or our agent for $2.0 million in principal amount of the notes at approximately 3:30 p.m., New York City time, on such determination date from three nationally recognized securities dealers we select, which may include any or all of the underwriters;providedthat if three such bids cannot reasonably be obtained, but two such bids are obtained, then the average of the two bids will be used, and if only one such bid is obtained, that one bid will be used. If at least one bid for $2.0 million in principal amount of the notes cannot reasonably be obtained, or in our reasonable judgment the bid quotations are not indicative of the secondary market value of the notes, then the trading price per $1,000 in principal amount of the notes will be deemed to be less than 98% of the product of the last reported sale price of our common stock and the ~~trading price~~applicable conversion rate. Any such determination will be conclusive absent manifest error.

The “trading price conversion rate” on any day will be (i) if the last reported sale price of our common stock on the trading day immediately preceding such day is less than or equal to the base conversion price, the base conversion rate or (ii) if such last reported sale price of our common stock is greater than the base conversion price, the base conversion rate plus a number of shares equal to the product of (a) the incremental share factor and (b) (1) the difference between such last reported sale price and the base conversion price divided by (2) such last reported sale price.

The “last reported sale price” of our common stock on any date means the closing sale price per share (or if no closing sale price is reported, the average of the last bid and ask prices or, if more than one in either case, the average of the average last bid and the average last ask prices) on that date as reported in composite transactions for the principal U.S. national or regional securities exchange on which our common stock is traded. If our common stock is not listed for trading on a U.S. national or regional securities exchange on the relevant date, the “last reported sale price” will be the closing sale price (or if no closing sale price is reported, the average of the bid and ask prices or, if more than one in either case, the average of the average bid and the average ask price) for our common stock on the relevant date as reported by the OTC Bulletin Board or, if not so reported, the last quoted bid price for our common stock in the over-the-counter market on the relevant date as reported by Pink Sheets LLC or similar organization. If our common stock is not so quoted, the last reported sale price will be the average of the mid-point of the last bid and ask prices for our common stock on the relevant date from each of at least three nationally recognized independent investment banking firms, which may include any or all of the underwriters, selected by us for this purpose. Any such determination will be conclusive absent manifest error.

Conversion Based on Common Stock Price

Prior to , 2013, a holder may surrender its notes for conversion during any calendar quarter (and only during such calendar quarter) commencing after the calendar quarter ending September 30, 2008, if the last reported sale price of our common stock for 20 or more trading days

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in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the ~~base~~applicable conversion price in effect for the notes on the last

286

trading day of the immediately preceding calendar quarter. In such case, we will promptly notify the holders of the notes and the trustee. The conversion trigger price immediately following issuance of the notes is approximately $ , which is 130% of the initial ~~base~~ conversion price per share of common stock. The foregoing conversion trigger price is subject to adjustment to the ~~base~~ conversion rate as described below under “— ~~Base~~ Conversion Rate Adjustments.”

Conversion upon Specified Corporate Events

If we elect to:


	•	distribute to all or substantially all holders of our common stock any rights or warrants entitling them for a period of not more than 45 days after the date of such distribution to subscribe for or purchase shares of our common stock at a price per share less than the average of the last reported sale prices of our common stock for the ten consecutive trading day period ending on and including the trading day immediately preceding the declaration date of such distribution; or


	•	distribute to all or substantially all holders of our common stock our assets (including cash), debt securities or certain rights to purchase our securities (excluding distributions described in clause (1) or (2) under “— ~~Base~~ Conversion Rate Adjustments” and other than pursuant to a stockholders’ rights plan), which distribution has a per share fair market value as determined by our board of directors exceeding 15% of the average of the last reported sale price of our common stock on the five consecutive trading days immediately preceding the declaration date for such distribution,

we must notify the holders of the notes and the trustee at least 35 scheduled trading days prior to the “ex-date” (as defined below) for such distribution. In the case of a distribution described above that also constitutes a “fundamental change” (as defined below), such notice shall also describe in reasonable detail holders’ rights to convert their notes as described in the following paragraph. Once we have given such notice, holders may surrender their notes for conversion at any time until the earlier of (i) 5:00 p.m., New York City time, on the business day immediately prior to the ex-date for such distribution orand (ii) our announcement that such distribution will not take place, even if the notes are not otherwise convertible at such time. The “ex-date” means the first date on which the shares of our common stock trade on the relevant exchange or in the relevant market, regular way, without the right to receive the issuance or distribution in question. Holders of the notes may not exercise this conversion right if they may participate (as a result of holding the notes, and at the same time as common stock holders participate) in any of the transactions described above as if such holders of the notes held a number of shares of our common stock equal to the applicable conversion rate, multiplied by the principal amount of notes held by such holders divided by $1,000, without having to convert their notes.

If an event constituting a “fundamental change” ~~(as defined below)~~ occurs, we will notify holders and the trustee of the occurrence of any such event no later than the effective date of such event. Once we have given such notice, a holder may surrender notes for conversion at any time from the effective date of such event until the later of (i) the fundamental change repurchase date corresponding to such event and (ii) 35 scheduled trading days following the effective date of such event. Our delivery of the fundamental change conversion notice will satisfy our obligation to deliver a fundamental change repurchase right notice if it contains all of the information that would otherwise be required in a fundamental change repurchase right notice. In addition, if an event constituting a “make-whole fundamental change” (as defined below) occurs, a holder may be entitled to receive an increase in the ~~base~~ conversion rate in the form of “additional shares” (as defined below) upon any conversion as described below under “— Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change.”

You will also have the right to convert your notes if we are a party to a combination, merger, recapitalization, reclassification, binding share exchange or other similar transaction or sale or conveyance of all or substantially all of our ~~property~~properties and assets, in each case pursuant to which our

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common stock would be converted into cash, securitiesand/or other property, that does not also

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constitute a fundamental change. In such event, you will have the right to convert your notes at any time beginning 35 scheduled trading days prior to the anticipated effective date of such transaction and ending on the 35th scheduled trading day following the effective date of such transaction. We will use our reasonable best efforts to notify holders and the trustee at least 35 scheduled trading days prior to the anticipated effective date of any such transaction, and in any event will give such notice no later than the actual effective date of any such transaction. Notwithstanding the foregoing, notes will not become convertible by reason of a merger, consolidation or other transaction effected with any of our direct or indirect subsidiaries solely for the purpose of changing our state of incorporation.

Conversion Procedures

If you hold a beneficial interest in a global note, to convert you must comply with DTC’s procedures for converting a beneficial interest in a global note and, if required, pay funds equal to interest payable on the next interest payment date to which you are not entitled and, if required, pay all taxes or duties, if any.

If you hold a certificated note, to convert you must:


	•	complete and manually sign the conversion notice on the back of the note, or a facsimile of the conversion notice;

	•	deliver the conversion notice, which is irrevocable, and the note to the conversion agent;

	•	if required, furnish appropriate endorsements and transfer documents;

	•	if required, pay all transfer or similar taxes; and

	•	if required, pay funds equal to interest payable on the next interest payment date to which you are not entitled.

The date you comply with these requirements is the “conversion date” under the indenture.

If a holder has already delivered a repurchase notice as described under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes” with respect to a note, such holder may not surrender that note for conversion until the holder has withdrawn the repurchase notice in accordance with the indenture.

Settlement upon Conversion

Unless we have made the irrevocable net share settlement election (as described below), upon conversion of the notes, we will settle conversions of the notes (i) entirely in shares of our common stock, (ii) entirely in cash, or (iii) in cash for the principal amount of the notes and shares of our common stock, or cash and shares of our common stock, for the excess, if any, of the conversion value above the principal amount (“combination settlement”). We will inform the converting holders of our chosen method of settling conversions through the trustee no later than the business day immediately following the related conversion date, and, with respect to an election to settle conversions using combination settlement, we may specify in such notice the percentage (the “cash percentage”) of the daily conversion value (as defined below) in excess of the daily portion of the principal amount that we will satisfy in cash. If we do not specify the cash percentage in such notice and we have not made the irrevocable net share cash settlement election, the cash percentage will be deemed to be zero. If we do not provide such a notice in connection with any conversion and we have not made the irrevocable net share cash settlement election, we will be obligated to settle such conversion using combination settlement pursuant to clause (2) below with a cash percentage of zero.

Unless we have made the irrevocable net share settlement election, at any time prior to the 35th scheduled trading day prior to the maturity date of the notes, we may deliver a notice to the holders of the notes designating the settlement method for all conversions that occur on or after the 35th scheduled trading day prior to maturity (and, if we elect combination settlement for such conversions, we will specify the cash percentage for all such conversions, which if not specified will be deemed to be zero). If we do not deliver such a notice and we have not made the irrevocable net

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share cash settlement election, then we will settle all such conversions using combination settlement pursuant to clause (2) below with a cash percentage of zero.

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We will treat all holders of notes converting on the same trading day in the same manner. Except for all conversions that occur on or after the 35th scheduled trading day prior to maturity of the notes and unless we have made the irrevocable net share settlement election, we will not have any obligation to settle our conversion obligations arising on different trading days in the same manner. That is, we may choose on one trading day to settle in shares of our common stock only and choose on another trading day to settle in cash or a combination of cash and shares of our common stock.

At any time on or prior to the 35th scheduled trading day prior to the maturity date of the notes, we may irrevocably elect (the “irrevocable net share settlement election”) to settle conversions of the notes in the manner described in clause (2) or (3) below. If we make the irrevocable net share settlement election, we will no longer be permitted under the indenture to settle conversions of the notes in the manner described in clause (1) below. Upon making the irrevocable net share settlement election, we will promptly (i) issue a press release and post such information on our website or otherwise publicly disclose this information and (ii) provide written notice to the holders of the notes in a manner contemplated by the indenture, including through the facilities of DTC. After we have made the irrevocable net share settlement election, upon conversion of any notes, we will inform the converting holders through the trustee, no later than the business day immediately following the related conversion date, of the cash percentage with respect to such conversion. If we do not specify the cash percentage, the cash percentage will be deemed to be zero.

The irrevocable net share settlement election is in our sole discretion and does not require the consent of the holders of the notes.

The settlement amount will be computed as follows:

(1) If we elect to settle any conversion entirely in shares of our common stock, we will deliver a number of shares of our common stock to the holder of the notes on the third business day ~~immediately following~~after the ~~last day of the related observation period~~relevant conversion date equal to (i) (A) the aggregate principal amount of notes to be converted, divided by (B) $1,000, multiplied by (ii) the ~~sum of~~applicable conversion rate on the ~~daily share settlement rates for each of the 30 VWAP trading days during the related observation period~~relevant conversion date (provided that we will deliver cash in lieu of fractional shares as described below).

(2) If we elect (or are deemed to elect) combination settlement, or if we have made the irrevocable net share settlement election, we will settle each $1,000 in principal amount of notes being converted by delivering, on the third business day immediately following the last day of the related observation period, cash and shares of our common stock, if any, equal to the sum of the “daily settlement amounts” (as defined below) for each of the 30 VWAP trading days during the related observation period.

(3) If we elect to settle any conversion entirely in cash, we will settle each $1,000 in principal amount of notes being converted by delivering, on the third business day immediately following the last day of the related observation period, an amount of cash equal to the sum of the daily conversion values for each of the 30 VWAP trading days during the related observation period.

It is our current intent ~~and policy~~ to settle any conversion of the notes in the manner set forth in clause (2) above.

For purposes of calculation of the daily conversion value or the daily share settlement rate, as applicable, the applicable conversion rate for the relevant VWAP trading day will be determined as follows:


	•	~~if the daily VWAP of our common stock on such date is less than or equal to the base conversion price, the applicable conversion rate for such date will be equal to the base conversion rate; and~~

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	•	~~if the daily VWAP of our common stock on such date is greater than the base conversion price, the applicable conversion rate for such date will be equal to the following:~~


~~Base Conversion~~ ~~Rate~~		+ ((		~~(Daily VWAP of our common stock on such date − Base Conversion Price)~~ ~~Daily VWAP of our common stock on such date~~		) ×		~~Incremental Share Factor~~)

In no event, however, will the applicable conversion rate per $1,000 principal amount of notes to be converted for any date exceed shares of our common stock, subject to adjustment in the same manner as the base conversion rate as described herein.

~~The “~~~~base conversion rate~~” per $1,000 principal amount of notes is initially shares of our common stock, subject to adjustment as described under “— Base Conversion Rate Adjustments.” The base conversion rate may also be adjusted in certain corporate transactions. See “— Adjustment to Shares Delivered upon Conversion in Connection with a~~Make-Whole~~ ~~Fundamental Change.”~~

~~The “~~~~base conversion price~~~~” is the dollar amount (initially, approximately $ ) determined by dividing $1,000 by the base conversion rate.~~

~~The “~~~~daily share settlement rate~~” for each of the 30 VWAP trading days during the observation period means, for each of the 30 consecutive VWAP trading days during the observation period, (1) the applicable conversion rate for such VWAP trading day, divided by (2) 30.

~~The “~~~~incremental share factor~~~~” per $1,000 principal amount of notes is initially shares of our common stock, subject to the same proportional adjustment as the base conversion rate.~~

For purposes of the calculation in clause (2) above, the “daily settlement amount” for each of the 30 VWAP trading days during the relevant observation period means:


	•	an amount of cash (the “principal portion”) equal to the lesser of (x) the quotient of $1,000 and 30 and (y) the daily conversion value for such VWAP trading day; plus

	•	if such daily conversion value for such VWAP trading day exceeds the principal portion, either:


	•	(i) if the cash percentage equals zero, a number of shares of our common stock (the “maximum deliverable shares”) equal to (A) the difference between such daily conversion

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		value and the principal portion, divided by (B) the daily VWAP of our common stock for such VWAP trading day, or


	•	(ii) if the cash percentage is greater than zero, (A) an amount of cash equal to the product of (x) the cash percentage, (y) the maximum deliverable shares and (z) the daily VWAP of our common stock for such VWAP trading day, and (B) a number of shares of our common stock equal to the product of (x) 100% minus the cash percentage and (y) the maximum deliverable shares.

The “observation period” with respect to any note means:


	•	with respect to any conversion date occurring on or after the 35th scheduled trading day prior to the maturity date of the notes, the 30 consecutive VWAP trading day period beginning on, and including, the 32nd scheduled trading day prior to the maturity date (or if such day is not a VWAP trading day, the next succeeding VWAP trading day); and

	•	in all other instances, the 30 consecutive VWAP trading day period beginning on and including the third VWAP trading day after the conversion date.

The “daily conversion value” means, for each of the 30 consecutive VWAP trading days during the observation period, 1/30th of the product of (1) the applicable conversion rate and (2) the “daily VWAP” (as defined below) of our common stock, or the consideration into which our common stock has been converted in connection with certain corporate transactions, on such VWAP trading day. Any determination of the daily conversion value by us will be conclusive absent manifest error.

The “daily VWAP” of our common stock means, for each of the 30 consecutive VWAP trading days during the observation period, the per share volume-weighted average price as displayed under the heading “Bloomberg VWAP” on Bloomberg page CVI.N <equity> AQR (or any equivalent

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successor page) in respect of the period from the scheduled open of trading on the principal trading market for our common stock to the scheduled close of trading on such market on such VWAP trading day (without regard toafter-hours trading), or if such volume-weighted average price is unavailable, the market value of one share of our common stock (or one unit of reference property consisting of marketable equity securities) on such VWAP trading day using a volume-weighted method (or, in the case of reference property (one “unit” of reference property being the kind and amount (in the same proportions) of reference property that a holder of one share of our common stock would receive in connection with the events described below under “ — ~~Base~~ Conversion Rate Adjustments — Treatment of Reference Property”) consisting of cash, the amount of such cash or in the case of reference property other than marketable equity securities or cash, the market value thereof), in each case as determined by a nationally recognized independent investment banking firm retained for this purpose by us.

“VWAP trading day” means a day during which (i) trading in our common stock generally occurs on the principal U.S. national or regional securities exchange or market on which our common stock is listed or admitted for trading and (ii) there is no “VWAP market disruption event” (as defined below). If our common stock is not so listed or traded, then “VWAP trading day” means a business day.

“VWAP market disruption event” means (i) a failure by the principal U.S. national or regional securities exchange or market on which our common stock is listed or admitted to trading to open for trading during its regular trading session or (ii) the occurrence or existence prior to 1:00 p.m. on any scheduled trading day for our common stock for an aggregate period of one half hour or more of any suspension or limitation imposed on trading (by reason of movements in price exceeding limits permitted by the stock exchange or otherwise) in our common stock or in any options contracts or futures contracts relating to our common stock.

Notwithstanding the foregoing, we will deliver cash in lieu of any fractional shares of our common stock deliverable upon conversion based on the daily VWAP (i) on ~~(i)~~ the last VWAP trading day of the applicable observation ~~period.~~period, in the case of conversions settled in cash or a combination of cash and shares of our common stock, and (ii) the conversion date (or, if the conversion date is not on a trading day, the next following trading day) for conversions settled entirely in shares of our common stock.

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The indenture requires us to pay the principal portion of the conversion consideration of the notes in cash if we have made the net share settlement election, and we may be required to repurchase the notes for cash at a price equal to 100% of the principal amount thereof, plus accrued and unpaid interest, if any, upon the occurrence of a fundamental change. 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, including our payment obligations with respect to the notes to the extent not secured by the pledge and escrow agreement, 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. 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 their credit facilities, tax considerations and legal restrictions. In particular, our subsidiaries’ credit facilities currently impose significant limitations on the ability of our subsidiaries to make distributions to us and consequently our ability to meet our obligations. See “Risk Factors — Risks Related to the Notes — We will be dependent on dividends from our subsidiaries to make future payments on the notes.” Our failure to pay in cash the principal portion of the notes when converted would result in an event of default with respect to the notes.

~~Base~~ Conversion Rate Adjustments

The ~~base~~ conversion rate will be adjusted as described below. However we will not make any adjustments to the ~~base~~ conversion rate if holders of the notes participate (as a result of holding the notes, and at the same time as common stockholders participate) in any of the transactions described below as if such holders of the notes held a number of shares of our common stock equal to the applicable conversion rate, multiplied by the principal amount of notes held by such holders divided by $1,000, without having to convert their notes (provided that this exception will not apply to any adjustment described under “— Adjustment to Shares Delivered upon Conversion in Connection with

~~289~~

a Make-Whole Fundamental Change”). For purposes of this “ — Base Conversion Rate Adjustments” subsection, each adjustment event that applies to the base conversion rate shall also be applied to the incremental share factor in the same manner, and all other references to base conversion rate shall be deemed to refer to both the base conversion rate and the incremental share factor. Accordingly, for purposes of determining any adjustment to the incremental share factor or any other effect on the incremental share factor, each reference to the base conversion rate appearing below shall be replaced with a reference to the incremental share factor. If we adjust the ~~base~~ conversion rate pursuant to the provisions below, we will provide written notification of such adjustment to the conversion agent and the trustee.

Adjustment Events.

(1) If we issue shares of our common stock as a dividend or distribution on shares of our common stock, or if we effect a share split or share combination, the ~~base~~ conversion rate will be adjusted based on the following formula:


CR' = CR₀ ×		OS' OS₀

where,

CR₀ = the ~~base~~ conversion rate in effect as of the close of business on the day immediately preceding the ex-date for such dividend or distribution or the effective date of such share split or combination, as the case may be;

CR' = the ~~base~~ conversion rate in effect as of the opening of business on the ex-date for such dividend or distribution or the effective date of such share split or combination, as the case may be;

OS₀ = the number of shares of our common stock outstanding immediately prior to the ex-date for such dividend or distribution or the effective date of such share split or combination, as the case may be; and

OS' = the number of shares of our common stock that would be outstanding as of the opening of business on the ex-date for such dividend or distribution immediately after giving effect to such dividend or distribution or immediately after the effective date of such share split or combination, as the case may be.

Any adjustment made pursuant to this clause (1) shall become effective on the date that is immediately after (x) the ex-date for such dividend or other distribution or (y) the date on which such split or combination becomes effective, as applicable. If any dividend or distribution described in this

291

clause (1) is declared but not paid or made, the new ~~base~~ conversion rate shall be readjusted to the ~~base~~ conversion rate that would be in effect if such dividend or distribution had not been declared.

(2) If we distribute to all or substantially all holders of our common stock any rights or warrants (other than rights issued pursuant to a stockholders’ rights plan) entitling them for a period of not more than 45 days after the date of such distribution to subscribe for or purchase shares of our common stock, at a price per share less than the average of the last reported sale prices of our common stock for the ten consecutive trading day period ending on and including the trading day immediately preceding the ex-date for such distribution, the ~~base~~ conversion rate will be adjusted based on the following formula:


CR' = CR₀ ×		OS₀ + X OS₀ + Y

where,

CR₀ = the ~~base~~ conversion rate in effect as of the close of business on the day immediately preceding the ex-date for such distribution;

CR' = the ~~base~~ conversion rate in effect as of the opening of business on the ex-date for such distribution;

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OS₀ = the number of shares of our common stock outstanding immediately prior to the ex-date for such distribution;

X = the total number of shares of our common stock issuable pursuant to such rights or warrants; and

Y = the number of shares of our common stock equal to the aggregate price payable to exercise such rights or warrants divided by the average of the last reported sale prices of our common stock for the ten consecutive trading day period ending on and including the trading day immediately preceding the ex-date for such distribution.

For purposes of this clause (2), in determining whether any rights or warrants entitle the holder to subscribe for or purchase our common stock at less than the average of the last reported sale prices of our common stock for the ten consecutive trading day period ending on and including the trading day immediately preceding the ex-date for such distribution, and in determining the aggregate exercise or conversion price payable for such common stock, there shall be taken into account any consideration received by the Company for such rights or warrants and any amount payable on exercise or conversion thereof, with the value of such consideration, if other than cash, to be determined by our board of directors or a committee thereof. If any right or warrant described in this paragraph (2) is not exercised or converted prior to the expiration of the exercisability or convertibility thereof, the new ~~base~~ conversion rate shall be readjusted to the ~~base~~ conversion rate that would have been in effect if our right or warrant had not been issued.

(3) If we distribute shares of our capital stock, evidences of our indebtedness or other assets or property of ours to all or substantially all holders of our common stock, excluding:


	•	dividends or distributions referred to in clause (1) or (2) above;

	•	dividends or distributions paid exclusively in cash referred to in clause (4) below; and

	•	spin-offs described below in this clause (3);

then the ~~base~~ conversion rate will be adjusted based on the following formula:


CR' = CR₀ ×		SP₀ SP₀ − FMV

where,

CR₀ = the ~~base~~ conversion rate in effect as of the close of business on the day immediately preceding the ex-date for such distribution;

CR' = the ~~base~~ conversion rate in effect as of the opening of business on the ex-date for such distribution;

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SP₀ = the average of the last reported sale prices of our common stock over the ten consecutive trading day period ending on the trading day immediately preceding the ex-date for such distribution; and

FMV = the fair market value as determined in good faith by our board of directors or a committee thereof of the shares of capital stock, evidences of indebtedness, assets or property distributed with respect to each outstanding share of our common stock on the ex-date for such distribution.

With respect to an adjustment pursuant to this clause (3) where there has been a payment of a dividend or other distribution on our common stock in shares of capital stock of any class or series, or similar equity interest, of or relating to a subsidiary or other of our business units, which we refer to as a “spin-off,” the ~~base~~ conversion rate in effect immediately before 5:00 p.m., New York City time, on the tenth trading day immediately following the effective date of the spin-off will be increased based on the following formula:


CR' = CR₀ ×		FMV₀ + MP₀ MP₀

~~291~~

where,

CR₀ = the ~~base~~ conversion rate in effect immediately before 5:00 p.m., New York City time, on the tenth trading day immediately following the effective date of the spin-off;

CR' = the ~~base~~ conversion rate in effect immediately after 5:00 p.m., New York City time, on the tenth trading day immediately following the effective date of the spin-off;

FMV₀ = the average of the last reported sale prices of the capital stock or similar equity interest distributed to holders of our common stock applicable to one share of our common stock over the ten consecutive trading day period beginning on and including the trading day immediately following the effective date of the spin-off; and

MP₀ = the average of the last reported sale prices of our common stock over the ten consecutive trading day period beginning on and including the trading day immediately following the effective date of the spin-off.

The adjustment to the ~~base~~ conversion rate under this clause (3) will occur at the close of business on the tenth trading day from the effective date of the spin-off;providedthat in respect of any conversion within the ten trading days beginning on the trading day immediately following the effective date of any spin-off, references in this clause (3) with respect to the spin-off to ten trading days shall be deemed replaced with such lesser number of trading days as have elapsed between the effective date of such spin-off and the conversion date in determining the ~~base~~applicable conversion rate.

If any such dividend or distribution described in this clause (3) is declared but not paid or made, the new ~~base~~ conversion rate shall be readjusted to be the ~~base~~ conversion rate that would then be in effect if such dividend or distribution had not been declared.

For the avoidance of doubt, the adjustment in this clause (3) does not apply to ~~any~~(a) conversions in connection with a spin-off fundamental change or (b) distributions to the extent that the right to convert notes has been changed into the right to convert into reference property in respect of such distribution as described under “Treatment of Reference Property” below.

(4) If we pay any cash dividends or distributions to all or substantially all holders of our common stock, the ~~base~~ conversion rate will be adjusted based on the following formula:


CR' = CR₀ ×		SP₀ SP₀ − C

where,

CR₀ = the ~~base~~ conversion rate in effect as of the close of business on the day immediately preceding the ex-date for such dividend or distribution;

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CR' = the ~~base~~ conversion rate in effect as of the opening of business on the ex-date for such dividend or distribution;

SP₀ = the average of the last reported sale prices of our common stock during the ten trading day period ending on and including the trading day immediately preceding the ex-date for such dividend or distribution; and

C = the amount in cash per share we distribute to holders of our common stock.

Such adjustment shall become effective immediately after the opening of business on the ex-date for such dividend or distribution. If any such dividend or distribution described in this clause (4) is declared but not paid or made, the new ~~base~~ conversion rate shall be readjusted to be the ~~base~~ conversion rate that would then be in effect if such dividend or distribution had not been declared.

For the avoidance of doubt, the adjustment in this clause (4) does not apply to any distributions to the extent that the right to convert notes has been changed into the right to convert into reference property in respect of such distribution as described under “Treatment of Reference Property” below.

(5) If we or any of our subsidiaries make a payment in respect of a tender offer or exchange offer for our common stock, to the extent that the cash and value (which will be as determined by our board of directors or a committee thereof) of any other consideration included in the payment per

~~292~~

share of our common stock exceeds the average of the last reported sale prices of our common stock over the ten consecutive trading days beginning on, and including, the trading day next succeeding the last date on which tenders or exchanges may be made pursuant to such tender or exchange offer, the ~~base~~ conversion rate will be increased based on the following formula:


CR' = CR₀ ×		AC + (SP' × OS') OS₀ × SP'

where,

CR₀ = the ~~base~~ conversion rate in effect on the date such tender or exchange offer expires;

CR' = the ~~base~~ conversion rate in effect on the day next succeeding the date such tender or exchange offer expires;

AC = the aggregate value of all cash and any other consideration as determined by our board of directors or a committee thereof paid or payable for shares purchased in such tender or exchange offer;

OS₀ = the number of shares of our common stock outstanding immediately prior to the date such tender or exchange offer expires;

OS' = the number of shares of our common stock outstanding immediately after the date such tender or exchange offer expires (after giving effect to such tender offer or exchange offer); and

SP' = the average of the last reported sale prices of our common stock over the ten consecutive trading day period beginning on, and including, the trading day next succeeding the date such tender or exchange offer expires.

The adjustment to the ~~base~~ conversion rate under this clause (5) will occur at the close of business on the tenth trading day from the trading day next succeeding the date such tender or exchange offer expires;providedthat in respect of any conversion within ten trading days immediately following, and including, the expiration date of any tender or exchange offer, references in this clause (5) with respect to ten consecutive trading days shall be deemed replaced with such lesser number of trading days as have elapsed between the expiration date of such tender or exchange offer and the conversion date in determining the ~~base~~applicable conversion rate.

In the event that we are obligated to purchase shares pursuant to such tender offer, but we are prevented by applicable law from effecting any or all such purchases or any or all such purchases are rescinded, the new ~~base~~ conversion rate will again be adjusted to the ~~base~~ conversion rate that would have been in effect based upon the number of shares actually purchased.

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If the application of any of the foregoing formulas (other than in respect of a share combination) would result in a decrease in the ~~base~~ conversion rate, no adjustment to the ~~base~~ conversion rate will be made.

If the effective date for any adjustment event occurs during an observation period for any notes, then we will make proportional adjustments to the ~~base~~ conversion rate for each VWAP trading day during the portion of such observation period preceding the effective date of such adjustment event.

Events that Will Not Result in Adjustments. Except as described in this section or in “— Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change” below, we will not adjust the ~~base~~ conversion rate. Without limiting the foregoing, the ~~base~~ conversion rate will not be adjusted:


	•	upon the issuance of any shares of our common stock pursuant to any present or future plan providing for the reinvestment of dividends or interest payable on our securities and the investment of additional optional amounts in shares of our common stock under any plan;

	•	upon the issuance of any shares of our common stock or options or rights to purchase or acquire those shares pursuant to any present or future employee, director or consultant benefit plan or program or stock purchase plan of or assumed by us or any of our subsidiaries;

~~293~~


	•	upon the issuance of any shares of our common stock pursuant to any option, warrant, right or exercisable, exchangeable or convertible security not described in the preceding bullet and outstanding as of the date the notes were first issued;


	•	for a change in the par value (or a change to no par value) of our common stock;


	•	for accumulated and unpaid dividends (except as provided in clause (4) of this section “— ~~Base~~ Conversion Rate Adjustments — Adjustment Events”); or


	•	for accrued and unpaid interest.

In addition, except as stated above, the ~~base~~ conversion rate will not be adjusted for the issuance or acquisition of shares of our common stock or any securities convertible into or exchangeable for shares of our common stock or carrying the right to purchase any of the foregoing.

Adjustments to the ~~base~~ conversion rate will be calculated to the nearest 1/10,000th of a share. No adjustment to the ~~base~~ conversion rate will be required unless the adjustment would require an increase or decrease of at least 1% of the ~~base~~ conversion rate. However, we will carry forward any adjustments that are less than 1% of the ~~base~~ conversion rate that we elect not to make and take them into account upon the earliest of (1) any conversion of notes, (2) each anniversary of the date of issuance of the notes, (3) each VWAP trading day during the period beginning on, and including, the 32nd scheduled trading day prior to the maturity date and (4) such time as all adjustments that have not been made prior thereto would have the effect of adjusting the ~~base~~ conversion rate by at least 1%.

Treatment of Reference Property. In the event of:


	•	any reclassification of our common stock (other than a change in par value, or from par value to no par value, or from no par value to par value);

	•	a consolidation, binding share exchange, recapitalization, reclassification, merger, combination or other similar event (other than a change in par value, or from par value to no par value, or from no par value to par value); or


	•	a sale, transfer or conveyance to another person of all or substantially all of our ~~property~~properties and assets (other than a spin-off fundamental change),

in which holders of our outstanding common stock would be entitled to receive cash, securities or other property for their shares of common stock, you will be entitled thereafter to convert your notes into the same type of consideration that holders of shares of our common stock would have been entitled to receive in connection with these events (such consideration, “reference property”), subject to our right to elect to settle conversions, in whole or in part, in shares of common stock (or reference property), cash or a combination of cash and shares of our common stock (or reference property). However, for any conversions settled in cash or using combination settlement, and for any conversions

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after we make the irrevocable net share settlement election, upon conversion, you will receive cash and reference property, if any, determined as described under “— Settlement upon Conversion.” The amount of reference property you receive upon conversion will be based on the applicable conversion rate, and, if applicable, the daily conversion values of the reference property during the observation period relating to such ~~conversion and the base conversion rate and incremental share factor in effect immediately prior to the events listed above in this subsection “Treatment of Reference Property.”~~conversion.

For purposes of the foregoing, the type and amount of consideration that a holder of our common stock would have been entitled to in the case of reclassifications, consolidations, mergers, sales or transfers of assets or other transactions that cause our common stock to be converted into the right to receive more than a single type of consideration determined, based in part upon any form of stockholder election, will be deemed to be (i) if holders of the majority of our shares of common stock affirmatively make such an election, the weighted average of the types and amounts of consideration received by the holders of our common stock that affirmatively make such an election or (ii) if the holders of a majority of the shares of our common stock do not affirmatively make such an election, the types and amount of consideration actually received by such holders.

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Notwithstanding the foregoing, solely for notes surrendered for conversion in connection with a spin-off fundamental change, during the period beginning on the effective date of such spin-off fundamental change and ending on the close of business on the business day immediately prior to the related fundamental change repurchase date, the “reference property” in respect of each share of our common stock will be deemed to consist of (1) one share of our common stock and (2) the ownership interests in the person to which all or substantially all of our properties or assets are conveyed or transferred in connection with such spin-off fundamental change (the “spin-off company”) that a holder of one share of our common stock would have been entitled to receive in connection with such spin-off fundamental change.

For the avoidance of doubt, all references to shares of our common stock in this Description of Notes (other than in this “— Conversion Rights — Treatment of Reference Property”) will be deemed to refer to units of reference property during any period in which the notes are convertible into reference property.

Treatment of Rights. We do not currently have a preferred stock rights plan. To the extent that we have a rights plan in effect upon conversion of the notes into common stock, you will receive, in addition to any common stock and in lieu of any adjustment to the ~~base~~ conversion rate, the rights under the rights plan, unless prior to any conversion, the rights plan expires or terminates or the rights have separated from the common stock, in which case the ~~base~~ conversion rate will be adjusted at the time of separation as if we distributed to all holders of our common stock, shares of our capital stock, evidences of indebtedness or assets as described in clause (3) under “— Adjustment Events” above, subject to readjustment in the event of the expiration, termination or redemption of such rights. In lieu of any such adjustment, the Company may amend such rights plan to provide that upon conversion of the notes the holders will receive, in addition to the shares of common stock issuable upon such conversion, the rights which would have attached to such common stock if the rights had not become separated from the common stock under such rights plan.

Voluntary Increases of ~~Base~~ Conversion Rate. We are permitted, to the extent permitted by law and the rules of The New York Stock Exchange or any other securities exchange on which our common stock is then listed, to increase the ~~base~~ conversion rate of the notes by any amount for a period of at least 20 business days, if our board of directors determines that such increase would be in our best interest. If we make such determination, it will be conclusive and we will notify the holders of the notes and the trustee of the increased ~~base~~ conversion rate and the period during which it will be in effect at least 15 days prior to the date the increased ~~base~~ conversion rate takes effect, and otherwise in accordance with law. We may also, but are not required to, increase the ~~base~~ conversion rate to avoid or diminish income tax to holders of our common stock or rights to purchase shares of our common stock in connection with a dividend or distribution of shares or rights to acquire shares or similar event.

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Tax Effect. A holder of the notes may, in some circumstances, be deemed to have received a distribution or dividend subject to U.S. federal income or withholding tax as a result of a change in, or the absence of a change in, the ~~applicable~~ conversion rate. For instance, if the ~~base~~ conversion rate is adjusted upon the distribution of cash dividends to holders of our shares of common stock, holders of the notes may be deemed to receive a taxable distribution or dividend even though the holders have not actually received any cash or property as a result of such adjustment. For a discussion of the U.S. federal income and withholding tax consequences of a change in, or the absence of a change in, the ~~applicable~~ conversion rate, see “Material United States Federal Income Tax Considerations.”

Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change

If a holder of notes elects to convert its notes in connection with a make-whole fundamental change, the ~~base~~ conversion rate will be increased by an additional number of shares of common stock (the “additional shares”) as described below. A conversion shall be deemed to be in connection with a make-whole fundamental change if such conversion occurs on or after the effective date of such make-whole fundamental change and prior to the close of business on the business day immediately ~~prior to~~preceding the related fundamental change repurchase date. We will notify holders and the trustee of the effective date of any make-whole fundamental change, and issue a press release, on the effective date of such transaction. We will settle conversions of notes as described above under “— Settlement upon Conversion.”

A “make-whole fundamental change” will be deemed to have occurred if any fundamental change set forth in clause (1), (2), (5) or ~~(5)~~(6) of the definition of “fundamental change” (as described below under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes”) occurs.

The number of additional shares by which the ~~base~~ conversion rate will be increased for conversions in connection with a make-whole fundamental change will be determined by reference to the table below, based on the earliest of the date on which such make-whole fundamental change is publicly announced, occurs or becomes effective (the “make-whole reference date”) and the price (the “stock price”) paid per share of our common stock in connection with the make-whole fundamental

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change. If holders of our common stock receive only cash consideration for their shares of common stock (in a single per-share amount, other than with respect to appraisal and similar rights) in connection with a make-whole fundamental change, the stock price will be the cash amount paid per share in such make-whole fundamental change. Otherwise, the stock price will be the average of the last reported sale prices of our common stock over the ten consecutive trading day period ending on and including the trading day immediately preceding the date on which such make-whole fundamental change occurs or becomes effective.

The stock prices set forth in the first column of the table below (i.e., the row headers) will be adjusted as of any date on which the ~~base~~ conversion rate of the notes is otherwise adjusted. The adjusted stock prices will equal the stock prices applicable immediately prior to such adjustment, multiplied by a fraction, the numerator of which is the ~~base~~ conversion rate immediately prior to the adjustment giving rise to the stock price adjustment and the denominator of which is the ~~base~~ conversion rate as so adjusted. The number of additional shares will be adjusted in the same manner as the ~~base~~ conversion rate as set forth under “— ~~Base~~ Conversion Rate Adjustments.”

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The following table sets forth the adjustments to the ~~base~~ conversion rate, expressed as a number of additional shares to be received per $1,000 in principal amount of the notes, in connection with a make-whole fundamental change.


Stock	Make-Whole Reference Date
Price	2008	2009	2010	2011	2012	2013

$
$
$
$
$
$
$
$
$
$
$
$
$
$

The exact stock prices and make-whole reference dates may not be set forth in the table above, in which case:


	•	If the stock price is between two stock price amounts in the table or the make-whole reference date is between two dates in the table, the number of additional shares will be determined by a straight-line interpolation between the number of additional shares set forth for the higher and lower stock price amounts and the two dates, as applicable, based on a365-day year.


	•	If the stock price is greater than $ per share, subject to adjustment, no additional shares will be added to the ~~base~~ conversion rate.


	•	If the stock price is less than $ per share, subject to adjustment, no additional shares will be added to the ~~base~~ conversion rate.

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Our obligation to increase the ~~base~~ conversion rate as described above could be considered a penalty, in which case the enforceability thereof would be subject to general principles of equity as they relate to economic remedies.

For a discussion of the U.S. federal income tax consequences of an adjustment to the ~~base~~ conversion rate of the notes in connection with a make-whole fundamental change, see “Material United States Federal Income Tax Considerations.”

Fundamental Change Permits Holders to Require Us to Repurchase Notes

If a “fundamental change” (as defined below) occurs at any time, you will have the right, at your option, to require us to repurchase all of your notes, or any portion of the principal amount thereof that is equal to $1,000 or an integral multiple of $1,000, on a date (the “fundamental change repurchase date”) of our choosing that is not less than 15 nor more than 35 days (or a longer period if required by law) after the date of the “fundamental change repurchase right notice” (as defined below). The price we are required to pay (the “fundamental change repurchase price”) is equal to 100% of the principal amount of the notes to be repurchased plus accrued and unpaid interest to, but not including, the fundamental change repurchase date, unless such fundamental change repurchase date falls after a

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regular record date and on or prior to the corresponding interest payment date, in which case we will pay the full amount of accrued and unpaid interest payable on such interest payment date to the holder of record as of the close of business on the corresponding regular record date. Any notes repurchased by us will be paid for in cash.

A “fundamental change” will be deemed to have occurred if any of the following occurs:

(1) (A) any person other than a Permitted Holder acquires beneficial ownership, directly or indirectly, through a purchase, tender or exchange offer, merger or other acquisition transaction or series of transactions, of shares of our capital stock entitling such person to exercise 50% or more of the total voting power of all shares of our capital stock entitled to vote generally in elections of directors or (B) Permitted Holders when taken together acquire beneficial ownership, directly or indirectly, through a purchase, tender or exchange offer, merger or other acquisition transaction or series of transactions, of shares or our capital stock entitling Permitted Holders when taken together to exercise 75% or more of the total voting power of all shares of our capital stock entitled to vote generally in elections of directors, other than, in the case of either clause (A) or (B), any transaction covered by the first bullet under clause (2) below where no person becomes the direct or indirect beneficial owner of common stock representing 50% or more (or, in the case of Permitted Holders when taken together, 75% or more) of the total voting power of all shares of capital stock entitled to vote generally in elections of directors of the continuing or surviving person; or

(2) we (i) merge or consolidate with or into any other person, another person merges with or into us, or we convey, sell, transfer or lease all or substantially all of our properties or assets to another person, or (ii) engage in any recapitalization, reclassification or other transaction in which all or substantially all of our common stock is exchanged for or converted into cash, securities or other property, in ~~each~~either case, other than any ~~transaction:~~transaction (except a spin-off fundamental change):


	•	that does not result in a reclassification, conversion, exchange or cancellation of our outstanding common stock and pursuant to which the holders of our common stock immediately prior to the transaction are entitled to exercise, directly or indirectly, 50% or more of the total voting power of all shares of capital stock entitled to vote generally in elections of directors of the continuing or surviving person immediately after such transaction in substantially the same proportions as their respective ownership of our voting securities immediately prior to the transaction; or


	•	which is effected solely to change our jurisdiction of incorporation and results in a reclassification, conversion or exchange of outstanding shares of our common stock solely into shares of common stock of the surviving entity; or

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(3) the first day on which a majority of the members of our board of directors does not consist of continuing directors; or

(4) we are liquidated or dissolved or holders of our common stock approve any plan or proposal for our liquidation or dissolution; or

(5) if shares of our common stock, or shares of any other common stock into which the notes are convertible pursuant to the terms of the indenture, are not listed for trading on any of the New York Stock Exchange, the NASDAQ Global Market or the NASDAQ Global Select Market (or any of their respective successors); or

(6) we convey or transfer all or substantially all of our properties and assets to another person in a spin-off transaction;

providedthat the definition of fundamental change shall not include any event under clause (1) or any event specified under clause (2), including, without limitation, the creation of a holding company, in each case, if at least 90% of the consideration paid for our common stock (excluding cash payments for fractional shares and cash payments made pursuant to dissenters’ appraisal rights and cash dividends) in connection with such event consists of shares of common stock or equivalent common

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equity traded on any of the New York Stock Exchange, the NASDAQ Global Market or the NASDAQ Global Select Market (or any of their respective successors) (or that will be so traded or quoted immediately following the completion of the merger or consolidation or such other transaction or creation of a holding company) and, as a result of such transaction or transactions, the notes become exchangeable or convertible into such shares of such common stock or equivalent common equity pursuant to “— ~~Base~~ Conversion Rate Adjustments — Treatment of Reference Property” above.

For purposes of these provisions, whether a person is a “beneficial owner” will be determined in accordance withRule 13d-3 under the Exchange Act, and “person” includes any syndicate or group that would be deemed to be a “person” under Section 13(d)(3) of the Exchange Act.

The phrase “all or substantially all” as it is used in the definition of fundamental change will likely be interpreted under applicable state law and will be dependent upon particular facts and circumstances. There is a degree of uncertainty in interpreting this phrase. Accordingly, the ability of a holder of the notes to require us to purchase its notes as a result of the sale, lease or transfer of less than all of our assets may be uncertain.

“Continuing directors” means (i) individuals who on the date of original issuance of the notes constituted our board of directors and (ii) any new directors whose election to our board of directors or whose nomination for election by our stockholders was approved by at least a majority of our directors then still in office (or a duly constituted committee thereof), either who were directors on the date of original issuance of the notes or whose election or nomination for election was previously so approved.

“Permitted Holder” means any of (1) Coffeyville Acquisition II LLC, The Goldman Sachs Group, Inc., Goldman, Sachs & Co., GS Capital Partners V Fund, L.P., GS Capital Partners V Offshore Fund, L.P., GS Capital Partners V GmbH & Co., KG and GS Capital Partners V Institutional, L.P. and any investment fund or vehicle that is an affiliate of, and wholly managed or sponsored by, any of the foregoing, (2) Coffeyville Acquisition LLC, Kelso & Company, L.P., Kelso Investment Associates VII, L.P., KEP ~~Fertilizer,~~VI, LLC, Kelso GP VII, LLC, Kelso GP VII, L.P. and any investment fund or vehicle that is an affiliate of, and wholly managed or sponsored by, any of the foregoing, (3) Coffeyville Acquisition III LLC and CVR GP, LLC and (4) members of senior management of CVR Energy, Inc., their family members, and trusts for any of their benefit.

After the occurrence of a fundamental change, but on or before the tenth day following such occurrence, we will notify all holders of the notes and the trustee and paying agent of the occurrence of the fundamental change and of the resulting repurchase right, if any (the “fundamental change repurchase right notice”). Such notice shall state, among other things:


	•	the events causing the fundamental change;

	•	the date of the fundamental change;

	•	the last date on which a holder may exercise the repurchase right, if applicable;

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	•	the fundamental change repurchase price, if applicable;

	•	the fundamental change repurchase date, if applicable;

	•	the name and address of the paying agent and the conversion agent, if applicable;


	•	the ~~base~~applicable conversion rate, including any adjustments to the ~~base~~ conversion rate, ~~including~~and any additional shares, if ~~applicable, and the applicable conversion rate;~~applicable;


	•	that the notes with respect to which a fundamental change repurchase notice has been delivered by a holder may be converted only if the holder withdraws the fundamental change repurchase notice in accordance with the terms of the indenture; and

	•	the procedures that holders must follow to require us to repurchase their notes, if applicable.

Simultaneously with providing such notice, we will publish a notice containing this information in a newspaper of general circulation in The City of New York or publish the information on our website or through such other public medium as we may use at that time.

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To exercise the repurchase right, you must deliver, on or before the close of business on the business day immediately preceding the fundamental change repurchase date, the notes to be repurchased. If the notes are held in global form, such delivery (and the related repurchase notice) must comply with all applicable DTC procedures. If the notes are held in certificated form, such notes must be duly endorsed for transfer, together with a written repurchase notice of the form entitled “Form of Fundamental Change Repurchase Notice” on the reverse side of the notes duly completed, to the paying agent. Your repurchase notice must state:


	•	if certificated, the certificate numbers of your notes to be delivered for repurchase;

	•	the portion of the principal amount of notes to be repurchased, which must be $1,000 or an integral multiple thereof; and

	•	that the notes are to be repurchased by us pursuant to the applicable provisions of the notes and the indenture.

You may withdraw any repurchase notice in whole or in part by a written notice of withdrawal delivered to the paying agent prior to the close of business on the business day prior to the fundamental change repurchase date. The notice of withdrawal shall state:

• the principal amount of the withdrawn notes;


	•	if certificated notes have been issued, the certificate numbers of the withdrawn notes, or if not certificated, your notice must comply with applicable DTC procedures; and

	•	the principal amount, if any, which remains subject to the repurchase notice.

In connection with any repurchase of the notes, we will agree under the indenture to:


	•	comply with the provisions ofRule 13e-4,Rule 14e-1 and any other tender offer rules under the Exchange Act that may then be applicable; and

	•	otherwise comply with all applicable federal and state securities laws.

We will be required to repurchase the notes on the fundamental change repurchase date. You will receive payment of the fundamental change repurchase price promptly following the later of the fundamental change repurchase date or the time of book-entry transfer or the delivery of the notes. Subject to a holder’s right to receive interest on the related interest payment date where the fundamental change repurchase date falls between a regular record date and the interest payment date to which it relates, if the paying agent holds money sufficient to pay the fundamental change repurchase price of the notes on the business day following the fundamental change repurchase date, then:


	•	the notes will cease to be outstanding and interest, if any, will cease to accrue, whether or not book-entry transfer of the notes is made or whether or not the note is delivered to the paying agent; and

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	•	all other rights of the holder will terminate other than the right to receive the fundamental change repurchase price and previously accrued and unpaid interest, if any, upon delivery or transfer of the notes.

The Company will not be required to offer to repurchase the notes in connection with a fundamental change if a third party makes the offer in the manner, at the times and otherwise in compliance with the requirements set forth in the indenture applicable to an offer to repurchase notes in connection with a fundamental change and purchases all notes validly tendered and not withdrawn under such offer.

The repurchase rights of the holders could discourage a potential acquirer of us. However, the fundamental change purchase feature is not the result of management’s knowledge of any specific effort to obtain control of us by any means or part of a plan by management to adopt a series of anti-takeover provisions.

The term fundamental change is limited to specified transactions and may not include other events that might adversely affect our financial condition. In addition, the requirement that we offer to

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repurchase the notes upon a fundamental change may not protect holders in the event of a highly leveraged transaction, reorganization, merger or similar transaction involving us.

If a fundamental change were to occur, we may not have enough funds to pay the fundamental change repurchase price. See “Risk Factors — Risks Related to the Notes — We may be unable to repurchase the notes for cash when required by the holders following a fundamental change.” If we fail to repurchase the notes when required following a fundamental change, we will be in default under the indenture. In addition, we may in the future incur other indebtedness with similar change in control provisions permitting our holders to accelerate or to require us to repurchase our indebtedness upon the occurrence of similar events or on some specific dates. Our subsidiaries conduct all of our operations and own substantially all of our assets. As a result, our cash flows and ability to meet our obligations, including our obligations with respect to the notes to the extent not secured by the pledge and escrow agreement, depend on the cash flow of our subsidiaries and payments by our subsidiaries to us in the form of dividends, tax sharing payments or otherwise. Our subsidiaries’ ability to make such distributions to us is subject to significant limitations under the terms of our credit facilities. See “Risk Factors — Risks Related to the Notes — We will be dependent on dividends from our subsidiaries to make future payments on the Notes.”

No notes may be repurchased at the option of holders upon a fundamental change if the principal amount of the notes has been accelerated, and such acceleration has not been rescinded, on or prior to such date.

Optional Redemption by the Company

The notes may not be redeemed by us at our option prior to maturity.

Consolidation, Merger and Sale of Assets

The indenture provides that we will not consolidate with or merge with or into, or convey, transfer or lease all or substantially all of our properties and assets to, another person, unless (i) the resulting, surviving or transferee person, if not us, is an entity organized and validly existing under the laws of the United States of America, any State thereof or the District of Columbia, and such person, if not us, expressly assumes by supplemental indenture all of our obligations under the notes, the indenture and, to the extent we have ongoing obligations under the pledge and escrow agreement, the pledge and escrow agreement, (ii) immediately after giving effect to such transaction, no default has occurred and is continuing under the indenture and (iii) other conditions described in the indenture are ~~met.~~met;providedthat this covenant shall not apply to a spin-off fundamental change if (a) prior to the effective date of such spin-off fundamental change, we make arrangements to have available sufficient cash to meet our obligation to repurchase notes in connection with such spin-off fundamental change as described under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes” and such arrangements remain in effect until the later of (x) the applicable fundamental change repurchase date and (y) the date on which all notes presented for repurchase by us in connection with such spin-off fundamental change have been repurchased as described under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes,” (b) we deliver or we cause the spin-off company to deliver to holders of the notes who duly surrender notes for conversion in connection with a spin-off fundamental change the number of spin-off company’s ownership interests that such holders are entitled to receive as described under “— Conversion Rights — Treatment of Reference Property” on or before the date on which we are required to settle conversions of the notes in connection with such spin-off fundamental change under “— Conversion Rights — Settlement upon Conversion,” and (c) we make and we cause the spin-off company to make all necessary arrangements to ensure that such ownership interests of the spin-off company are, upon delivery to such converting holders, freely transferable without restriction under the Securities Act. Upon any such consolidation, merger, conveyance, transfer or lease, the resulting, surviving or transferee person shall succeed to, and be substituted for, and may exercise, every right and power of ours under the indenture. If the predecessor is still in existence after the transaction, it will be released from its obligations and

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covenants under the indenture and the notes, except in the case of a lease of all or substantially all of our properties and assets.

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Although these types of transactions are permitted under the indenture, certain of the foregoing transactions could constitute a fundamental change permitting each holder to require us to repurchase the notes of such holder as described above.

Events of Default

Each of the following is an event of default:

(1) default in any payment of interest on any note when due and payable and the default continues (x) for any interest payment date through , 2011, for a period of ten business days, or (y) for any interest payment date thereafter, for a period of 30 days;

(2) default in the payment of principal of any note when due and payable at its stated maturity, upon required repurchase, upon acceleration or otherwise;

(3) failure by us to comply with our obligation to convert the notes into shares of our common stockand/or cash and, if applicable, reference property, upon exercise of a holder’s conversion right, which default continues for a period of 5 days;

(4) failure by us to comply with our obligations under “— Consolidation, Merger and Sale of Assets”;

(5) failure by us to comply with our notice obligations under “— Fundamental Change Permits Holders to Require Us to Repurchase Notes” for a period of 10 days after any such notice becomes due;

(6) failure by us for 60 days after written notice from the trustee or the holders of at least 25% of the aggregate principal amount of the notes then outstanding has been received by us to comply with any of our other agreements contained in the notes or indenture;

(7) default by us or any of our subsidiaries with respect to any mortgage, agreement or other instrument under which there may be outstanding, or by which there may be secured or evidenced any debt for money borrowed in excess of $20 million in the aggregate of the Companyand/or any subsidiary of the Company, whether such debt now exists or shall hereafter be created, which default results (i) in such debt becoming or being declared due and payable or (ii) from a failure to pay the principal of any such debt when due and payable at its stated maturity, upon required repurchase, upon declaration or otherwise;

(8) failure by us or any of our subsidiaries, within 30 days, to pay, bond or otherwise discharge any judgments or orders for the payment of money the total uninsured amount of which for us or any of our subsidiaries exceeds in the aggregate $20 million, which are not stayed on appeal;

(9) certain events of bankruptcy, insolvency or reorganization of the Company or any of our “significant subsidiaries” as defined in Rule 1-02 ofRegulation S-X promulgated by the SEC as in effect on the original date of issuance of the notes (the “bankruptcy provisions”); or

(10) the pledge and escrow agreement ceases to be in full force and effect, or enforceable, prior to its expiration in accordance with its terms, and such default continues for a period of 5 days.

If an event of default occurs and is continuing, the trustee by notice to us, or the holders of at least 25% of the aggregate principal amount of the outstanding notes by notice to us and the trustee, may, and the trustee at the request of such holders shall, declare 100% of the principal of and accrued and unpaid interest on all the notes to be due and payable. Upon such a declaration of acceleration, all principal and accrued and unpaid interest on the notes will be due and payable immediately. However, upon an event of default arising out of the bankruptcy provisions with respect to the Company, the aggregate principal amount and accrued and unpaid interest will be due and payable immediately.

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Notwithstanding the foregoing, if we so elect, the sole remedy of holders for an event of default relating to any obligations we may have or are deemed to have pursuant to Section 314(a)(1) of the

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Trust Indenture Act relating to our failure to file any documents or reports that we are required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act or of the covenant described below in “— Reports” (a “reporting default”) will for the first 90 days (the “first extension period”) after the date (the “reporting default date”) on which such reporting default occurs consist exclusively of the right to receive an extension fee on the notes equal to 0.25% of the aggregate principal amount of the notes (the “first extension fee” and together with the second extension fee (as defined herein), if any, the “extension fee”). We refer to this election as the “first extension right.” If we exercise the first extension right, the first extension fee will be payable on all notes outstanding one business day prior to the time of payment of the first extension fee, as specified in the following paragraph. On the 91st day after the reporting default date (if such reporting default is not cured or waived prior to such 91st day), the notes will be subject to acceleration as provided above unless we have exercised the second extension right in accordance with the provisions described below. If we do not elect to pay the first extension fee upon such reporting default, the notes will be subject to acceleration as provided above.

In addition, if we so elect, the sole remedy of holders with respect to a reporting default that continues beyond the first extension period will for the period from the 91st day after the reporting default date until the 180th day after the reporting default date (the “second extension period”) consist exclusively of the right to receive an extension fee on the notes equal to 0.25% of the aggregate principal amount of the notes (the “second extension fee”). We refer to this election as the “second extension right.” If we exercise the second extension right, the second extension fee will be payable on all notes outstanding one business day prior to the time of payment of the second extension fee, as specified in the following paragraph. On the 181st day after the reporting default date (if such reporting default is not cured or waived prior to such 181st day), the notes will be subject to acceleration as provided above. If we elect to exercise the first extension right but we do not pay the second extension fee on or prior to the 91st day after the reporting default date, the notes will be subject to acceleration as provided above.

In order to exercise the first extension right or second extension right, as the case may be, and elect to pay the applicable extension fee as the sole remedy during the related extension period, we must (i) notify all holders of notes and the trustee and paying agent of such election prior to the close of business on (x) for the first extension right, the first business day following the reporting default date, or (y) for the second extension right, the second business day prior to the last day of the first extension period, and (ii) pay the applicable extension fee on or before the close of business on (x) for the first extension right, the reporting default date, or (y) for the second extension right, the second business day prior to the last day of the first extension period. If we fail to timely give such notice or pay the first extension fee or the second extension fee, as the case may be, as described above, the notes will be immediately subject to acceleration as provided above.

Notwithstanding the preceding three paragraphs, if an event of default occurs under any other series of our debt securities issued subsequent to the issuance of the notes resulting from our failure to file any such documents or reports and such event of default is not subject to extension on terms similar to the above and results in the principal amount of such debt securities becoming due and payable, then neither the first extension right nor the second extension right will apply and the notes will be subject to acceleration as provided above.

The holders of a majority of the aggregate principal amount of the outstanding notes may waive all past defaults (except with respect to an uncured nonpayment of principal or interest, a failure to deliver amounts due upon conversion or a covenant or provision of the indenture that cannot be modified or modified without the consent of the holder of each outstanding note affected) and rescind any such acceleration with respect to the notes and its consequences if (1) rescission would not conflict with any judgment or decree of a court of competent jurisdiction and (2) all existing events of default, other than the uncured nonpayment of the principal of and interest on the notes or failure to

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deliver amounts due upon conversion that have become due solely by such declaration of acceleration, have been cured or waived.

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Subject to the provisions of the indenture relating to the duties of the trustee, if an event of default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any of the holders unless such holders have offered to the trustee indemnity or security reasonably satisfactory to it against any loss, liability or expense. Except to enforce the right to receive payment of principal or interest when due or to receive amounts due to it upon conversion, no holder may pursue any remedy with respect to the indenture or the notes unless:

(1) such holder has previously given the trustee notice that an event of default is continuing;

(2) holders of at least 25% of the aggregate principal amount of the outstanding notes have requested the trustee to pursue the remedy;

(3) such holders have offered the trustee security or indemnity reasonably satisfactory to it against any loss, liability or expense;

(4) the trustee has not complied with such request within 60 days after the receipt of the request and the offer of security or indemnity; and

(5) the holders of a majority of the aggregate principal amount of the outstanding notes have not given the trustee a direction that, in the opinion of the trustee, is inconsistent with such request within such60-day period.

Subject to certain restrictions, the holders of a majority of the aggregate principal amount of the outstanding notes are given the right to direct the time, method and place of conducting any proceeding for any remedy available to the trustee or of exercising any trust or power conferred on the trustee. The indenture provides that if an event of default has occurred and is continuing, the trustee will be required in the exercise of its powers to use the degree of care that a prudent person would use in the conduct of its own affairs. The trustee, however, may refuse to follow any direction that conflicts with law or the indenture or that the trustee determines is unduly prejudicial to the rights of any other holder or that would involve the trustee in personal liability. Prior to taking any action under the indenture, the trustee will be entitled to indemnification satisfactory to it in its sole discretion against all losses and expenses caused by taking or not taking such action.

The indenture provides that if a default occurs and is continuing and is known to the trustee, the trustee must mail to each holder notice of the default within 90 days after it occurs. Except in the case of a default in the payment of principal of or interest on any note or conversion default, the trustee may withhold notice if and so long as a committee of trust officers of the trustee in good faith determines that withholding notice is in the interests of the holders. In addition, we are required to deliver to the trustee, within 120 days after the end of each fiscal year, a certificate, the signer of which shall be the principal executive officer, principal accounting officer or principal financial officer of the Company, indicating whether the signer thereof knows of any default that occurred during the previous year. We are also required to deliver to the trustee, within 30 days after the occurrence thereof, written notice of any events that would constitute a default, the status of those events and what action we are taking or propose to take in respect thereof.

Modification and Amendment

Subject to certain exceptions, the indenture and the notes may be amended with the consent of the holders of at least a majority of the aggregate principal amount of the notes then outstanding, including without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes, and, subject to certain exceptions, any past default or compliance with any provisions may be waived with the consent of the holders of a majority of the aggregate principal amount of the notes then outstanding, including, without limitation, consents obtained in connection

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with a purchase of, or tender offer or exchange offer for, notes. However, without the consent of each holder of an outstanding note affected, no amendment or waiver may, among other things:

(1) reduce the amount of notes whose holders must consent to an amendment;

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(2) reduce the rate, or change the stated time for payment, of interest on any note or reduce the amount, or extend the stated time for payment, of the extension fee;

(3) reduce the principal, or change the stated maturity, of any note;

(4) make any change that adversely affects the conversion rights of any notes;

(5) reduce the fundamental change repurchase price of any note or amend or modify in any manner adverse to the holders of notes our obligation to make such payments, whether through an amendment or waiver of provisions in the covenants, definitions or otherwise;

(6) change the place or currency of payment of principal or interest or the extension fee in respect of any note;

(7) impair the right of any holder to receive payment of principal of and interest on such holder’s notes on or after the due dates therefore or to institute suit for the enforcement of any payment on or with respect to such holder’s notes;

(8) adversely affect the ranking of the notes as our senior unsecured indebtedness; or

(9) make any change in the amendment provisions which require each holder’s consent or in the waiver provisions.

Without the consent of any holder, we and the trustee may amend the indenture or the notes to:

(1) cure any ambiguity or correct any omission, manifest error, defect or inconsistency in the indenture, so long as such action will not adversely affect the rights of holders of the notes in any material respect;

(2) provide for the assumption by a successor corporation or entity of our obligations under the indenture;

(3) add guarantees with respect to the notes;

(4) provide for a successor trustee, conversion agent, paying agent or registrar in accordance with the terms of the indenture or to otherwise comply with any requirement of the indenture;

(5) provide for the issuance of additional notes, to the extent that we and the trustee deem such amendment necessary or advisable in connection with such issuance;providedthat no such amendment or supplement may impair the rights or interests of any holder of the outstanding notes;

(6) increase the ~~base~~ conversion ~~rate or the incremental share factor;~~rate;

(7) secure the notes;

(8) add to our covenants or events of default for the benefit of the holders or surrender any right or power conferred upon us;

(9) provide for the conversion of notes in accordance with the terms of the indenture;

(10) make any change that does not adversely affect the rights of any holder in any material respect;

(11) comply with any requirement of the SEC in connection with the qualification of the indenture under the Trust Indenture Act; or

(12) conform the provisions of the indenture or the notes to the “Description of the Notes” section in this prospectus, so long as such action will not adversely affect the interests of holders of the notes.

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The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment. It is sufficient if such consent approves the substance of the proposed amendment. After an amendment under the indenture becomes effective, we are required to issue a notice to the holders briefly describing such amendment. However, the failure to give such notice to all the holders, or any defect in the notice, will not impair or affect the validity of the amendment.

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The pledge and escrow amendment may not be amended in any manner adverse to the holders of the notes without the consent of each such affected holder.

Discharge

We may satisfy and discharge our obligations under the indenture by delivering to the securities registrar for cancellation all outstanding notes or by depositing with the trustee or delivering to the holders, as applicable, after the notes have become due and payable, whether at stated maturity, or any fundamental change repurchase date, or upon conversion or otherwise, cash, shares of common stock or cash and shares of common stock, if applicable, sufficient to pay all of the outstanding notes and paying all other sums payable under the indenture by us. Such discharge is subject to terms contained in the indenture.

Calculations in Respect of Notes

Except as otherwise provided above, we will be responsible for making all calculations called for under the notes or in connection with a conversion. These calculations include, but are not limited to, determinations of the last reported sale prices of our common stock, accrued interest payable on the notes and the ~~base conversion rate,~~ applicable ~~conversion rate and trading price~~ conversion rate of the notes. We will make all these calculations in good faith and, absent manifest error, our calculations will be final and binding on holders of notes. We will provide a schedule of our calculations to each of the trustee and the conversion agent, and each of the trustee and conversion agent is entitled to rely conclusively upon the accuracy of our calculations without independent verification. The trustee will forward our calculations to any holder of notes upon the written request of that holder.

Trustee

Wells Fargo Bank, N.A. is the trustee, security registrar, paying agent and conversion agent.

Payments on the Notes; Paying Agent and Registrar

Through our paying agent, we will pay the principal of, and interest on, notes in global form registered in the name of or held by The Depository Trust Company (“DTC”) or its nominee in immediately available funds to DTC or its nominee, as the case may be, as the registered holder of such global notes.

We will pay the principal of certificated notes at the office or agency designated by us. We have initially designated a corporate trust office of the trustee as our paying agent and registrar as a place where notes may be presented for payment or for registration of transfer. We may, however, change the paying agent or registrar without prior notice to the holders of the notes, and we may act as registrar. Interest and any extension fee on certificated notes will be payable (i) to holders having an aggregate principal amount of $5.0 million or less, by check mailed to the holders of such notes and (ii) to holders having an aggregate principal amount of more than $5.0 million, either by check mailed to each holder or, upon application by a holder to the registrar not later than the relevant record date, by wire transfer in immediately available funds to that holder’s account within the United States, which application shall remain in effect until the holder notifies, in writing, the registrar to the contrary.

Reports

The indenture provides that any documents or reports that we are required to file with the SEC pursuant to Section 13 or 15(d) of the Exchange Act will be filed with the trustee within 15 days after the same are required to be filed with the SEC. Documents filed by us with the SEC via the EDGAR

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system will be deemed filed with the trustee as of the time such documents are filed via EDGAR,provided that the trustee shall have no responsibility to determine whether such filing has occurred.

No Stockholder Rights for Holders of Notes

Holders of the notes, as such, will not have any rights as stockholders of CVR Energy (including, without limitation, voting rights and rights to receive any dividends or other distributions on our common stock).

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No Personal Liability of Directors, Officers, Employees and Stockholders

No director, officer, employee, incorporator, stockholder or partner of ours, as such, will have any liability for any of our obligations under the notes, the indenture or for any claim based on, in respect of, or by reason of such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Global Notes, Book-Entry Form

The notes will be evidenced by one or more global notes. We will deposit the global note or notes with the trustee as custodian for DTC and register the global notes in the name of Cede & Co. as DTC’s nominee. Except as set forth below, a global note may be transferred, in whole or in part, only to another nominee of DTC or to a successor of DTC or its nominee.

Beneficial interests in a global note may be held directly through DTC if such holder is a participant in DTC, or indirectly through organizations that are participants in DTC, whom we refer to as participants. Transfers between participants will be effected in the ordinary way in accordance with DTC rules and will be settled in clearing house funds. The laws of some states require that some persons take physical delivery of securities in definitive form. As a result, the ability to transfer beneficial interests in the global note to such persons may be limited.

Holders who are not participants may beneficially own interests in a global note held by DTC only through participants, or certain banks, brokers, dealers, trust companies and other parties that clear through or maintain a custodial relationship with a participant, either directly or indirectly, who we refer to as indirect participants. So long as Cede & Co., as the nominee of DTC, is the registered owner of a global note, Cede & Co. for all purposes will be considered the sole holder of such global note. Except as provided below, owners of beneficial interests in a global note will:


	•	not be entitled to have certificates registered in their names;

	•	not receive physical delivery of certificates in definitive registered form; and

	•	not be considered holders of the global note.

We will make payments on a global note to Cede & Co., as the registered owner of the global note, by wire transfer of immediately available funds on each interest payment date, repurchase date or fundamental change repurchase date, as the case may be, and the maturity date. Neither we, the trustee nor any paying agent, registrar or conversion agent will be responsible or liable:


	•	for the records relating to, or payments made on account of, beneficial ownership interests in a global note; or

	•	for maintaining, supervising or reviewing any records relating to the beneficial ownership interests.

We have been informed that DTC’s practice is to credit participants’ accounts upon receipt of funds on that payment date with payments in amounts proportionate to their respective beneficial interests in the principal amount represented by a global note as shown in the records of DTC. Payments by participants to owners of beneficial interests in the principal amount represented by a global note held through participants will be the responsibility of the participants, as is now the case with securities held for the accounts of customers registered in “street name”.

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Because DTC can only act on behalf of participants, who in turn act on behalf of indirect participants, the ability of a person having a beneficial interest in the principal amount represented by the global note to pledge such interest to persons or entities that do not participate in the DTC system, or otherwise take actions in respect of such interest, may be affected by the lack of a physical certificate evidencing its interest.

Neither we, the trustee, registrar, paying agent nor conversion agent will have any responsibility for the performance by DTC or its participants or indirect participants of their respective obligations under the rules and procedures governing their operations. DTC has advised us that it will take any

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action permitted to be taken by a holder of notes, including the presentation of notes for exchange, only at the direction of one or more participants to whose account with DTC interests in the global note are credited, and only in respect of the principal amount of the notes represented by the global note as to which the participant or participants has or have given such direction.

DTC has advised us that it is:


	•	a limited purpose trust company organized under the laws of the State of New York, and a member of the Federal Reserve System;

	•	a “clearing corporation” within the meaning of the Uniform Commercial Code; and

	•	a “clearing agency” registered pursuant to the provisions of Section 17A of the Exchange Act.

DTC was created to hold securities for its participants and to facilitate the clearance and settlement of securities transactions between participants through electronic book-entry changes to the accounts of its participants. Participants include securities brokers, dealers, banks, trust companies and clearing corporations and other organizations. Some of the participants or their representatives, together with other entities, own DTC. Indirect access to the DTC system is available to others such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a participant, either directly or indirectly.

DTC has agreed to the foregoing procedures to facilitate transfers of interests in a global note among participants. However, DTC is under no obligation to perform or continue to perform these procedures, and may discontinue these procedures at anytime. If DTC is at any time unwilling or unable to continue as depositary and a successor depositary is not appointed by us within 90 days, we will issue notes in fully registered certificated form in exchange for global notes. In addition, the owner of a beneficial interest in a global note will be entitled to receive a note in fully registered certificated form in exchange for such interest if an event of default has occurred and is continuing.

Neither we nor the trustee will have any responsibility or liability for any aspect of the records relating to or payments made on account of notes by DTC, or for maintaining, supervising or reviewing any records of DTC relating to the notes.

Governing Law

The notes, the indenture and the pledge and escrow agreement will be governed by, and construed in accordance with, the laws of the State of New York.

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DESCRIPTION OF CAPITAL STOCK

Our authorized capital stock consists of 350,000,000 shares of common stock, par value $0.01 per share, and 50,000,000 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. As of the date of this prospectus, there are 86,141,291 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 amended and restated 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 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.

Our common stock will be represented by certificates, unless our board of directors adopts a resolution providing that some or all of our common stock shall be uncertificated. Any such resolution will not apply to any shares of common stock that are already certificated until such shares are surrendered to us.

Preferred Stock

Our board of directors may, from time to time, authorize the issuance of one or more series of preferred stock without stockholder approval. Subject to the provisions of our amended and restated certificate of incorporation and limitations prescribed by law, our board of directors is authorized to adopt resolutions to issue shares, designate the series, establish the number of shares, change the number of shares constituting any series, and provide or change the voting powers, preferences and relative participating, optional and other special rights, and any 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 on Liability and Indemnification of Officers and Directors

Our amended and restated 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

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breaches resulting from grossly negligent behavior. However, our directors will be personally liable to us and our stockholders for any breach of the director’s duty of loyalty, for acts or omissions not in good faith or which involve intentional misconduct or a knowing violation of law, under Section 174 of the Delaware General Corporation Law or for any transaction from which the director derived an improper personal benefit. In addition, our amended and restated certificate of incorporation and bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. We also maintain directors and officers insurance.

Corporate Opportunities

Our amended and restated certificate of incorporation provides that the Goldman Sachs Funds and the Kelso Funds have no obligation to offer us an opportunity to participate in business opportunities presented to the Goldman Sachs Funds or the Kelso Funds or their respective affiliates even if the opportunity is one that we might reasonably have pursued, and that neither the Goldman Sachs Funds, the Kelso Funds nor their respective affiliates will be liable to us or our stockholders for breach of any duty by reason of any such activities unless, in the case of any person who is a director or officer of our company, such business opportunity is expressly offered to such director or officer in writing solely in his or her capacity as an officer or director of our company. Stockholders will be deemed to have notice of and consented to this provision of our certificate of incorporation.

In addition, the Partnership’s partnership agreement provides that the owners of the managing general partner of the Partnership, which include the Goldman Sachs Funds and the Kelso Funds, are permitted to engage in separate businesses which directly compete with the Partnership and are not required to share or communicate or offer any potential corporate opportunities to the Partnership even if the opportunity is one that we might reasonably have pursued. The agreement provides that the owners of the managing general partner will not be liable to the Partnership or any partner for breach of any fiduciary or other duty by reason of the fact that such person pursued or acquired for itself any corporate opportunity. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our noteholders and stockholders.”

Delaware Anti-Takeover Law

Our amended and restated certificate of incorporation provides that we are not 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.

Removal of Directors; Vacancies

Our amended and restated certificate of incorporation and bylaws provide that any director or the entire board of directors may be removed with or without cause by the affirmative vote of the majority of all shares then entitled to vote at an election of directors. Our amended and restated certificate of incorporation and bylaws also provide that any vacancies on our board of directors will be filled by the affirmative vote of a majority of the board of directors then in office, even if less than a quorum, or by a sole remaining director.

Voting

The affirmative vote of a plurality of the shares of our common stock present, in person or by proxy will decide the election of any directors, and the affirmative vote of a majority of the shares of our common stock present, in person or by proxy will decide all other matters voted on by

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stockholders, unless the question is one upon which, by express provision of law, under our amended and restated certificate of incorporation, or under our bylaws, a different vote is required, in which case such provision will control.

Action by Written Consent

Our amended and restated certificate of incorporation and bylaws provide that stockholder action can be taken by written consent of the stockholders only if the Goldman Sachs Funds and the Kelso Funds collectively beneficially own more than 35.0% of the outstanding shares of our common stock.

Ability to Call Special Meetings

Our bylaws provide that special meetings of our stockholders can only be called pursuant to a resolution adopted by a majority of our board of directors or by the chairman of our board of directors. Special meetings may also be called by the holders of not less than 25% of the outstanding shares of our common stock if the Goldman Sachs Funds and the Kelso Funds collectively beneficially own 50% or more of the outstanding shares of our common stock. Thereafter, stockholders will not be permitted to call a special meeting or to require our board to call a special meeting.

Amending Our Certificate of Incorporation and Bylaws

Our amended and restated certificate of incorporation provides that our certificate of incorporation may be amended by the affirmative vote of a majority of the board of directors and by the affirmative vote of the majority of all shares of our common stock then entitled to vote at any annual or special meeting of stockholders. In addition, our amended and restated certificate of incorporation and bylaws provide that our bylaws may be amended, repealed or new bylaws may be adopted by the affirmative vote of a majority of the board of directors or by the affirmative vote of the majority of all shares of our common stock then entitled to vote at any annual or special meeting of stockholders.

Advance Notice Provisions for Stockholders

In order to nominate directors to our board of directors or bring other business before an annual meeting of our stockholders, a stockholder’s notice must be received by the Secretary of the Company at the principal executive offices of the Company not less than 120 calendar days before the date that our proxy statement is released to stockholders in connection with the previous year’s annual meeting of stockholders, subject to certain exceptions contained in our bylaws. If no annual meeting was held in the previous year, or if the date of the applicable annual meeting has been changed by more than 30 days from the date of the previous year’s annual meeting, then a stockholder’s notice, in order to be considered timely, must be received by the Secretary of the Company no later than the later of the 90th day prior to such annual meeting or the tenth day following the day on which notice of the date of the annual meeting was mailed or public disclosure of such date was made.

Listing

Our common stock is listed on the New York Stock Exchange under the symbol “CVI.”

Transfer Agent and Registrar

The transfer agent and registrar for our common stock is American Stock Transfer & Trust Company.

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SHARES ELIGIBLE FOR FUTURE SALE

We have outstanding 86,141,291 shares of common stock. The 23,000,000 shares sold in our initial public offering and the 27,100 shares of common stock granted to our non-executive officer employees in connection with our initial public offering and registered pursuant to a registration statement onForm S-8 filed on October 24, 2007 are 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 63,114,191 shares outstanding 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 or 701 promulgated under the Securities Act, which are summarized below.

In general, under Rule 144 as currently in effect, after the expiration of any applicablelock-up agreements, an affiliate who has beneficially owned restricted securities for at least six months 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 861,413 shares immediately after this offering; or

	•	the average weekly trading volume of the common stock during the four calendar weeks preceding the sale.

Sales by affiliates under Rule 144 are also subject to manner of sale requirements, notice requirements and the availability of current public information about us. Under Rule 144, 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 six months, is entitled to sell his or her shares provided he or she complies with the current public information requirement. After one year, a non-affiliate may freely sell his or her shares.

Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and John J. Lipinski, who, collectively hold 63,114,191 shares of our common stock are parties to registration rights agreements with us. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, who hold 62,866,720 shares collectively, can request that we register their shares with the SEC at any time on up to three occasions each, including pursuant to shelf registration statements. Mr. Lipinski can piggyback on any registration statement we file with the SEC.

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MATERIAL UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS

The following is a summary of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of the notes and shares of our common stock (the “common shares”) into which the notes may be converted. This summary applies to you only if you are a U.S. Holder or aNon-U.S. Holder (as defined below) of a note and you acquire the note in this offering for a price equal to the issue price of the notes. The issue price of the notes is the first price at which a substantial amount of the notes is sold other than to bond houses, brokers, or similar persons or organizations acting in the capacity of underwriters, placement agents or wholesalers.

This summary deals only with notes and common shares that are held as capital assets (generally, investment property) and does not deal with special tax situations such as:


	•	dealers in securities or currencies and traders who have elected themark-to-market method of accounting for their securities;

	•	U.S. Holders (as defined below) whose functional currency is not the U.S. dollar;

	•	persons holding notes or common shares as part of a conversion, constructive sale, wash sale or other integrated transaction or a hedge, straddle or synthetic security;

	•	persons subject to the alternative minimum tax;

	•	certain former citizens or long-term residents of the United States;

	•	financial institutions;

	•	insurance companies;

	•	controlled foreign corporations, real estate investment trusts, passive foreign investment companies and regulated investment companies and shareholders of such corporations;

	•	entities that are tax-exempt for U.S. federal income tax purposes and retirement plans, individual retirement accounts and tax-deferred accounts;

	•	persons that actually or constructively own 10% or more (by voting power or value) of the common shares;

	•	pass-through entities, including partnerships and entities and arrangements classified as partnerships for U.S. federal tax purposes, and beneficial owners of pass-through entities; and

	•	persons that acquire the notes for a price other than their issue price.

If an entity or arrangement treated as a partnership or other type of pass-through entity for U.S. federal income tax purposes owns the notes or the common shares, 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 the notes or the common shares should consult their own tax advisors as to the particular U.S. federal income tax consequences applicable to them.

This summary does not discuss all of the aspects of U.S. federal taxation that may be relevant to you in light of your particular investment or other circumstances. In addition, this summary does not discuss any U.S. state or local income ornon-U.S. income or other tax consequences. This summary is based on U.S. federal income tax law, including the provisions of the Internal Revenue Code of 1986, as amended (the “Code”), U.S. Treasury regulations, administrative rulings and judicial authority, all as in effect or in existence as of the date of this prospectus supplement. Subsequent developments in the U.S. federal income tax law, including changes in law or differing interpretations, which may be applied retroactively, could have a material effect on the U.S. federal income tax consequences of acquiring, owning and disposing of the notes and the common shares as set forth in this summary. We have not sought, and will not seek, any rulings from the U.S. Internal Revenue Service (the “IRS”) with respect to the matters discussed below. There can be no assurance that the IRS will not take a different position concerning the tax consequences of the acquisition, ownership or disposition of the notes or the common shares or that any such position would not be sustained. Before you purchase

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the notes, you should consult your own tax advisor regarding the particular U.S. federal, state and local andnon-U.S. and other tax consequences of acquiring, owning and disposing of the notes and common shares that may be applicable to you.

As used in this summary, “U.S. Holder” means a beneficial owner of a note or the common shares received on conversion of the note that is, for U.S. federal income tax purposes,


	•	an individual who is a citizen or resident of the United States;

	•	a corporation created or organized in or under the laws of the United States, any state thereof or the District of Columbia;

	•	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 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”.

“Non-U.S. Holder” means a beneficial owner of a note or the common shares received on conversion of the note that is neither a U.S. Holder nor a partnership (or an entity or arrangement classified as a partnership) for U.S. federal income tax purposes.

An individual may be treated as a resident of the United States in any calendar year for U.S. 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.

U.S. Holders

Interest on the Notes. Interest on a note will be included in a U.S. Holder’s gross income, as ordinary income, at the time the interest is accrued or received in accordance with the U.S. Holder’s method of accounting for U.S. federal income tax purposes.

Additional Amount. We intend to treat the possibility that we will pay an amount described above under “Description of the Notes — Events of Default” as a remote or incidental contingency, within the meaning of applicable U.S. Treasury regulations. In the unlikely event that such an additional amount becomes payable, we intend to treat such an additional amount as ordinary interest income taxable to a U.S. Holder at the time that it is paid or accrued in accordance with such holder’s method of accounting for U.S. federal income tax purposes. Our determination that there is a remote likelihood of paying an additional amount on the notes, or that such payment, if any, is incidental, is binding on each U.S. Holder unless the U.S. Holder explicitly discloses in the manner required by applicable U.S. Treasury regulations that its determination is different from ours. The IRS, however, may take a different position, which could affect the timing and character of a U.S. Holder’s income with respect to the notes. You should consult your own tax advisor with regard to the potential application of these rules. The following discussion assumes that the intended treatment described above is correct.

Disposition of the Notes. Upon the sale, exchange (other than in a tax-free transaction), retirement or other taxable disposition of a note (other than conversion of a note into cash, the common shares or a combination of cash and the common shares, the U.S. federal income tax consequences of which are described in “— Conversion of the Notes” below), a U.S. Holder generally will recognize gain or loss in an amount equal to the difference, if any, between (i) the amount of cash proceeds and the fair market value of any property received in the disposition (except with respect to amounts received upon a disposition attributable to accrued but unpaid interest, which generally will be taxable as ordinary income as discussed above) and (ii) such U.S. Holder’s tax basis in the note. A

~~313~~315

U.S. Holder’s tax basis in a note generally will be the U.S. Holder’s cost for the note. In general, any such gain or loss will be capital gain or loss, and will be long-term capital gain or loss if, at the time of the disposition, the note has been held for more than one year. Long-term capital gains recognized by individuals and certain other non-corporate U.S. Holders generally are eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Conversion of the Notes. The notes may be converted into cash, the common shares or a combination of cash and the common shares as described in “Description of the Notes — Conversion Rights”.

A U.S. Holder will not recognize taxable gain or loss as a result of its note being converted solely into the common shares (except with respect to cash received in lieu of a fractional common share and the common shares received attributable to accrued and unpaid interest), subject to the discussion under “— Conversion Rate Adjustments” below regarding the possibility that a change in the ~~applicable~~ conversion rate of a note may be treated as a taxable stock distribution. The U.S. Holder’s tax basis in the common shares received on the conversion (including any fractional common share for which cash is paid, but excluding common shares received attributable to accrued and unpaid interest) will equal the U.S. Holder’s tax basis in the converted note immediately before the conversion, and the U.S. Holder’s holding period for such common shares will include the U.S. Holder’s holding period in the converted note.

Upon the conversion of a note solely into cash, a U.S. Holder generally will be subject to the rules described under “— Disposition of the Notes” above.

The tax consequences of the conversion of a note into a combination of cash and the common shares is not entirely clear. A U.S. Holder may be treated as exchanging the note for the common shares and cash in a recapitalization for U.S. federal income tax purposes. In that case, a U.S. Holder would not be permitted to recognize loss, but would be required to recognize gain. A U.S. Holder would recognize gain in an amount equal to the lesser of (i) the excess (if any) of (A) the amount of cash received (excluding any cash received in lieu of a fractional common share and any cash received attributable to accrued and unpaid interest) plus the fair market value of the common shares received (treating a fractional common share as issued and received for this purpose and excluding any such common shares that are attributable to accrued and unpaid interest) upon conversion over (B) the U.S. Holder’s tax basis in the converted note, and (ii) the amount of cash received upon conversion (other than any cash received in lieu of a fractional common share and any cash received attributable to accrued and unpaid interest). Subject to the discussion under “— Conversion Rate Adjustments” below regarding the possibility that a change in the ~~applicable~~ conversion rate of a note may be treated as a taxable stock distribution, any gain recognized by a U.S. Holder upon conversion of a note will be long-term capital gain if the note has been held for more than one year at the time of the conversion. A U.S. Holder’s tax basis in the common shares received (including any fractional common share for which cash is paid, but excluding common shares attributable to accrued and unpaid interest) generally would equal the tax basis of the converted note, decreased by the amount of cash received (other than cash received in lieu of a fractional common share and any cash attributable to accrued and unpaid interest), and increased by the amount of gain (if any) recognized upon conversion (other than any gain recognized as a result of cash received in lieu of a fractional common share). A U.S. Holder’s holding period in the common shares received (other than common shares attributable to accrued and unpaid interest) would include the U.S. Holder’s holding period in the converted note. We intend to treat the conversion of a note into a combination of cash and the common shares as an exchange of the note for the common shares and cash in a recapitalization for U.S. federal income tax purposes.

However, it is possible that the conversion of a note into cash and the common shares could be treated as in part a payment in redemption for cash of a portion of the note and in part a conversion of a portion of the note into common shares. In such case, the U.S. Holder’s aggregate tax basis in the note would be allocated between the portion of the note treated as redeemed and the portion of the note treated as converted into the common shares on a pro rata basis. The U.S. Holder generally

~~314~~316

would recognize capital gain or loss with respect to the portion of the note treated as redeemed equal to the difference between the amount of cash received (other than amounts attributable to accrued and unpaid interest) and the U.S. Holder’s tax basis in the portion of the note treated as redeemed. See “— Disposition of the Notes” above. With respect to the portion of the note treated as converted, the U.S. Holder generally would not recognize any gain or loss (except with respect to cash received in lieu of a fractional common share and the common shares received attributable to accrued and unpaid interest), subject to the discussion under “— Conversion Rate Adjustments” below regarding the possibility that a change in the ~~applicable~~ conversion rate of a note may be treated as a taxable stock distribution. The U.S. Holder’s tax basis allocated to the portion of the note treated as converted into common shares would be the U.S. Holder’s tax basis in the common shares (including any fractional common share for which cash is paid, but excluding common shares received attributable to accrued and unpaid interest). The U.S. Holder’s holding period in the common shares (other than common shares attributable to accrued and unpaid interest) would include the U.S. Holder’s holding period in the converted note.

With respect to cash received in lieu of a fractional common share, a U.S. Holder would be treated as if such fractional common share were issued and received and then immediately redeemed for cash. Accordingly, the ~~U.S~~U.S. Holder generally would recognize gain or loss equal to the difference between the cash received and that portion of the U.S. Holder’s tax basis in the common shares (determined as discussed above) attributable to the fractional common share.

Any cash and the value of any portion of the common shares that is attributable to accrued and unpaid interest on a note not yet included in income by a U.S. Holder would be taxed as ordinary income. The U.S. Holder’s tax basis in any common shares received attributable to accrued and unpaid interest would equal the fair market value of such common shares when received. The U.S. Holder’s holding period in any common shares received attributable to accrued and unpaid interest would begin the day after the date of conversion.

If a U.S. Holder converts a note between a record date for an interest payment and the next interest payment and consequently receives a payment of cash interest, as described in “Description of the Notes — Conversion Rights” above, the U.S. Holder should consult its own tax advisor concerning the appropriate treatment of such payments.

U.S. Holders are urged to consult their own tax advisors with respect to the U.S. federal income tax consequences of converting their notes into cash, the common shares or a combination of cash and the common shares.

Distributions on the Common Shares. We do not anticipate making cash distributions on the common shares in the foreseeable future. If a U.S. Holder receives common shares upon a conversion of a note and we make a cash distribution with respect to such common shares, such distribution will be included in the U.S. Holder’s gross income as ordinary dividend income when paid to the extent of our current or accumulated earnings and profits as determined for U.S. federal income tax purposes. If the distribution exceeds our current and accumulated earnings and profits, the excess will be treated as a non-taxable return of capital to the extent of the U.S. Holder’s adjusted tax basis in the common shares and thereafter as capital gain from the sale or exchange of such common shares. Dividends received by a non-corporate U.S. Holder in taxable years beginning before January 1, 2011 generally will be taxed at the lower applicable capital gains rate provided that the U.S. Holder satisfies certain holding period requirements and other requirements (which requirements might not be considered to be satisfied in the case of any portion of any constructive stock distribution (described below) that is treated as a dividend). Dividends received by a corporate U.S. Holder may be eligible for a dividends received deduction, subject to satisfaction of applicable requirements (which requirements might not be considered to be satisfied in the case of any portion of any constructive stock distribution (described below) that is treated as a dividend).

Conversion Rate Adjustments. The terms of the notes allow for changes in the ~~applicable~~ conversion rate of the notes under certain circumstances. A change in the ~~applicable~~ conversion rate that allows noteholders to receive more common shares upon conversion may increase the

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noteholders’ proportionate interests in our earnings and profits or assets. In that case, the noteholders may be treated as though they received a taxable distribution in the form of the common shares. A taxable constructive stock distribution would result, for example, if the ~~base~~ conversion rate is adjusted to compensate noteholders for distributions of cash or property to our stockholders. ~~In addition, a change in the applicable conversion rate as a result of the price of the common shares exceeding the base conversion price may be treated as a taxable constructive stock distribution.~~ The adjustment to the ~~base~~ conversion rate of notes converted in connection with a make-whole fundamental change, as described under “Description of the Notes — Conversion Rights — Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change” above, also may be treated as a taxable constructive stock distribution. Not all changes in the ~~applicable~~ conversion rate that result in noteholders receiving more common shares upon a conversion, however, increase the noteholders’ proportionate interests in our earnings and profits or assets. For instance, a change in the ~~base~~ conversion rate could prevent the dilution of the noteholders’ interests upon a stock split or other change in our capital structure. Changes of this type, if made pursuant to a bona fide reasonable adjustment formula, are not treated as taxable constructive stock distributions. Conversely, if an event occurs that dilutes the noteholders’ interests and the ~~base~~ conversion rate is not adjusted, the resulting increase in the proportionate interests of our stockholders could be treated as a taxable constructive stock distribution to those stockholders. Any taxable constructive stock distribution resulting from a change in, or the absence of a change in, the ~~applicable~~ conversion rate would be treated for ~~U.S~~U.S. federal income tax purposes in the same manner as distributions on the common shares paid in cash or other property, either as a taxable dividend, return of capital or capital gain, as discussed above under “— Distributions on the Common Shares”. The amount of any such taxable constructive stock distribution that is treated as a taxable dividend or as capital gain by a U.S. Holder would increase the U.S. Holder’s tax basis in the notes or common shares, as applicable. It is not clear whether any taxable constructive stock dividend would be eligible for taxation at the lower applicable capital gains rate or the dividends received deduction described under “— Distributions on the Common Shares”, as the requisite applicable holding period requirements might not be considered to be satisfied.

In the event of certain corporate transactions as described under “Description of the Notes — Conversion Rights — Treatment of Reference Property” above, the conversion obligation may be adjusted so that holders of the notes would be entitled thereafter to convert the notes into the same type of consideration that they would have been entitled to receive had they held a number of common shares equal to the ~~base~~ conversion rate ~~and incremental share factor~~ in effect immediately prior to such transactions. Depending on the facts and circumstances at the time of such a corporate transaction, such an adjustment may result in a deemed exchange of the outstanding notes, which may be a taxable event for U.S. federal income tax purposes.

U.S. Holders are urged to consult their own tax advisors regarding the U.S. federal income tax consequences of any change in, or, in certain circumstances, the absence of a change in, the ~~applicable~~ conversion rate or obligation.

Sale or Exchange of Common Shares. Upon the sale or exchange of common shares received upon the conversion of a note, a U.S. Holder generally will recognize gain or loss in an amount equal to the difference, if any, between (i) the amount of cash proceeds and the fair market value of any property received in the sale or exchange and (ii) such U.S. Holder’s tax basis in the common shares. In general, gain or loss recognized by a U.S. Holder on the sale or exchange of common shares will be capital gain or loss and will be long-term capital gain or loss if, at the time of the disposition, the common shares have been held for more than one year. Long-term capital gains recognized by individuals and certain other non-corporate U.S. Holders generally are eligible for reduced rates of taxation. The deductibility of capital losses is subject to limitations.

Information Reporting and Backup Withholding. Interest paid or accrued on a note, dividends on the common shares, as well as the proceeds of a disposition of a note or common shares generally will be subject to information reporting. In addition, in general, “backup withholding” at a rate of 28% (which rate currently is scheduled to increase to 31% for taxable years beginning on

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or after January 1, 2011) will apply to payments of principal of and interest on a note, dividends on the common shares and the proceeds of a disposition of a note or common shares if you are a non-corporate U.S. Holder and you fail to provide a correct taxpayer identification number or otherwise

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comply with applicable requirements of the backup withholding rules. The backup withholding tax is not an additional tax and may be credited against a U.S. Holder’s U.S. federal income tax liability, provided that correct information is timely provided to the IRS.

Non-U.S. Holders

As noted above under “— U.S. Holders — Additional Amount”, we intend to treat, for U.S. federal income tax purposes, the possibility that we will pay an amount described above under “Description of the Notes — Events of Default” as a remote or incidental contingency, and the discussion below assumes that our intended treatment in this regard is correct.

Interest on the Notes. Under current U.S. federal income tax laws, and subject to the discussion below, U.S. federal withholding tax will not apply to payments by us or our paying agent (in its capacity as such) of principal of or interest on aNon-U.S. Holder’s notes under the “portfolio interest” exception of the Code, provided that in the case of payments of interest:


	•	theNon-U.S. Holder does not, directly or indirectly, actually or constructively, own ten percent or more of the total combined voting power of all classes of our stock entitled to vote within the meaning of section 871(h)(3) of the Code and the Treasury regulations thereunder;

	•	theNon-U.S. Holder is not a controlled foreign corporation for U.S. federal income tax purposes that is related, directly or indirectly, to us through sufficient stock ownership (as provided in the Code);

	•	theNon-U.S. Holder is not a bank receiving interest described in section 881(c)(3)(A) of the Code;

	•	such interest is not effectively connected with theNon-U.S. Holder’s conduct of a trade or business in the United States; and

	•	theNon-U.S. Holder provides a signed written statement, on an IRS FormW-8BEN (or other applicable form) which can reliably be related to it, certifying under penalties of perjury that theNon-U.S. Holder is not a “United States person” within the meaning of the Code and provides theNon-U.S. Holder’s name and address to: (A) us or our paying agent; or (B) a securities clearing organization, bank or other financial institution that holds customers’ securities in the ordinary course of its trade or business and holds theNon-U.S. Holder’s notes on such holder’s behalf and that certifies to us or our paying agent under penalties of perjury that it, or the other bank or financial institution between it and theNon-U.S. Holder, has received from theNon-U.S. Holder its signed, written statement and provides us or our paying agent with a copy of this statement.

The applicable Treasury regulations provide alternative methods for satisfying the certification requirement described in this section. In addition, under these Treasury regulations, special rules apply to pass-through entities and this certification requirement may also apply to beneficial owners of pass-through entities.

If aNon-U.S. Holder cannot satisfy the requirements of the “portfolio interest” exception described above, payments of interest made to it will be subject to 30% U.S. federal withholding tax unless theNon-U.S. Holder provides us or our paying agent with a properly executed (1) IRSForm W-8ECI (or other applicable form) stating that interest paid on theNon-U.S. Holder’s notes is not subject to withholding tax because it is effectively connected with theNon-U.S. Holder’s conduct of a trade or business in the United States, or (2) IRSForm W-8BEN (or other applicable form) claiming an exemption from or reduction in this withholding tax under an applicable income tax treaty. Interest on a note that is effectively connected with aNon-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 theNon-U.S. Holder in the United States, will be subject to U.S. federal income tax on a net income basis at the regular graduated rates and in the manner applicable to a

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U.S. Holder. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on interest on a note received by a foreign corporation that is effectively connected with the conduct of a trade or business in the United States.

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Dividends on the Common Shares. If aNon-U.S. Holder receives common shares upon conversion of a note and we make a cash distribution with respect to such common shares that is treated as a dividend for U.S. federal income tax purposes (see the discussion above under “— U.S. Holders — Distributions on the Common Shares”) and is not effectively connected with theNon-U.S. Holder’s conduct of a U.S. trade or business, 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 suchNon-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, aNon-U.S. Holder will be required to provide a properly executed IRSForm 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 the common shares. ANon-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 IRS.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 aNon-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 theNon-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 a U.S. Holder. In that case, we will not have to withhold U.S. federal withholding tax if theNon-U.S. Holder provides a properly executed IRSForm 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.

Constructive Dividends. Under certain circumstances, aNon-U.S. Holder may be deemed to have received a taxable constructive stock distribution (see “— U.S. Holders— Conversion Rate Adjustments”). Any such constructive stock distribution received by aNon-U.S. Holder will be treated in the same manner as an actual dividend received by theNon-U.S. Holder, as discussed above under “— Dividends on the Common Shares”. We intend to deduct withholding tax applicable to any such constructive stock distribution received by aNon-U.S. Holder from payments on theNon-U.S. Holder’s notes, and such withholding tax may also be deducted from theNon-U.S. Holder’s common shares or sales proceeds subsequently paid or credited to theNon-U.S. Holder. In such event, theNon-U.S. Holder should consult its tax advisor as to whether theNon-U.S. Holder can obtain a refund for all or a portion of any tax withheld.

Disposition of the Notes or Common Shares. Subject to the discussion below, aNon-U.S. Holder generally will not be subject to U.S. federal income or withholding tax on any gain realized from (or accrued interest with respect to a note treated as received in connection with) the sale, conversion (including a conversion of a note for the common sharesand/or cash) or other disposition of a note or the common shares, unless:


	•	in the case of proceeds of a disposition (including conversion) of a note representing accrued interest, theNon-U.S. Holder cannot satisfy the requirements of the “portfolio interest” exception described above (and such Non-U.S. Holder’s U.S. federal income tax liability has not otherwise been fully satisfied through the U.S. federal withholding tax);

	•	the gain is effectively connected with theNon-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 theNon-U.S. Holder in the United States; in these

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		cases, the gain will be taxed on a net income basis at the regular graduated rates and in the manner applicable to a U.S. Holder (unless an applicable income tax treaty provides otherwise)

320


		and, if theNon-U.S. Holder is a foreign corporation, the “branch profits tax” described above may also apply;


	•	theNon-U.S. Holder is an individual who 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 theNon-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 theNon-U.S. Holder held the notes or the common shares, as applicable.

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, aNon-U.S. Holder which did not beneficially own (actually or constructively) (i) the notes having a fair market value greater than 5% of the common shares or (ii) more than 5% of the total fair market value of the common shares or the notes, in each case at any time during the shorter of the five-year period ending on the date of disposition or the period that the common shares or the notes were held by theNon-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 a note or the common shares if, at any time during the calendar year of the disposition, the common shares were regularly traded on an established securities market within the meaning of the applicable U.S. Treasury regulations.

The common shares are listed on the New York Stock Exchange. Although not free from doubt, the common shares should be considered to be regularly traded on an established securities market for any calendar quarter during which they are regularly quoted by brokers or dealers that hold themselves out to buy or sell the common shares at the quoted price. If the common shares 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 a note or the common shares 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 a note or the common shares 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 IRS in accordance with applicable U.S. Treasury regulations. We urge allNon-U.S. Holders to consult their own tax advisors regarding the application of these rules to them.

Information Reporting and Backup Withholding. Interest on the notes and dividends on the common shares paid to aNon-U.S. Holder will be subject to U.S. information reporting and may be subject to backup withholding. ANon-U.S. Holder will be exempt from backup withholding if theNon-U.S. Holder provides a properly executed IRSForm W-8BEN or otherwise meets documentary evidence requirements for establishing its status as aNon-U.S. Holder or otherwise establishes an exemption.

The gross proceeds from the disposition of a note or the common shares may be subject to U.S. information reporting and backup withholding. If aNon-U.S. Holder sells a note or the common

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shares outside the United States through anon-U.S. office of anon-U.S. broker and the sales proceeds are paid to theNon-U.S. Holder outside the United States, then the U.S. backup withholding

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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 aNon-U.S. Holder sells a note or the common shares through anon-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 theNon-U.S. Holder is not a United States person and certain other conditions are met or theNon-U.S. Holder otherwise establishes an exemption.

If aNon-U.S. Holder receives payments of the proceeds of a sale of a note or the common shares to or through a United States office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless theNon-U.S. Holder provides a properly executed IRSForm W-8BEN certifying that theNon-U.S. Holder is not a “United States person” or theNon-U.S. Holder otherwise establishes an exemption.

ANon-U.S. Holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed theNon-U.S. Holder’s U.S. federal income tax liability by filing a refund claim with the IRS.

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UNDERWRITING

The Company and the underwriters will enter into an underwriting agreement with respect to the notes being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the principal amount of notes indicated in the following table. Goldman, Sachs & Co. and Citigroup Global Markets Inc. are the joint book-running managers for this offering and the representatives of the underwriters.


	Principal Amount
Underwriters	of Notes

Goldman, Sachs & Co.
Citigroup Global Markets Inc.
Deutsche Bank Securities Inc.
Credit Suisse Securities (USA) LLC

Total	$	125,000,000

The underwriters are committed to take and pay for all of the notes being offered, if any are taken, other than the notes covered by the option described below unless and until such option is exercised. We expect that the underwriting agreement will provide that the obligations of the underwriters to take and pay for the notes are subject to a number of conditions, including, among others, the accuracy of the Company’s representations and warranties in the underwriting agreement, 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 notes than the total principal amount set forth in the table above, the underwriters have an option to buy up to an additional $18,750,000 in aggregate principal amount of notes to cover such sales. They may exercise that option for 30 days. If any notes are purchased pursuant to this option, the underwriters will severally purchase notes in approximately the same proportion as set forth in the table above. If the underwriters’ over-allotment option is exercised in full, the total price to public would be $143,750,000, the total underwriters’ discounts and commissions would be $ , and the total proceeds to us would be $ .

Notes sold by the underwriters to the public will initially be offered at the initial offering price set forth on the cover page of this prospectus. Any notes sold by the underwriters to securities dealers may be sold at a discount from the initial public offering price of up to % of the principal amount of the notes. If all of the notes are not sold at the initial offering price, the representatives may change the offering price and the other selling terms. The offering of the notes by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.

The Company, the controlling stockholders and the directors and executive officers of the Company have agreed with the underwriters, subject to exceptions, not to dispose of or hedge any of the shares of common stock of the Company or securities convertible into or exercisable or exchangeable for shares of common stock of the Company during the period from the date of this prospectus continuing through the date 90 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.

The90-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the90-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 90-day restricted period, the Company announces that it will release earnings results during the 15-day period following the last day of the90-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.

The underwriters have informed us that they do not presently intend to release shares or other securities subject to thelock-up agreements. Any determination to release any securities subject to

~~321~~323

thelock-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 notes or the common stock, the liquidity of the trading market for the notes or the common stock, general market conditions, the number of securities proposed to be sold, and the timing, purpose and terms of the proposed sale.

Our common stock is listed on the New York Stock Exchange under the symbol “CVI.”

In connection with this offering, the underwriters may purchase and sell notes 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 notes than they are required to purchase in this offering. Stabilizing transactions consist of various bids for or purchases of notes 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 notes sold by or for the account of that underwriter in stabilizing or short covering transactions.

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 notes and, together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the notes. As a result, the price of the notes and the Company’s 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, in the over-the-counter market or otherwise.

The notes are a new issue of securities with no established trading market. The Company has been advised by certain of the underwriters that they intend to make a market in the notes but are not obligated to do so and may discontinue market making at any time without notice. No assurance can be given as to the liquidity of the trading market for the notes.

Each underwriter has represented and agreed that:

(a) 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 the FSMA) received by it in connection with the issue or sale of the notes in circumstances in which Section 21(1) of the FSMA does not apply to the Company; and

(b) it has complied and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the notes 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 notes to the public in that Relevant Member State prior to the publication of a prospectus in relation to the notes 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 notes 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;

~~322~~324

(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or

(d) 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 notes to the public” in relation to any notes 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 notes to be offered so as to enable an investor to decide to purchase or subscribe the notes, 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.

The notes 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 notes 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 notes 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 notes may not be circulated or distributed, nor may the notes 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 notes 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 notes 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 notes 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

~~323~~325

of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.

The Company estimates that its share of the total expenses of this offering will be approximately ~~$1.2~~$1.6 million.

The Company has agreed to indemnify the several underwriters against specified liabilities, including liabilities under the Securities Act.

Because affiliates of Goldman, Sachs & Co. own more than 10% of the Company’s outstanding common stock, Goldman, Sachs & Co. is deemed to be an affiliate of the Company under Rule 2720(b)(1) of the NASD Conduct Rules and, therefore, Goldman, Sachs & Co. is also deemed to have a conflict of interest under Rule 2720 of the NASD Conduct Rules. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2720 of the NASD Conduct Rules. Rule 2720 requires that the initial public offering price can be no higher than that recommended by a “qualified independent underwriter,” as defined by the NASD Conduct Rules. Deutsche Bank Securities Inc. will serve in that capacity and will perform due diligence investigations and review and participate in the preparation of the registration statement of which this prospectus forms a part.

Under the terms of the deferral of $87.5 million of the amounts owed to J. Aron, an affiliate of Goldman, Sachs & Co., we are required to use the substantial majority of any gross proceeds from any indebtedness we incur during the deferral period in excess of $125.0 million, including all of the gross proceeds received from the sale of the notes issued in connection with the exercise by the underwriters of theover-allotment option net of fees, to prepay a portion of the deferred amounts owed to J. Aron.

Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, investment banking, commercial banking and other services for our company, for which they received or will receive customary fees and expenses. Furthermore, certain of the underwriters and their respective affiliates may, from time to time, enter into arms-length transactions with us in the ordinary course of their business.

Goldman Sachs Credit Partners L.P. and Credit Suisse Securities (USA) LLC are joint lead arrangers and joint bookrunners under our Credit Facility. Credit Suisse is the administrative agent and Deutsche Bank Trust Company Americas is the syndication agent under our Credit Facility. Goldman Sachs Credit Partners L.P., Deutsche Bank Securities Inc., Credit Suisse and Citicorp North America, Inc. are lenders under the Credit Facility. In addition, each of the underwriters may also participate in a registered offering by certain selling stockholders of shares of our common stock.

For a description of other transactions between us and Goldman, Sachs & Co. and its affiliates, including payments of dividends and payments under our credit facilities by us to such affiliates and director designation rights, see “Certain Relationships and Related Party Transactions” and “The Nitrogen Fertilizer Limited Partnership.”

~~324~~326

LEGAL MATTERS

Certain legal matters relating to the notes offered hereby will be passed upon for our company by Fried, Frank, Harris, Shriver & Jacobson LLP, New York, New York. Debevoise & 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 we refer to as Successor, collectively refer to the consolidated financial statements for the174-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, 2006 and 2007 and for the233-day period ended December 31, 2005 for 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 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. The audit report also contains an explanatory paragraph that states as discussed in note 2 to the consolidated financial statements, the Company has restated the accompanying consolidated financial statements as of and for the year ended December 31, 2007.

WHERE YOU CAN FIND MORE INFORMATION

We have filed with the SEC a registration statement onForm S-1 under the Securities Act with respect to the notes offered hereby. 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 the notes, 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 at1-800-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 athttp://www.sec.gov.

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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 heating oil.

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.

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.

Coker unit		A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke.


Common units		The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies.


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 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.

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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.

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.

Jobber		A person or company that purchases quantities of refined fuel from refining companies, either for sale to retailers or to sell directly to the users of those products.

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.

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.

Midcontinent		Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and Iowa.

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MMBtu		One million British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree ~~Farenheit.~~Fahrenheit.


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.


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.

Operating units		Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on service.

Override units		The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which represent profits interests in the respective limited liability companies. With respect to the override units issued under the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, the units are classified as either operating units or value units.

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.

Phantom performance points		Phantom points granted or to be granted pursuant to the Phantom Unit Plan I and Phantom Unit Plan II, which vest based on performance of the investment made by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively.

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Phantom points		The class of interests to be issued under the Phantom Unit Plan I, and to be issued under the Phantom Unit Plan II, which represent or will represent the opportunity to receive a cash payment when distributions of profit are made pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Phantom points are classified as either phantom service points or phantom performance points.

Phantom service points		Phantom points granted or to be granted pursuant to the Phantom Unit Plan I and Phantom Unit Plan II, which vest based on service.

Phantom Unit Plan I		The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition LLC.

Phantom Unit Plan II		The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition II LLC.

Profits interests		Interests in the profits of Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, also referred to as “override units.”

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		Gasoline with compounds or properties 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.

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Syngas		A mixture of gases (largely carbon monoxide and hydrogen) that results from heating coal in the presence of steam.

Throughput		The volume processed through a unit 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.

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.

Value units		Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on performance of the investment made by Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, respectively.

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 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils.

WTS		West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of30-32 degrees and a sulfur content of approximately 2.0 weight percent.

Yield		The percentage of refined products that is produced from crude and other feedstocks.

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CVR ENERGY, INC. AND SUBSIDIARIES

Index to Consolidated Financial Statements


Audited Consolidated Financial Statements:
Report of Independent Registered Public Accounting Firm			F-2
Consolidated Balance Sheets as of December 31, 2006 and December 31, 2007			F-3
Consolidated Statements of Operations for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007			F-4
Consolidated Statements of Changes in Stockholders’ Equity/Members’ Equity for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007			F-5
Consolidated Statements of Cash Flows for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007			F-9
Notes to Consolidated Financial Statements			F-10
Unaudited Condensed Consolidated Financial Statements:
Condensed Consolidated Balance Sheets as of ~~March 31,~~June 30, 2008 and December 31, 2007 (unaudited)			F-65
Condensed Consolidated Statements of Operations for the three and six months ended ~~March 31,~~June 30, 2008 (unaudited) and the three and six months ended ~~March 31,~~June 30, 2007 (unaudited)			F-66
Condensed Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~March 31,~~June 30, 2008 (unaudited) and the ~~three~~six months ended ~~March 31,~~June 30, 2007 (unaudited)			F-67
Notes to Condensed Consolidated Financial Statements (unaudited)			F-68

F-1

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. and subsidiaries (the Successor) as of December 31, 2006 and 2007, and the related statements of operations, changes in stockholders’ equity/members’ equity, and cash flows for Coffeyville Group Holdings, LLC and subsidiaries, excluding Leiber Holdings, LLC, (the Predecessor) for the174-day period ended June 23, 2005, and for the Successor for the233-day period ended December 31, 2005 and for the years ended December 31, 2006 and 2007, as discussed in note 1 to the consolidated financial statements. These consolidated financial statements are the responsibility of the Successor’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.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Successor as of December 31, 2006 and 2007, and the results of the Predecessor’s operations and its cash flows for the174-day period ended June 23, 2005 and the results of the Successor’s operations and its cash flows for the233-day period ended December 31, 2005 and for the years ended December 31, 2006 and 2007, in conformity with U.S. generally accepted accounting principles.

As discussed in note 1 to the consolidated financial statements, effective June 24, 2005, the Successor acquired the net assets of the Predecessor in a business combination accounted for as a purchase. As a result of this acquisition, the consolidated financial statements for the periods after the acquisition are presented on a different cost basis than that for the period before the acquisition and, therefore, are not comparable.

As discussed in note 2 to the consolidated financial statements, the Company has restated the accompanying consolidated financial statements as of and for the year ended December 31, 2007.

/s/ KPMG LLP

KPMG LLP

Kansas City, Missouri

March 28, 2008, except as to note 2, which is as of May 8, 2008

F-2

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Balance Sheets


	December 31,		December 31,
	2006		2007
	(In thousands of dollars)
			As restated(†)

ASSETS
Current assets:
Cash and cash equivalents	$	41,919	$	30,509
Accounts receivable, net of allowance for doubtful accounts of $375 and $391, respectively		69,589		86,546
Inventories		161,433		254,655
Prepaid expenses and other current assets		18,525		14,186
Insurance receivable		—		73,860
Income tax receivable		32,099		31,367
Deferred income taxes		18,889		79,047

Total current assets		342,454		570,170
Property, plant, and equipment, net of accumulated depreciation		1,007,156		1,192,174
Intangible assets, net		638		473
Goodwill		83,775		83,775
Deferred financing costs, net		9,128		7,515
Insurance receivable		—		11,400
Other long-term assets		6,329		2,849

Total assets	$	1,449,480	$	1,868,356


LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	5,798	$	4,874
Note payable and capital lease obligations		—		11,640
Payable to swap counterparty		36,895		262,415
Accounts payable		138,911		182,225
Personnel accruals		24,731		36,659
Accrued taxes other than income taxes		9,035		14,732
Deferred revenue		8,812		13,161
Other current liabilities		6,019		33,820

Total current liabilities		230,201		559,526
Long-term liabilities:
Long-term debt, less current portion		769,202		484,328
Accrued environmental liabilities		5,395		4,844
Deferred income taxes		284,123		286,986
Other long-term liabilities		—		1,122
Payable to swap counterparty		72,806		88,230

Total long-term liabilities		1,131,526		865,510
Commitments and contingencies
Minority interest in subsidiaries		4,326		10,600
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006		6,981		—
Stockholders’ equity/members’ equity
Voting common units, 22,614,937 units issued and outstanding in 2006		73,593		—
Management nonvoting override units, 2,976,353 units issued and outstanding in 2006		2,853		—
Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding		—		861
Additionalpaid-in-capital		—		458,359
Retained deficit		—		(26,500	)

Total stockholders’ equity/members’ equity		76,446		432,720

Total liabilities and stockholders’ equity/members’ equity	$	1,449,480	$	1,868,356


(†)		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-3

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Operations


	Immediate Predecesssor			Successor
	174 Days Ended			233 Days Ended			Year Ended			Year Ended
	June 23,			December 31,			December 31,			December 31,
	2005			2005			2006			2007
	(in thousands except share amounts)
										As restated(†)
Net sales	$	980,706		$	1,454,260		$	3,037,567		$	2,966,865
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		768,067			1,168,137			2,443,374			2,308,740
Direct operating expenses (exclusive of depreciation and amortization)		80,914			85,313			198,980			276,138
Selling, general and administrative expenses (exclusive of depreciation and amortization)		18,342			18,320			62,600			93,122
Net costs associated with flood		—			—			—			41,523
Depreciation and amortization		1,128			23,954			51,005			60,779

Total operating costs and expenses		868,451			1,295,724			2,755,959			2,780,302

Operating income		112,255			158,536			281,608			186,563
Other income (expense):
Interest expense and other financing costs		(7,802	)		(25,007	)		(43,880	)		(61,126	)
Interest income		512			972			3,450			1,100
Gain (loss) on derivatives		(7,665	)		(316,062	)		94,493			(281,978	)
Loss on extinguishment of debt		(8,094	)		—			(23,360	)		(1,258	)
Other income (expense)		(761	)		(564	)		(900	)		356

Total other income (expense)		(23,810	)		(340,661	)		29,803			(342,906	)

Income (loss) before income taxes and minority interest in subsidiaries		88,445			(182,125	)		311,411			(156,343	)
Income tax expense (benefit)		36,048			(62,968	)		119,840			(88,515	)
Minority interest in loss of subsidiaries		—			—			—			210

Net income (loss)	$	52,397		$	(119,157	)	$	191,571		$	(67,618	)

Unaudited Pro Forma Information (Note 13)
Net earnings (loss) per share
Basic							$	2.22		$	(0.78	)
Diluted							$	2.22		$	(0.78	)
Weighted average common shares outstanding:
Basic								86,141,291			86,141,291
Diluted								86,158,791			86,141,291


(†)		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-4

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in

Stockholders’ Equity/Members’ Equity


	Voting			Nonvoting			Unearned
	Preferred			Common			Compensation			Total
	(in thousands of dollars)

Immediate Predecessor
Members’ Equity, December 31, 2004	$	10,485		$	7,585		$	(3,986	)	$	14,084
Recognition of earned compensation expense related to common units		—			—			3,986			3,986
Contributed capital		728			—			—			728
Dividends on preferred units ($0.70 per unit)		(44,083	)		—			—			(44,083	)
Dividends to management on common units ($0.70 per unit)		—			(8,128	)		—			(8,128	)
Net income		44,240			8,157			—			52,397

Members’ Equity, June 23, 2005	$	11,370		$	7,614		$	—		$	18,984

See accompanying notes to consolidated financial statements.

F-5

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in

Stockholders’ Equity/Members’ Equity — (Continued)


	Management Voting						Note Receivable
	Common Units						from Management
	Subject to Redemption						Unit Holder			Total
	Units			Dollars			Dollars			Dollars
	(in thousands of dollars except share amounts)

Successor
For the 233 days ended December 31, 2005, and the year ended December 31, 2006
Balance at May 13, 2005		—		$	—		$	—		$	—
Issuance of 177,500 common units for cash		177,500			1,775			—			1,775
Issuance of 50,000 common units for note receivable		50,000			500			(500	)		—
Adjustment to fair value for management common units		—			3,035			—			3,035
Net loss allocated to management common units		—			(1,138	)		—			(1,138	)

Balance at December 31, 2005		227,500			4,172			(500	)		3,672
Payment of note receivable		—			—			150			150
Forgiveness of note receivable		—			—			350			350
Adjustment to fair value for management common units		—			4,240			—			4,240
Prorata reduction of management common units outstanding		(26,437	)		—			—			—
Distributions to management on common units		—			(3,119	)		—			(3,119	)
Net income allocated to management common units		—			1,688			—			1,688

Balance at December 31, 2006		201,063			6,981			—			6,981
Adjustment to fair value for management common units, as restated(†)		—			2,037			—			2,037
Net loss allocated to management common units, as restated(†)		—			(362	)		—			(362	)
Change from partnership to corporate reporting structure		(201,063	)		(8,656	)		—			(8,656	)

Balance at December 31, 2007		—		$	—		$	—		$	—


(†)		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-6

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in

Stockholders’ Equity/Members’ Equity — (Continued)


							Management						Management
							Nonvoting Override						Nonvoting Override
	Voting Common Units						Operating Units						Value Units						Total
	Units			Dollars			Units			Dollars			Units			Dollars			Dollars
	(in thousands of dollars except share amounts)

For the 233 days ended December 31, 2005, and the year ended December 31, 2006
Balance at May 13, 2005		—		$	—			—		$	—			—		$	—		$	—
Issuance of 23,588,500 common units for cash		23,588,500			235,885			—			—			—			—			235,885
Issuance of 919,630 nonvested operating override units		—			—			919,630			—			—			—			—
Issuance of 1,839,265 nonvested value override units		—			—			—			—			1,839,265			—			—
Recognition of share-based compensation expense related to override units		—			—			—			603			—			395			998
Adjustment to fair value for management common units		—			(3,035	)		—			—			—			—			(3,035	)
Net loss allocated to common units		—			(118,019	)		—			—			—			—			(118,019	)

Balance at December 31, 2005		23,588,500			114,831			919,630			603			1,839,265			395			115,829
Issuance of 2,000,000 common units for cash		2,000,000			20,000			—			—			—			—			20,000
Recognition of share-based compensation expense related to override units		—			—			—			1,160			—			695			1,855
Adjustment to fair value for management common units		—			(4,240	)		—			—			—			—			(4,240	)
Prorata reduction of common units outstanding		(2,973,563	)		—			—			—			—			—			—
Issuance of 72,492 nonvested operating override units		—			—			72,492			—			—			—			—
Issuance of 144,966 nonvested value override units		—			—			—			—			144,966			—			—
Distributions to common unit holders		—			(246,881	)		—			—			—			—			(246,881	)
Net income allocated to common units		—			189,883			—			—			—			—			189,883

Balance at December 31, 2006		22,614,937			73,593			992,122			1,763			1,984,231			1,090			76,446
Recognition of share-based compensation expense related to override units		—			—			—			1,018			—			701			1,719
Adjustment to fair value for management common units, as restated(†)		—			(2,037	)		—			—			—			—			(2,037	)
Adjustment to fair value for minority interest		—			(1,053	)		—			—			—			—			(1,053	)
Reversal of minority interest fair value adjustments upon redemption of the minority interest		—			1,053			—			—			—			—			1,053
Net loss allocated to common units, as restated(†)		—			(40,756	)		—			—			—			—			(40,756	)
Change from partnership to corporate reporting structure, as restated(†)		(22,614,937	)		(30,800	)		(992,122	)		(2,781	)		(1,984,231	)		(1,791	)		(35,372	)

Balance at December 31, 2007		—		$	—			—		$	—			—		$	—		$	—


(†)		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-7

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Changes in

Stockholders’ Equity/Members’ Equity — (Continued)


	Common Stock				Additional									Common Stock				Additional
	Shares				Paid-In			Retained						Shares				Paid-In			Retained
	Issued		Amount		Capital			Deficit			Total			Issued		Amount		Capital			Deficit			Total
	(in thousands of dollars except share amounts)													(in thousands of dollars except share amounts)

Balance at January 1, 2007		—	$	—	$	��		$	—		$	—			—	$	—	$	—		$	—		$	—
Change from partnership to corporate reporting structure, as restated(†)		62,866,720		629		43,398			—			44,027			62,866,720		629		43,398			—			44,027
Issuance of common stock in exchange for minority interest of related party		247,471		2		4,700			—			4,702			247,471		2		4,700			—			4,702
Cash dividend declared		—		—		(10,600	)		—			(10,600	)		—		—		(10,600	)		—			(10,600	)
Public offering of common stock, net of stock issuance costs of $39,873,655		22,917,300		229		395,326			—			395,555			22,917,300		229		395,326			—			395,555
Purchase of common stock by employees through share purchase program		82,700		1		1,570			—			1,571			82,700		1		1,570			—			1,571
Share-based compensation		—		—		23,400			—			23,400			—		—		23,400			—			23,400
Issuance of common stock to employees		27,100		—		565			—			565			27,100		—		565			—			565
Net loss, as restated(†)		—		—		—			(26,500	)		(26,500	)		—		—		—			(26,500	)		(26,500	)

Balance at December 31, 2007, as restated(†)		86,141,291	$	861	$	458,359		$	(26,500	)	$	432,720			86,141,291	$	861	$	458,359		$	(26,500	)	$	432,720


(†)		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-8

CVR ENERGY, INC. AND SUBSIDIARIES

Consolidated Statements of Cash Flows


	Immediate
	Predecessor			Successor
	174 Days Ended			233 Days Ended			Year Ended			Year Ended
	June 23,			December 31,			December 31,			December 31,
	2005			2005			2006			2007
										As restated(†)
	(in thousands of dollars)
Cash flows from operating activities:
Net income (loss)	$	52,397		$	(119,157	)	$	191,571		$	(67,618	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		1,128			23,954			51,005			68,406
Provision for doubtful accounts		(190	)		276			100			15
Amortization of deferred financing costs		812			1,751			3,337			2,778
Loss on disposition of fixed assets		—			—			1,188			1,273
Loss on extinguishment of debt		8,094			—			23,360			1,258
Forgiveness of note receivable		—			—			350			—
Share-based compensation		3,986			1,093			16,905			44,083
Minority interest in loss of subsidiaries		—			—			—			(210	)
Changes in assets and liabilities, net of effect of acquisition:
Accounts receivable		(11,335	)		(34,507	)		1,871			(16,972	)
Inventories		(59,045	)		1,895			(7,157	)		(84,980	)
Prepaid expenses and other current assets		(939	)		(6,492	)		(5,384	)		4,848
Insurance receivable		—			—			—			(105,260	)
Insurance proceeds for flood		—			—			—			20,000
Other long-term assets		3,036			(4,651	)		1,971			3,245
Accounts payable		16,125			40,656			5,005			59,110
Accrued income taxes		4,504			(136	)		(37,039	)		732
Deferred revenue		(9,073	)		9,983			(3,218	)		4,349
Other current liabilities		1,255			10,405			4,592			27,027
Payable to swap counterparty		—			256,722			(147,021	)		240,944
Accrued environmental liabilities		(1,553	)		(539	)		(1,614	)		(551	)
Other long-term liabilities		(297	)		(296	)		—			1,122
Deferred income taxes		3,804			(98,425	)		86,770			(57,684	)

Net cash provided by operating activities		12,709			82,532			186,592			145,915

Cash flows from investing activities:
Cash paid for acquisition of Immediate Predecessor, net of cash acquired		—			(685,126	)		—			—
Capital expenditures		(12,257	)		(45,172	)		(240,225	)		(268,593	)

Net cash used in investing activities		(12,257	)		(730,298	)		(240,225	)		(268,593	)

Cash flows from financing activities:
Revolving debt payments		(343	)		(69,286	)		(900	)		(345,800	)
Revolving debt borrowings		492			69,286			900			345,800
Proceeds from issuance of long-term debt		—			500,000			805,000			50,000
Principal payments on long-term debt		(375	)		(562	)		(529,438	)		(335,797	)
Payment of financing costs		—			(24,628	)		(9,364	)		(2,491	)
Prepayment penalty on extinguishment of debt		—			—			(5,500	)		—
Payment of note receivable		—			—			150			—
Issuance of members’ equity		—			237,660			20,000			—
Net proceeds from sale of common stock		—			—			—			399,556
Distribution of members’ equity		(52,211	)		—			(250,000	)		(10,600	)
Sale of managing general partnership interest		—			—			—			10,600

Net cash provided by (used in) financing activities		(52,437	)		712,470			30,848			111,268

Net increase (decrease) in cash and cash equivalents		(51,985	)		64,704			(22,785	)		(11,410	)
Cash and cash equivalents, beginning of period		52,652			—			64,704			41,919

Cash and cash equivalents, end of period	$	667		$	64,704		$	41,919		$	30,509

Supplemental disclosures
Cash paid for income taxes, net of refunds (received)	$	27,040		$	35,593		$	70,109		$	(31,563	)
Cash paid for interest	$	7,287		$	23,578		$	51,854		$	56,886
Non-cash investing and financing activities:
Step-up in basis in property for exchange of common stock for minority interest, net of deferred taxes of $389	$	—		$	—		$	—		$	586
Accrual of construction in progress additions	$	—		$	—		$	45,991		$	(15,268	)
Contributed capital through Leiber tax savings	$	729		$	—		$	—		$	—
Notes payable and capital lease obligations for insurance and inventory	$	—		$	—		$	—		$	11,640


†		See Note 2 to consolidated financial statements.

See accompanying notes to consolidated financial statements.

F-9

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements


(1)	Organization and History of the Company

Organization

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date prior to October 16, 2007 (the date of the restructuring as further discussed in this Note) and subsequent to June 24, 2005 are to Coffeyville Acquisition LLC (CALLC) and its subsidiaries.

On June 24, 2005, CALLC 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). CRIncs collectively own 100% of CL JV Holdings, LLC (CLJV) and, directly or through CLJV, they 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).

The Company, through its wholly-owned subsidiaries, acts as 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. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. CALLC formed Coffeyville Refining & Marketing Holdings, Inc. (Refining Holdco) as a wholly owned subsidiary, incorporated in Delaware in August 2007, by contributing its shares of CRM to Refining Holdco in exchange for its shares. Refining Holdco was formed in connection with a financing transaction in August 2007. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (CALLC II).

Initial Public Offering of CVR Energy, Inc.

On October 26, 2007, CVR Energy, Inc. completed an initial public offering of 23,000,000 shares of its common stock. The initial public offering price was $19.00 per share.

The net proceeds to CVR from the initial public offering were approximately $408.5 million, after deducting underwriting discounts and commissions, but before deduction of offering expenses. The Company also incurred approximately $11.4 million of other costs related to the initial public offering. The net proceeds from this offering were used to repay $280 million of term debt under the Company’s credit facility and to repay all indebtedness under the Company’s $25 million unsecured facility and $25 million secured facility, including related accrued interest through the date of repayment of approximately $5.9 million. Additionally, $50 million of net proceeds were used to repay outstanding indebtedness under the revolving loan facility under the Company’s credit facility. In connection with the repayment of the $25 million unsecured facility and the $25 million secured facility, the Company recorded a write-off of unamortized deferred financing fees of approximately $1.3 million in the fourth quarter of 2007.

F-10

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

formed direct subsidiaries of CVR into Refining Holdco and CNF. Concurrent with the merger of the subsidiaries and in accordance with a previously executed agreement, the Company’s chief executive officer received 247,471 shares of CVR common stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully vested and were exchanged at fair market value.

The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in connection with the initial public offering. The compensation expense recorded in the fourth quarter of 2007 was $565,000 related to shares issued. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, which does not include the non-vested shares issued noted below.

On October 24, 2007, 17,500 shares of non-vested stock having a fair value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights on these shares from the date of grant. The fair value of each share of restricted stock was measured based on the market price of the common stock as of the date of grant and will be amortized over the respective vesting periods. One-third of the restricted stock will vest on October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on October 24, 2010. Additionally, options to purchase 10,300 common shares at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. These awards will vest over a three year service period. Fair value was measured using an option-pricing model at the date of grant.

Nitrogen Fertilizer Limited Partnership

In conjunction with the consummation of CVR’s initial public offering, CVR transferred CRNF, its nitrogen fertilizer business, to a newly created limited partnership (Partnership) in exchange for a managing general partner interest (managing GP interest), a special general partner interest (special GP interest, represented by special GP units) and a de minimis limited partner interest (LP interest, represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to an entity owned by its controlling stockholders and senior management at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing general partner interest was $10.6 million. This interest has been reflected as minority interest in the consolidated balance sheet at December 31, 2007.

The valuation of the managing general partner interest was based on a discounted cash flow analysis, using a discount rate commensurate with the risk profile of the managing general partner interest. The key assumptions underlying the analysis were commodity price projections, which were used to determine the Partnership’s raw material costs and output revenues. Other business expenses of the Partnership were based on management’s projections. The Partnership’s cash distributions were assumed to be flat at expected forward fertilizer prices, with cash reserves developed in periods of high prices and cash reserves reduced in periods of lower prices. The Partnership’s projected cash flows due to the managing general partner under the terms of the Partnership’s partnership agreement used for the valuation were modeled based on the structure of expectations of the Partnership’s operations, including production volumes and operating costs, which were developed by management based on historical operations and experience. Price projections were based on information received from Blue, Johnson & Associates, a leading fertilizer industry consultant in the United States which CVR routinely uses for fertilizer market analysis.

In conjunction with CVR Energy’s indirect ownership of the special GP interest, it initially owned all of the interests in the Partnership (other than the managing general partner interest and the IDRs)

F-11

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

and initially was entitled to all cash distributed by the Partnership. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the amended and restated partnership agreement, generated by the Partnership during the period from the completion of the Partnership’s initial public offering of its common units representing limited partner interests (Partnership Offering) through December 31, 2009 has been distributed in respect of the GP units and subordinated GP units, which CVR Energy will indirectly hold following completion of the Partnership Offering, and the Partnership’s common units (which will be issued in connection with the Partnership Offering) and any other partnership interests that are issued in the future. The Partnership and its subsidiaries are currently guarantors under CRLLC’s credit facility.

The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR the Partnership and the managing general partner also entered into a number of agreements to regulate certain business relations between the partners.

At December 31, 2007, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing general partner interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing general partner interest and the IDRs.

On February 28, 2008, the Partnership filed a registration statement with the SEC to effect the contemplated initial public offering of its common units representing limited partner interests. The registration statement provided that upon consummation of the Partnership’s initial public offering, CVR will indirectly own the Partnership’s special general partner and approximately 87% of the outstanding units of the Partnership. There can be no assurance that any such offering will be consummated on the terms described in the registration statement or at all. The offering is under review by the Securities and Exchange Commission (SEC) and as a result the terms and resulting structure disclosed below could be materially different.

In connection with the Partnership’s initial public offering, CRLLC will contribute all of its special LP units to the Partnership’s special general partner and all of the Partnership’s special general partner interests and special limited partner interests will be converted into a combination of GP and subordinated GP units. Following the initial public offering, the Partnership will have five types of partnership interest outstanding:


	•	5,250,000 common units representing limited partner interests, all of which the Partnership will sell in the initial public offering;

	•	18,750,000 GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner;

	•	18,000,000 subordinated GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner;

F-12

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


	•	incentive distribution rights representing limited partner interests, all of which will be held by the Partnership’s managing general partner; and

	•	a managing general partner interest, which is not entitled to any distributions, which is held by the Partnership’s managing general partner.

Effective with the Partnerships’ initial public offering, the partnership agreement will require that the Partnership distribute all of its cash on hand at the end of each quarter, less reserves established by its managing general partner, subject to the sustainability requirement in the event the Partnership elects to increase the quarterly distribution amount. The amount of available cash may be greater or less than the aggregate amount necessary to make the minimum quarterly distribution on all common units, GP units and subordinated units.

Subsequent to the initial public offering, the Partnership will make minimum quarterly distributions of $0.375 per common unit ($1.50 per common unit on an annualized basis) to the extent the Partnership has sufficient available cash. In general, cash distributions will be made each quarter as follows:


	•	First, to the holders of common units and GP units until each common unit and GP unit has received a minimum quarterly distribution of $0.375 plus any arrearages from prior quarters;

	•	Second, to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.375; and

	•	Third, to all unitholders, pro rata, until each unit has received a quarterly distribution of $0.4313.

If cash distributions exceed $0.4313 per unit in a quarter, the Partnership’s managing general partner, as holder of the IDRs, will receive increasing percentages, up to 48%, of the cash the Partnership distributes in excess of $0.4313 per unit. However, the managing general partner will not be entitled to receive any distributions in respect of the IDRs until the Partnership has made cash distributions in an aggregate amount equal to the Partnership’s adjusted operating surplus generated during the period from the closing of the initial public offering until December 31, 2009.

If the Partnership meets the financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after the first quarter whose first day begins at least three years following the closing of the Partnership Offering, 25% of the subordinated GP units will convert into GP units on a one-for-one basis. If the Partnership meets these financial tests for any three consecutive four-quarter periods ending on or after the first quarter whose first day begins at least four years following the closing of the Partnership Offering, an additional 25% of the subordinated GP units will convert into GP units on a one-for-one basis. The early conversion of the second 25% of the subordinated GP units may not occur until at least one year following the end of the last four-quarter period in respect of which the first 25% of the subordinated GP units were converted. If the subordinated GP units have converted into subordinated LP units at the time the financial tests are met they will convert into common units, rather than GP units. In addition, the subordination period will end if the managing general partner is removed as the managing general partner where “cause” (as defined in the partnership agreement) does not exist and no units held by the managing general partner and its affiliates are voted in favor of that removal.

F-13

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

When the subordination period ends, all subordinated units will convert into GP units or common units on a one-for-one basis, and the common units and GP units will no longer be entitled to arrearages.

The partnership agreement authorizes the Partnership to issue an unlimited number of additional units and rights to buy units for the consideration and on the terms and conditions determined by the managing general partner without the approval of the unitholders.

The Partnership will distribute all cash received by it or its subsidiaries in respect of accounts receivable existing as of the closing of the initial public offering exclusively to its special general partner.

The managing general partner, together with the special general partner, manages and operates the Partnership. Common unitholders will only have limited voting rights on matters affecting the Partnership. In addition, common unitholders will have no right to elect either of the general partners or the managing general partner’s directors on an annual or other continuing basis.

If at any time the managing general partner and its affiliates own more than 80% of the common units, the managing general partner will have the right, but not the obligation, to purchase all of the remaining common units at a purchase price equal to the greater of (x) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (y) the highestper-unit price paid by the managing general partner or any of its affiliates for common units during the90-day period preceding the date such notice is first mailed.

Successor and Immediate Predecessor

Successor refers collectively to both CVR Energy, Inc. and CALLC. CALLC was formed as a Delaware limited liability company on May 13, 2005. On June 24, 2005, CALLC acquired all of the outstanding stock of CRIncs from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). As a result of this transaction, CRIncs ownership increased to 100% of CLJV, a Delaware limited liability company formed on September 27, 2004. CRIncs directly and indirectly, through CLJV, collectively own 100% of CRLLC and its wholly owned subsidiaries, CRRM; CRNF; CRCT; CRP; and CRT.

CALLC 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 16 and 17) 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.

F-14

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 and Immediate Predecessor, 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 was Pegasus Partners II, L.P., the Immediate Predecessor’s principal stockholder, contributed to CLJV its interest in the Judith Leiber business, a designer handbag business, in exchange for a minority interest in CLJV. The Judith Leiber business was at the time owned through Leiber Holdings, LLC (LH), a Delaware limited liability company wholly owned at the time 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 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. 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.

F-15

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Successor 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 $673,273,000, including the assumption of $353,085,000 of liabilities. Successor also paid transaction costs of $12,519,000, which consisted of legal, accounting, and advisory fees of $5,783,000 paid to various parties, and transaction fees of $6,000,000 and $736,000 in expenses related to the acquisition paid to institutional investors (see Note 17). 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	$	667,000
Accounts receivable		37,329,000
Inventories		156,171,000
Prepaid expenses and other current assets		4,865,000
Intangibles, contractual agreements		1,322,000
Goodwill		83,775,000
Other long-term assets		3,838,000
Property, plant, and equipment		750,910,000

Total assets acquired	$	1,038,877,000

Liabilities assumed
Accounts payable	$	47,259,000
Other current liabilities		16,017,000
Current income taxes		5,076,000
Deferred income taxes		276,889,000
Other long-term liabilities		7,844,000

Total liabilities assumed	$	353,085,000

Cash paid for acquisition of Immediate Predecessor	$	685,792,000


(2)	Restatement of Financial Statements

(A) On April 23, 2008, the Audit Committee of the Board of Directors and management of the Company concluded that the Company’s previously issued consolidated financial statements for the year ended December 31, 2007 and the related quarter ended September 30, 2007 contained errors. The Company arrived at this conclusion during the course of its closing process and review for the quarter ended March 31, 2008. The restatement principally relates to errors in the calculation of the cost of crude oil purchased by the Company and associated financial transactions.

For the year ended December 31, 2007, net loss increased by $10.8 million, from $56.8 million to $67.6 million. This increase in net loss is the result of an increase in cost of product sold (exclusive of depreciation and amortization) of $17.7 million, with an associated increase in income tax benefit of $6.9 million.

F-16

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Due to the restatement, inventories for the year ended December 31, 2007 increased by $5.4 million and accounts payable increased by $23.1 million. Income tax receivable increased by $6.1 million and current deferred income tax asset increased by $0.8 million.

The effect of the above adjustments on the consolidated financial statements is set forth in the tables in 2(B) below. The restatement had no effect on net cash flows from operating, investing or financing activities as shown in the Consolidated Statements of Cash Flows. The restatement did not have any impact on the Company’s covenant compliance under its debt facilities or its cash position as of December 31, 2007.

(B) Notes 5, 11, 13, 15, 17, 18, 19 and 20 have been restated to reflect the adjustments described above.

F-17

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

The following is a summary of the impact of the restatement described in Note 2(A) on the Company’s Consolidated Balance Sheet as of December 31, 2007:


	December 31, 2007
	Previously						As
	Reported			Adjustment			Restated

Assets
Consolidated Balance Sheet
Current assets:
Cash and cash equivalents	$	30,509		$	—		$	30,509
Accounts receivable, net of allowance for doubtful accounts of $375 and $391, respectively		86,546			—			86,546
Inventories		249,243			5,412			254,655
Prepaid expenses and other current assets		14,186			—			14,186
Insurance receivable		73,860			—			73,860
Income tax receivable		25,273			6,094			31,367
Deferred income taxes		78,265			782			79,047

Total current assets		557,882			12,288			570,170
Property, plant, and equipment, net of accumulated depreciation		1,192,174			—			1,192,174
Intangible assets, net		473			—			473
Goodwill		83,775			—			83,775
Deferred financing costs, net		7,515			—			7,515
Insurance receivable		11,400			—			11,400
Other long-term assets		2,849			—			2,849

Total assets	$	1,856,068		$	12,288		$	1,868,356

Liabilities and Equity
Current liabilities:
Current portion of long-term debt	$	4,874			—			4,874
Note payable and capital lease obligations		11,640			—			11,640
Payable to swap counterparty		262,415			—			262,415
Accounts payable		159,142			23,083			182,225
Personnel accruals		36,659			—			36,659
Accrued taxes other than income taxes		14,732			—			14,732
Deferred revenue		13,161			—			13,161
Other current liabilities		33,820			—			33,820

Total current liabilities		536,443			23,083			559,526
Long-term liabilities:
Long-term debt, less current portion		484,328			—			484,328
Accrued environmental liabilities		4,844			—			4,844
Deferred income taxes		286,986			—			286,986
Other long-term liabilities		1,122			—			1,122
Payable to swap counterparty		88,230			—			88,230

Total long-term liabilities		865,510			—			865,510
Commitments and contingencies		—						—
Minority interest in subsidiaries		10,600			—			10,600
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006		—			—			—
Stockholders’ equity/members’ equity
Voting common units, 22,614,937 units issued and outstanding in 2006		—			—			—
Management nonvoting override units, 2,976,353 units issued and outstanding in 2006		—			—			—
Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding		861			—			861
Additionalpaid-in-capital		460,551			(2,192	)		458,359
Retained deficit		(17,897	)		(8,603	)		(26,500	)

Total stockholders’ equity/members’ equity		443,515			(10,795	)		432,720

Total liabilities and stockholders’ equity/members’ equity	$	1,856,068		$	12,288		$	1,868,356

F-18

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

The following is a summary of the impact of the restatement described in Note 2(A) above on the Company’s Consolidated Statements of Operations for the year ended December 31, 2007:


	December 31, 2007
	Previously
	Reported			Adjustment			As Restated

Net sales	$	2,966,865		$	—		$	2,966,865
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		2,291,069			17,671			2,308,740
Direct operating expenses (exclusive of depreciation and amortization)		276,138			—			276,138
Selling, general and administrative expenses (exclusive of depreciation and amortization)		93,122			—			93,122
Net costs associated with flood		41,523			—			41,523
Depreciation and amortization		60,779			—			60,779

Total operating costs and expenses		2,762,631			17,671			2,780,302

Operating income		204,234			(17,671	)		186,563
Other income (expense):
Interest expense and other financing costs		(61,126	)		—			(61,126	)
Interest income		1,100			—			1,100
Gain (loss) on derivatives		(281,978	)		—			(281,978	)
Loss on extinguishment of debt		(1,258	)		—			(1,258	)
Other income (expense)		356			—			356

Total other income (expense)		(342,906	)		—			(342,906	)
Income (loss) before income taxes and minority interest in subsidiaries		(138,672	)		(17,671	)		(156,343	)

Income tax expense (benefit)		(81,639	)		(6,876	)		(88,515	)
Minority interest in loss of subsidiaries		210			—			210

Net income (loss)	$	(56,823	)	$	(10,795	)	$	(67,618	)

Unaudited Pro Forma Information (Note 13)
Net earnings (loss) per share
Basic	$	(0.66	)	$	(0.12	)	$	(0.78	)
Diluted	$	(0.66	)	$	(0.12	)	$	(0.78	)
Weighted average common shares outstanding:
Basic		86,141,291						86,141,291
Diluted		86,141,291						86,141,291


(3)	Summary of Significant Accounting Policies

Principles of Consolidation

The accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interest of minority investors in its subsidiaries are recorded as minority interest. All intercompany accounts and transactions have been eliminated in consolidation.

F-19

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

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. In connection with CVR’s initial public offering, $4.2 million of deferred offering costs in 2007 were presented in operating activities in the interim financial statements. Such amounts have now been reflected as financing activities for the 2007 period in the Consolidated Statements of Cash Flows. The impact on prior financial statements of this revision is not considered material.

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, 2006 and December 31, 2007, two customers individually represented greater than 10% and collectively represented 29% and 29%, respectively, of the total accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2006 and December 31, 2007 was 16% and 15%, respectively, 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 thefirst-in, first-out (FIFO) cost, or market for fertilizer products, 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 towork-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 moving average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

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 complete. Depreciation is computed using principally the straight-line method over the estimated

F-20

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

useful lives of the various classes of depreciable assets. The lives used in computing depreciation for such assets are as follows:


		Range of Useful
Asset		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 7

Our leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease term or the estimated useful life. Expenditures for routine maintenance and repair costs are expenses when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Company’s consolidated statements of operations.

Goodwill and Intangible Assets

Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a business combination and intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. 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 related to the term debt are amortized to interest expense and other financing costs using the effective-interest method over the life of the term debt. Deferred financing costs related to the revolving loan facility and the funded letters of credit facility are amortized to interest expense and other financing costs using the straight-line method through the termination date of each credit facility.

Planned Major Maintenance Costs

The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. During the year ended December 31, 2006, the Coffeyville nitrogen plant completed a major scheduled turnaround. Costs of approximately $2,570,000 associated with the turnaround are included in direct operating expenses (exclusive of depreciation and amortization). The Coffeyville refinery completed a major scheduled turnaround in 2007. Costs of approximately $3,984,000 and $76,393,000, associated with the 2007 turnaround, were included in direct operating expenses (exclusive of depreciation and amortization) for the year ended December 31, 2006 and December 31, 2007, respectively.

Planned major maintenance activities for the nitrogen plant generally occur every two years. The required frequency of the maintenance varies by unit, for the refinery, but generally is every four years.

F-21

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $150,000, $1,061,000, $2,148,000, and $2,390,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately $907,000, $22,706,000, $47,714,000, and $57,367,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively. Direct operating expenses also exclude depreciation of $7,627,000 for the year ended December 31, 2007 that is included in “Net Costs Associated with Flood” on the consolidated statement of operations as a result of the assets being idle due to the flood.

Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of approximately $71,000, $187,000, $1,143,000, and $1,022,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.

Income Taxes

CVR accounts for income taxes under the provision of Statement Financial Accounting Standards (SFAS) No. 109,Accounting for Income Taxes. SFAS 109 requires the asset and liability approach for accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and 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. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.

As discussed in Note 11 (“Income Taxes”), CVR adopted Financial Accounting Standards Board (FASB) Interpretation No. 48,Accounting for Uncertainty in Income Taxes an Interpretation of FASB No. 109(FIN 48) effective January 1, 2007.

Consolidation of Variable Interest Entities

In accordance with FASB Interpretation No. 46R,Consolidation of Variable Interest Entities, (FIN 46R), management has reviewed the terms associated with its interests in the Partnership based upon the partnership agreement. Management has determined that the Partnership is a variable interest entity (VIE) and as such has evaluated the criteria under FIN 46R to determine that CVR is the primary beneficiary of the Partnership. FIN 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. FIN 46R defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and where there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. As

F-22

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

the primary beneficiary, CVR absorbs the majority of the expected lossesand/or receives a majority of the expected residual returns of the VIE’s activities.

Impairment of Long-Lived Assets

CVR accounts for long-lived assets in accordance with SFAS No. 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. No impairment charges were recognized for any of the periods presented.

Revenue Recognition

Revenues for products sold are recorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when payment has been received or collection is reasonably assumed. 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. Excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.

Shipping Costs

Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of product sold (exclusive of depreciation and amortization).

Derivative Instruments and Fair Value of Financial Instruments

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 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 gain (loss) on derivatives in accordance with SFAS 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, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with SFAS No. 123(R),Share-Based PaymentsandEITF 00-12 IssueNo. 00-12,Accounting by an

F-23

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee(EITF 00-12). CVR has been allocated non-cash share-based compensations expense from CALLC, CALLC II and CALLC III.

In accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair-value based measurement method in accounting for share-based compensation. In accordance withEITF 00-12, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance in EITF IssueNo. 96-18,Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires variable accounting in the circumstances.

Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The fair value of the stock options is estimated on the date of grant using the Black — Scholes option pricing model.

As of December 31, 2007, there had been 17,500 shares of non-vested common stock awarded. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have voting and non-forfeitable dividend rights on these shares from the date of grant. See Note 4, “Members’ Equity and 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, internal and third-party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. Loss contingency accruals, including those for environmental remediation, are subject to revision as further information develops or circumstances change and such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.

Use of Estimates

The consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles, using management’s best estimates and judgments where appropriate. These estimates and judgments 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 materially from these estimates and judgments.

New Accounting Pronouncements

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 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

F-24

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. The Company is currently evaluating the effect that this statement will have on its financial statements.

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

In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business combinations for which the acquisition date is on or after January 1, 2009.

In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for us beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.


(4)	Members’ Equity and Share Based Compensation

Management of Immediate Predecessor was issued 11,152,941 nonvoting restricted common units for recourse promissory notes aggregating $63,000. Concurrent with the Acquisition at June 23, 2005, as described in Note 1, all of the restricted common units of management were fully vested. Immediate Predecessor recognized $3,986,000 in compensation expense for the174-day period ended June 23, 2005, related to earned compensation.

On June 23, 2005, immediately prior to the Acquisition (see Note 1), the Immediate Predecessor used available cash balances to distribute a $52,211,000 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 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 accrued interest at 7% and required annual principal and interest payments through December 2009. The unpaid

F-25

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

balance of the unsecured recourse promissory note and all unpaid interest was forgiven September 25, 2006 (see Note 17).

As required by the term loan agreements to fund certain capital projects, on September 14, 2005 an additional $10,000,000 capital contribution was received in return for 1,000,000 voting common units and on May 23, 2006 an additional $20,000,000 capital contribution was received in return for 2,000,000 at $10 par value (Delayed Draw Capital).

Common units held by management contained put rights held by management and call rights held by CALLC exercisable at fair value in the event the management member became inactive. Accordingly, in accordance with EITF TopicNo. 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 were classified in temporary equity as Management Voting Common Units Subject to Redemption (Capital Subject to Redemption) in the accompanying consolidated balance sheets. The put rights and call rights were eliminated in October 2007.

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%. Because cash unit holder’s value and ownership interest before and after the reallocation is unchanged and since no transfer of value occurred among the common unit holders, this pro rata reduction had no accounting consequence. At December 31, 2006, management held 201,063 of the 22,816,000 voting common units.

On December 28, 2006, successor refinanced its existing long-term debt with $775 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under its previous first and second lien credit facilities, pay related fees and expenses and pay a distribution of $250 million to its common unit holders at December 31, 2006.

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 executives’ 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 LL’s board of directors (or the compensation committee thereof) determines in its discretion that put and call rights will apply.

CVR accounts for changes in redemption value of management common units in the period the changes occur and adjusts the carrying value of the Management Voting Common Units Subject to Redemption to equal the redemption value at the end of each reporting period with an equal and

F-26

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

offsetting adjustment to Members’ Equity. None of the Management Voting Common Units Subject to Redemption were redeemable at December 31, 2005 or December 31, 2006.

At December 31, 2005 the Management Voting Common Units Subject to Redemption were revalued through an independent appraisal process, and the value was determined to be $18.34 per unit. Accordingly, the carrying value of the Management Voting Common Units Subject to Redemption increased by $3,035,000 for the233-day period ended December 31, 2005 with an equal and offsetting decrease to Members’ Equity.

At December 31, 2006, the Management Voting Common Units Subject to Redemption were revalued through an independent appraisal process, and the value was determined to be $34.72 per unit. The appraisal utilized a discounted cash flow (DCF) method, a variation of the income approach, and the guideline public company method, a variation of the market approach, to determine the fair value. The guideline public company method utilized a weighting of market multiples from publicly-traded petroleum refiners and fertilizer manufactures that are comparable to the Company. The recognition of the value of $34.72 per unit increased the carrying value of the Management Voting Common Units Subject to Redemption by $4,240,000 for the year ended December 31, 2006 with an equal and offsetting decrease to Members’ Equity. This increase was the result of higher forward market price assumptions, which were consistent with what was observed in the market during the period, in the refining business resulting in increased free cash flow projections utilized in the DCF method. The market multiples for the public-traded comparable companies also increased from December 31, 2005, resulting in increased value of the units.

Concurrent with the Subsequent Acquisition, Successor issued nonvoting override operating units to certain management members who hold common units. There were no required capital contributions for the override operating units.

Upon completion of the initial public offering on October 26, 2007, members’ equity, Management Voting Common Units Subject to Redemption, and Management Nonvoting Override Units were eliminated and replaced with Stockholders’ Equity to reflect the new corporate structure.

The following describes the share-based compensation plans of CALLC, CALLC II, CALLC III and CRLLC, CVR Energy’s wholly owned subsidiary.

919,630 Override Operating Units at an Adjusted Benchmark Value of $11.31 per Unit

In June 2005, CALLC issued nonvoting override operating units to certain management members holding common units of CALLC. There were no required capital contributions for the override operating units. In accordance with SFAS 123(R),Share Based Compensation, using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,605,000. Pursuant to the forfeiture schedule described below, CVR Energy recognized 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 was $602,000, $1,157,000, and $10,675,000 for the191-day period ending December 31, 2005, and for the years ending December 31, 2006 and 2007, respectively. In connection with the split of CALLC into two entities on October 16, 2007, management’s equity interest in CALLC was split so that half of management’s equity interest is in CALLC and half is in CALLC II. The restructuring resulted in a modification of the existing awards under SFAS 123(R). However, because the fair value of the modified award equaled the fair value of the original award before the modification, there was no accounting consequence as a result of the modification. However, due to the restructuring, the employees of CVR Energy and CVR Partners no longer hold share-based awards in a parent company. Due to the change in status of the employees related to the awards, CVR Energy

F-27

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

recognized compensation expense for the newly measured cost attributable to the remaining vesting (service) period prospectively from the date of the change in status, which expense is included in the amounts noted above. Also, CVR Energy now accounts for these awards pursuant toEITF 00-12 following the guidance inEITF 96-18, which requires variable accounting in this circumstance. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units as noted below.

Significant assumptions used in the valuation were as follows:


	Grant Date	Remeasurement Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule below	Based on forfeiture schedule below
Grant — date; fair value — controlling basis	$5.16 per share	—
October 16, 2007 (date of modification) estimated fair value	—	$39.53
December 31, 2007 estimated fair value	N/A	$51.84 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	35.8%

72,492 Override Operating Units at a Benchmark Value of $34.72 per Unit

On December 28, 2006, CALLC issued additional nonvoting override operating units to a certain management member who holds common units of CALLC. There were no required capital contributions for the override operating units. In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units on December 28, 2006 of $473,000. Management believed that this method was preferable for the valuation of the override units as it allowed a better integration of the cash flows with other inputs, including the timing of potential exit events that impact the estimated fair value of the override units. These override operating units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above and pursuant to the forfeiture schedule described below, CVR recognized compensation expense of $3,000 and $877,000 for the periods ending December 31, 2006 and 2007, respectively. The amount included in the year ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units as described below.

F-28

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Significant assumptions used in the valuation were as follows:


	Grant Date	Remeasurement Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule below	Based on forfeiture schedule below
Grant — date; fair value — controlling basis	$8.15 per share	—
October 16, 2007 (date of modification) estimated fair value	—	$20.34
December 31, 2007 estimated fair value	N/A	$32.65 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	35.8%

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 an Adjusted Benchmark Value of $11.31 per Unit

In June 2005, CALLC issued 1,839,265 nonvoting override value units to certain management members holding common units of CALLC. There were no required capital contributions for the override value units.

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 $4,065,000. For the override value units, CVR Energy is recognizing compensation expense ratably over the implied service period of 6 years. These override value units are being accounted for the same as the override operating units with an adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above, CVR recognized compensation expense of $395,000, $677,000, and $12,788,000 for the191-day period ending December 31, 2005, and for the years ending December 31, 2006 and 2007, respectively. The amount included in the year ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash

F-29

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

flow projections resulted in an estimated fair value of the override value units as described below. Significant assumptions used in the valuation were as follows:


	Grant Date	Remeasurement Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant — date; fair value — controlling basis	$2.91 per share	—
October 16, 2007 (date of modification) estimated fair value	—	$39.53
December 31, 2007 estimated fair value	N/A	$51.84 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	35.8%

144,966 Override Value Units at a Benchmark Value of $34.72 per Unit

On December 28, 2006, CALLC issued 144,966 additional nonvoting override value units to a certain management member who holds common units of CALLC. There were no required capital contributions for the override value units.

In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override value units on December 28, 2006 of $945,000. Management believed that this method was preferable for the valuation of the override units as it allowed a better integration of the cash flows with other inputs, including the timing of potential exit events that impact the estimated fair value of the override units. For the override value units, CVR Energy is recognizing compensation expense ratably over the implied service period of 6 years. These override value units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above, CVR recognized compensation expense of $17,000, and $718,000 for the years ending December 31, 2006 and 2007, respectively. The amount included in the year ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override value units as noted below.

Significant assumptions used in the valuation were as follows:


	Grant Date	Remeasurement Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant — date; fair value — controlling basis	$8.15 per share	—
October 16, 2007 (date of modification) estimated fair value	—	$20.34
December 31, 2007 estimated fair value	N/A	$32.65 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	35.8%

F-30

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Unless the compensation committee of the board of directors of CVR Energy 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:


	Forfeiture
Minimum Period Held	Percentage

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

At December 31, 2007, assuming no change in the estimated fair value at December 31, 2007, there was approximately $71.1 million of unrecognized compensation expense related to nonvoting override units. This is expected to be recognized over a period of five years as follows (in thousands):


	Override		Override
Year Ending December 31,	Operating Units		Value Units

2008	$	7,882	$	16,924
2009		4,087		16,924
2010		1,217		16,924
2011		—		7,138

	$	13,186	$	57,910

Phantom Unit Appreciation Plan

CVR Energy, 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 of CVR Energy. As of December 31, 2007, the issued Profits Interest (combined phantom plan and override units) represented 15% of combined common unit interest and Profits Interest of CVR Energy. The Profits Interest was comprised of 11.1% and 3.9% of override interest and phantom interest, respectively. In accordance with SFAS 123(R), using the December 31, 2007 CVR Energy stock closing price to determine the CVR Energy equity value, through an independent valuation process, the service phantom interest and the performance phantom interest were both valued at $51.84 per point. CVR has recorded compensation expense related to the Phantom Unit Plan of $95,000, $10,722,000, and $18,400,000 for the191-day period ending December 31, 2005, and for the years ending December 31, 2006 and December 31, 2007, respectively. $10,817,000 and $29,217,000 were recorded in personnel accruals as of December 31, 2006 and 2007, respectively.

At December 31, 2007, and assuming no change in the estimated fair value at December 31, 2007, there was approximately $25.2 million of unrecognized compensation expense related to the Phantom Unit Plan. This is expected to be recognized over a remaining period of four years.

F-31

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

138,281 Override Units with a Benchmark Amount of $10

In October 2007, CALLC III issued non-voting override units to certain management members holding common units of CALLC III. There were no required capital contributions for the override units. In accordance with SFAS 123(R),Share Based Compensation, using a binomial and a probability-weighted expected return method which utilized the CALLC III’s cash flows projections, the estimated fair value of the operating units at December 31, 2007 was $3,000. CVR Energy recognizes compensation costs for this plan based on the fair value of the awards at the end of each reporting period in accordance withEITF 00-12 using the guidance inEITF 96-18. In accordance withEITF 00-12, as a noncontributing investor, CVR Energy also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is, its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation costs. This amount equaled the compensation expense recognized for these awards for the year ended December 31, 2007. Pursuant to the forfeiture schedule reflected above, CVR Energy recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed.

Significant Assumptions used in the valuation were as follows:


Estimated forfeiture rate		None
Explicit Service Period		Based on forfeiture schedule above
December 31, 2007 estimated fair value		$0.02 per share
Marketability and minority interest discount		15% discount
Volatility		34.7%

In connection with the initial public offering, the fractional shares held by the Company’s chief executive officer in the Successor’s subsidiaries were exchanged at the fair value for 247,471 shares of CVR common stock. This exchange resulted in the elimination of the minority interest, the reversal of previous fair value adjustments of $1,053,000 in Members’ Equity, thestep-up in property, plant and equipment of $974,000, and the recognition of a related deferred tax liability of $389,000.

In February 2008, CALLC III issued additional non-voting override units to management members.

Long Term Incentive Plan

The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP, permits the grant of options, stock appreciation rights, or SARs, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). Individuals who are eligible to receive awards and grants under the LTIP include the Company’s subsidiaries’ employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below. As of December 31, 2007, no awards had been made under the LTIP to any of the Company’s executive officers.

Shares Available for Issuance. The LTIP authorizes a share pool of 7,500,000 shares of the Company’s common stock, 1,000,000 of which may be issued in respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available for issuance under the LTIP shall be increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of the award. As of December 31, 2007, 7,463,600 shares of common stock were available for issuance under the LTIP.

F-32

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Options to purchase 10,300 common shares at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. Options to purchase 8,600 common shares at an exercise price of $24.73 per share were granted to outside directors on December 21, 2007.

A summary of the status of CVR’s non-vested shares as of December 31, 2007 and changes during the year ended December 31, 2007 is presented below:


			Weighted
			Average
			Grant-Date
Non-Vested Shares	Shares		Fair Value
	(In 000’s)

Non-vested at December 31, 2006	$	—	$	—
Granted		18		20.88
Vested		—		—
Forfeited		—		—

Non-vested at December 31, 2007	$	18	$	20.88

As of December 31, 2007, there was approximately $0.3 million of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately one year. Total compensation expense recorded in 2007 related to the nonvested stock was $42,000.

Activity and price information regarding CVR’s stock options granted are summarized as follows:


					Weighted
			Weighted		Average
			Average		Remaining
			Exercise		Contractual
Options	Shares		Price		Term
	(In 000’s)

Outstanding, December 31, 2006		—	$	—		—
Granted		19	$	21.61		9.89
Exercised		—		—
Forfeited		—		—
Expired		—		—
Outstanding, December 31, 2007		19	$	21.61		9.89
Vested or expected to vest at December 31, 2007		—		—
Exercisable at December 31, 2007		—		—

The weighted average grant-date fair value of options granted during the year ended December 31, 2007 was $12.47 per share. Total compensation expense recorded in 2007 related to the stock options was $15,000.

F-33

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(5)	Inventories

Inventories consisted of the following (in thousands):


	Successor
	December 31,		December 31,
	2006		2007
			As restated(†)

Finished goods	$	59,722	$	109,394
Raw materials and catalysts		60,810		92,104
In-process inventories		18,441		29,817
Parts and supplies		22,460		23,340

	$	161,433	$	254,655


(†)		See Note 2 to consolidated financial statements.


(6)	Property, Plant, and Equipment

A summary of costs for property, plant, and equipment is as follows (in thousands):


	Successor
	December 31,		December 31,
	2006		2007

Land and improvements	$	11,028	$	13,058
Buildings		11,042		17,541
Machinery and equipment		864,140		1,108,858
Automotive equipment		4,175		5,171
Furniture and fixtures		5,364		6,304
Leasehold improvements		887		929
Construction in progress		184,531		182,046

		1,081,167		1,333,907
Accumulated depreciation		74,011		141,733

	$	1,007,156	$	1,192,174

Capitalized interest recognized as a reduction in interest expense for the years ended December 31, 2006, and December 31, 2007 totaled approximately $11,613,000 and $12,049,000, respectively.


(7)	Goodwill and Intangible Assets

In connection with the Acquisition described in Note 1, Successor recorded goodwill of $83,775,000. SFAS No. 142,Goodwill and Other Intangible Assets, provides that goodwill and other intangible assets with indefinite lives shall not be amortized but shall be tested for impairment on an annual basis. In accordance with SFAS 142, Successor completed its annual test for impairment of goodwill as of November 1, 2006 and 2007. Based on the results of the test, no impairment of goodwill was recorded as of December 31, 2006 or December 31, 2007. 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. CVR’s reporting units are defined as operating segments, as such all goodwill impairment testing is done at each operating segment.

F-34

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Contractual agreements with a fair market value of $1,322,000 were acquired in the Acquisition described in Note 1. The intangible value of these agreements is amortized over the life of the agreements through June 2025. Amortization expense of $313,000, $370,000, and $165,000 was recorded in depreciation and amortization for the233-days ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.

Estimated amortization of the contractual agreements is as follows (in thousands):


	Contractual
Year Ending December 31,	Agreements

2008		64
2009		33
2010		33
2011		33
2012		28
Thereafter		282

		473


(8)	Deferred Financing Costs

Deferred financing costs of $10,009,000 were paid in conjunction with a debt financing in 2004. The unamortized amount of these deferred financing costs of $8,094,000 related to the May 10, 2004 refinancing were written off when the related debt was extinguished upon the 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 174 days ended June 23, 2005, amortization of deferred financing costs reported as interest expense and other financing costs was $812,000, using the effective-interest amortization method.

Deferred financing costs of $24,628,000 were paid in the Acquisition described in Note 1. Effective December 28, 2006, the Company amended and restated its credit agreement with a consortium of banks, additionally capitalizing $8,462,000 in debt issuance costs. This amendment and restatement was within the scope of theEITF 96-19,Debtor’s Accounting for Modification or Exchange of Debt Instruments, as well asEITF 98-14,Debtor’s Accounting for Changes inLine-of-Credit or Revolving-Debt Arrangements. In accordance with that guidance, a portion of the unamortized loan costs of $16,959,000 from the original credit facility as well as additional finance and legal charges associated with the second amended and restated credit facility of $901,000 were included in loss on extinguishment of debt for the year December 31, 2006. The remaining costs are being amortized over the life of the related debt instrument. Additionally, a prepayment penalty of $5,500,000 on the previous credit facility was also paid and expensed and included in loss on extinguishment of debt for the year ended December 31, 2006. For the 233 days ended December 31, 2005, the years ended December 31, 2006, and December 31, 2007, amortization of deferred financing costs reported as interest expense and other financing costs totaled $1,751,000, $3,337,000, and $1,947,000, respectively, using the effective-interest amortization method for the term debt and the straight-line method for the letter of credit facility and revolving loan facility.

Deferred financing costs of $2,088,000 were paid in conjunction with three new credit facilities entered into August 2007 as a result of the flood and crude oil discharge. The unamortized amount of these deferred financing costs of $1,258,000 were written off when the related debt was extinguished upon the consummation of the initial public offering and these costs were included in loss on extinguishment of debt for the year ended December 31, 2007. Amortization of deferred financing costs reported as interest expense and other financing costs was $831,000 using the effective-interest amortization method.

F-35

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Deferred financing costs consisted of the following (in thousands):


	December 31,		December 31,
	2006		2007

Deferred financing costs	$	11,065	$	12,278
Less accumulated amortization		21		2,778

Unamortized deferred financing costs		11,044		9,500
Less current portion		1,916		1,985

	$	9,128	$	7,515

Estimated amortization of deferred financing costs is as follows (in thousands):


	Deferred
Year Ending December 31,	Financing

2008	$	1,985
2009		1,968
2010		1,953
2011		1,436
2012		1,426
Thereafter		732

	$	9,500


(9)	Note Payable and Capital Lease Obligations

The Company entered into an insurance premium finance agreement in July 2007 to finance the purchase of its property, liability, cargo and terrorism policies. The approximately $3.4 million note will be repaid in equal monthly installments of $0.8 million with final payment in April 2008.

The Company entered into two capital leases in 2007 to lease platinum required in the manufacturing of a new catalyst. The leases will terminate on the date an equal amount of platinum is returned to each lessor with the difference to be paid in cash. At December 31, 2007 the lease obligations were recorded at approximately $8.2 million on the consolidated balance sheet.


(10)	Flood

On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. As a result, the Company’s refinery and nitrogen fertilizer plant were severely flooded resulting in significant damage to the refinery assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The Company maintains property damage insurance which includes damage caused by a flood of up to $300 million per occurrence subject to deductibles and other limitations. The deductible associated with the property damage is $2.5 million.

Management is working closely with the Company’s insurance carriers and claims adjusters to ascertain the full amount of insurance proceeds due to the Company as a result of the damages and losses. The Company has recognized a receivable of approximately $85.3 million from insurance at December 31, 2007 which management believes is probable of recovery from the insurance carriers. While management believes that the Company’s property insurance should cover substantially all of the estimated total physical damage to the property, the Company’s insurance carriers have cited potential coverage limitations and defenses that might preclude such a result.

F-36

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

The Company’s insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Company has incurred relating to the damages and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. Because the fertilizer plant was restored to operation within this45-day period and the refinery restarted its last operating unit in 48 days, a substantial portion of the lost profits incurred because of the flood cannot be claimed under insurance. The Company is assessing its policies to determine how much, if any, of its lost profits after the45-day period are recoverable. No amounts for recovery of lost profits under the Company’s business interruption policy have been recorded in the accompanying consolidated financial statements.

As of December 31, 2007, the Company has recorded pretax costs of approximately $41.5 million associated with the flood and related crude oil discharge as discussed in Note 15, “Commitments and Contingent Liabilities”, including $7.2 million in the fourth quarter of 2007. These amounts were net of anticipated insurance recoveries of approximately $105.3 million. The components of the net costs as of December 31, 2007 include $3.6 million for uninsured losses within the Company’s insurance deductibles; $7.6 million for depreciation for the temporarily idled facilities; $6.8 million as a result of other uninsured expenses incurred which included salaries of $1.2 million, professional fees of $1.9 million and other miscellaneous amounts of $3.7 million. The $41.5 million net costs also included approximately $23.5 million recorded with respect to the environmental remediation and property damage as discussed in Note 15, “Commitments and Contingent Liabilities”. These costs are reported in “Net costs associated with flood” in the Consolidated Statements of Operations.

Total gross costs recorded due to the flood and related oil discharge that were included in the statement of operations for the year ended December 31, 2007 were approximately $146.8 million. Of these gross costs for the year ended December 31, 2007, approximately $101.9 million were associated with repair and other matters as a result of the flood damage to the Company’s facilities. Included in this cost was $7.6 million of depreciation for temporarily idled facilities, $6.1 million of salaries, $2.2 million of professional fees and $86.0 million for other repair and related costs. There were approximately $44.9 million costs recorded for the year ended December 31, 2007 related to the third party and property damage remediation as a result of the crude oil discharge. Total anticipated insurance recoveries of approximately $105.3 million were recorded and netted with the gross costs as of December 31, 2007. As of December 31, 2007, CVR had received insurance proceeds of $10.0 million under its property insurance policy, and an additional $10.0 million under its environmental policies related to the recovery of certain costs associated with the crude oil discharge. Subsequent to December 31, 2007, CVR received insurance proceeds of $1.5 million under the Builder’s Risk Insurance Policy. See Note 15, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007. Accounts receivable from insurers for flood related matters approximated $85.3 million at December 31, 2007, for which we believe collection is probable, including $11.4 million related to the crude oil discharge and $73.9 million as a result of the flood damage to the Company’s facilities.

The Company anticipates that approximately $6.0 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods. Although the Company believes that it will recover substantial sums under its insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company ultimately receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements.

F-37

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(11)	Income Taxes

Income tax expense (benefit) is comprised of the following (in thousands):


	Immediate
	Predecessor		Successor
	174 Days		233 Days			Year		Year
	Ended		Ended			Ended		Ended
	June 23,		December 31,			December 31,		December 31,
	2005		2005			2006		2007
								As restated(†)
Current
Federal	$	26,145	$	29,000		$	26,096	$	(26,814	)
State		6,099		6,457			6,974		(4,017	)

Total current		32,244		35,457			33,070		(30,831	)

Deferred
Federal		3,083		(80,500	)		69,836		(21,434	)
State		721		(17,925	)		16,934		(36,250	)

Total deferred		3,804		(98,425	)		86,770		(57,684	)

Total income tax expense (benefit)	$	36,048	$	(62,968	)	$	119,840	$	(88,515	)

The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federal income tax rate (35%) to income before income tax expense (benefit) (in thousands):


	Immediate
	Predecessor			Successor
	174 Days			233 Days			Year			Year
	Ended			Ended			Ended			Ended
	June 23,			December 31,			December 31,			December 31,
	2005			2005			2006			2007
										As restated(†)
Tax computed at federal statutory rate	$	30,956		$	(63,744	)	$	108,994		$	(54,720	)
State income taxes, net of federal tax benefit (expense)		4,433			(7,454	)		15,618			(6,382	)
State tax incentives, net of deferred federal tax expense		—			—			(78	)		(19,792	)
Manufacturing activities deduction		(825	)		(897	)		(1,089	)		—
Federal tax credit for production of ultra-low sulfur diesel fuel		—			—			(4,462	)		(17,259	)
Loss on unexercised option agreements with no tax benefit to Successor		—			8,750			—			—
Non-deductible share based compensation		1,395			349			649			8,771
Other, net		89			28			208			867

Total income tax expense (benefit)	$	36,048		$	(62,968	)	$	119,840		$	(88,515	)


(†)		See Note 2 to consolidated financial statements.

F-38

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Certain provisions of the American Jobs Creation Act of 2004 (the Act) are providing federal income tax benefits to CVR. The Act created Internal Revenue Code section 199 which provides an income tax benefit to domestic manufacturers. CVR recognized an income tax benefit related to this manufacturing deduction of approximately $825,000, $897,000, $1,089,000, and $0 for the 174 days ended June 23, 2005, the 233 days ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.

The Act also provides for a $0.05 per gallon income tax credit on compliant diesel fuel produced up to an amount equal to the remaining 25% of the qualified capital costs. CVR recognized an income tax benefit of approximately $4,462,000 and $17,259,000 on a credit of approximately $6,865,000 and $26,552,000 related to the production of ultra low sulfur diesel for the years ended December 31, 2006, and December 31, 2007, respectively.

The loss on unexercised option agreements of $25,000,000 in 2005 occurred at Coffeyville Acquisition LLC, and the tax deduction related to the loss was passed through to the partners of Coffeyville Acquisition LLC in the 233 days ended December 31, 2005.

The income tax effect of temporary differences that give rise to significant portions of the deferred income tax assets and deferred income tax liabilities at December 31, 2006 and 2007 are as follows:


	December 31,			December 31,
	2006			2007
				As restated(†)
	(in thousands)

Deferred income tax assets:
Allowance for doubtful accounts	$	150		$	156
Personnel accruals		5,072			12,757
Inventories		673			671
Unrealized derivative losses, net		40,389			85,650
Low sulfur diesel fuel credit carry forward		—			17,860
State net operating loss carry forwards, net of federal expense		—			4,158
Accrued expenses		249			1,713
Deferred revenue		—			3,403
State tax credit carryforward, net of federal expense		—			17,475
Other		—			353

Total Gross deferred income tax assets		46,533			144,196

Deferred income tax liabilities:
Property, plant, and equipment		(309,472	)		(348,902	)
Prepaid Expenses		(1,140	)		(3,233	)
Other		(1,155	)		—

Total Gross deferred income tax liabilities		(311,767	)		(352,135	)

Net deferred income tax liabilities	$	(265,234	)	$	(207,939	)


(†)		See Note 2 to consolidated financial statements.

At December 31, 2007, CVR has net operating loss carryforwards for state income tax purposes of approximately $86.9 million, which are available to offset future state taxable income. The net operating loss carryforwards, if not utilized, will expire between 2012 and 2027.

F-39

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

At December 31, 2007, CVR has federal tax credit carryforwards related to the production of low sulfur diesel fuel of approximately $17.9 million, which are available to reduce future federal regular income taxes. These credits, if not used, will expire in 2027. CVR also has Kansas state income tax credits of approximately $26.9 million, which are available to reduce future Kansas state regular income taxes. These credits, if not used, will expire in 2017.

In assessing the realizability of deferred tax assets including net operating loss and credit carryforwards, 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, CVR has not recorded any valuation allowances against deferred tax assets as of December 31, 2006 or December 31, 2007.

CVR adopted FIN 48 effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements. If the probability of sustaining a tax position is at least more likely than not, then the tax position is warranted and recognition should be at the highest amount which is greater than 50% likely of being realized upon ultimate settlement. As of the date of adoption of FIN 48 and at December 31, 2007, CVR did not believe it had any tax positions that met the criteria for uncertain tax positions. As a result, no amounts were recognized as a liability for uncertain tax positions.

CVR recognizes interest and penalties on uncertain tax positions and income tax deficiencies in income tax expense. CVR did not recognize any interest or penalties in 2007 for uncertain tax positions or income tax deficiencies. At December 31, 2007, CVR’s tax returns are open to examination for federal and various states for the 2004 to 2007 tax years.

A reconciliation of the unrecognized tax benefits for the year ended December 31, 2007, is as follows:


Balance as of January 1, 2007	$	0
Increase and decrease in prior year tax positions		—
Increases and decrease in current year tax positions		—
Settlements		—
Reductions related to expirations of statute of limitations		—

Balance as of December 31, 2007	$	0


(12)	Long-Term Debt

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. 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 17). The credit facility was in an aggregate amount not to exceed $525,000,000, consisting of $225,000,000 Tranche B Term

F-40

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

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 was secured by substantially all of Successor’s assets. Outstanding borrowings on December 28, 2006 were repaid in connection with the refinancing described below.

The Term Loans and Revolving Loan Facility provided CVR the option of a3-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 was paid quarterly when using the Index Rate and at the expiration of the LIBOR term selected when using the LIBOR rate; interest varied with the Index Rate or LIBOR rate in effect at the time of the borrowing. The annual fee for the Funded Facility was 2.725% of outstanding Funded Letters of Credit.

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 17). CVR had the option of a3-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 loan was secured by a second lien on substantially all of CVR’s assets. Outstanding borrowings on December 28, 2006 were repaid in connection with the refinancing described below.

On December 28, 2006, Successor entered into a second amended and restated credit and guaranty agreement (the credit and guaranty agreement) with two banks and one related party institutional lender (see Note 17). The credit facility was in an aggregate amount not to exceed $1,075,000,000, consisting of $775,000,000 Tranche D Term Loans; a $150,000,000 Revolving Loan Facility; and a Funded Facility of $150,000,000. The credit facility was secured by substantially all of CVR’s assets. At December 31, 2006, and December 31, 2007, $775,000,000 and $489,202,000 of Tranche D Term Loans was outstanding, and there was no outstanding balance on the Revolving Loan Facility. At December 31, 2006, and December 31, 2007, Successor had $150,000,000 in Funded Letters of Credit outstanding to secure payment obligations under derivative financial instruments (see Note 16).

At December 31, 2006, the Term Loan and Revolving Loan Facility provided CVR the option of a3-month LIBOR rate plus 3.0% 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 2.0%). At December 31, 2007, the Term Loan and Revolving Loan Facility provide CVR the option of a3-month LIBOR rate plus 2.75% 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 1.75%). 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, 2006 and December 31, 2007 was 8.36%and 7.98%, respectively. The annual fee for the Funded Facility was 3.225% and 2.975%, respectively at December 31, 2006 and December 31, 2007 of outstanding Funded Letters of Credit.

F-41

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

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:

First Lien Credit Facility


	Minimum
	Interest		Maximum
Fiscal Quarter Ending	Coverage Ratio		Leverage Ratio

March 31, 2008		3.25:1.00		3.25:1.00
June 30, 2008		3.25:1.00		3.00:1.00
September 30, 2008		3.25:1.00		2.75:1.00
December 31, 2008		3.25:1.00		2.50:1.00
March 31, 2009 — December 31, 2009		3.75:1.00		2.25:1.00
March 31, 2010 and thereafter		3.75:1.00		2.00:1.00

Failure to comply with the various restrictive and affirmative covenants of the loan agreements could negatively affect CVR’s ability to incur additional indebtednessand/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, 2006 and December 31, 2007. As required by the debt agreements, CVR has entered into interest rate swap agreements (as described in Note 16) that are required to be held for the remainder of the stated term.

Long-term debt at December 31, 2007 consisted of the following future maturities (in thousands):


	Year Ending
	December 31,		Amount

First lien Tranche D term loans; principal payments		2008	$	4,874
of .25% of the principal balance due quarterly		2009		4,825
commencing April 2007, increasing to 23.5% of the		2010		4,777
principal balance due quarterly commencing April 2013,		2011		4,730
with a final payment of the aggregate remaining unpaid		2012		4,682
principal balance due December 2013		Thereafter		465,314

			$	489,202

Commencing with fiscal year 2007, CVR shall prepay the loans in an aggregate amount equal to 75% of Consolidated Excess Cash Flow (as defined in the credit and guaranty agreement, which includes a formulaic calculation consisting of many financial statement items, starting with consolidated Earnings Before Interest Taxes Depreciation and Amortization) less 100% of voluntary prepayments made during that fiscal year. Commencing with fiscal year 2008, the aggregate amount changes to 50% of Consolidated Excess Cash Flow provided the total leverage ratio is less than 1:50:1:00 or 25% of Consolidated Excess Cash Flow provided the total leverage ratio is less than 1:00:1:00.

At December 31, 2007, Successor had $5.8 million in letters of credit outstanding to collateralize its environmental obligations, $30.6 million in letters of credit outstanding to secure transportation services for crude oil, and $3.0 million in support of surety bonds in place to support state and federal

F-42

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

excise tax for refined fuels. These letters of credit were outstanding against the December 28, 2006 Revolving Loan Facility. The fee for the revolving letters of credit is 3.00%.

The Revolving Loan Facility has a current expiration date of December 28, 2012. The Funded Facility has a current expiration date of December 28, 2010.

As a result of the flood and crude oil discharge, the Company’s subsidiaries entered into three new credit facilities in August 2007. Coffeyville Resources, LLC entered into a $25 million senior secured term loan (the $25 million secured facility). The facility was secured by the same collateral that secures the Company’s existing Credit Facility. Interest was payable in cash, at the Company’s option, at the base rate plus 1.00% or at the reserve adjusted Eurodollar rate plus 2.00%. Coffeyville Resources, LLC also entered into a $25 million senior unsecured term loan (the $25 million unsecured facility). Interest was payable in cash, at the Company’s option, at the base rate plus 1.00% or at the reserve adjusted Eurodollar rate plus 2.00%. A subsidiary of Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., entered into a $75 million senior unsecured term loan (the $75 million unsecured facility). Drawings could be made from time to time in amounts of at least $5 million. Interest accrued, at the Company’s option, at the base rate plus 1.50% or at the reserve adjusted Eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding.

All indebtedness outstanding under the $25 million secured facility and the $25 million unsecured facility was repaid in October 2007 with the proceeds of the Company’s initial public offering, and all three facilities were terminated at that time.


(13)	Pro Forma Earnings Per Share

On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of its common stock. Also, in connection with the initial public offering, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of the subsidiaries of CALLC and CALLC II and all of its refinery and fertilizer assets. This reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholder, in conjunction with the merger of two newly formed direct subsidiaries of CVR. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding any non-vested shares issued. See Note 1, “Organization and History of Company”.

The computation of basic and diluted earnings per share for the years ended December 31, 2006 and December 31, 2007 are calculated on a pro forma basis assuming the capital structure in place after the completion of the offering was in place for the entire year for both 2006 and 2007.

F-43

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Pro forma earnings (loss) per share for the years ended December 31, 2006 and December 31, 2007 is calculated as noted below. For the year ended December 31, 2007, 17,500 non-vested common shares and 18,900 of common stock options have been excluded from the calculation of pro-forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive:


	December 31
	2006		2007
	(unaudited)		(unaudited)
			(As restated)(†)
	(in thousands)

Net income (loss)	$	191,571	$	(67,618	)
Pro forma weighted average shares outstanding:
Original CVR common shares		100		100
Effect of 628,667.20 to 1 stock split		62,866,620		62,866,620
Issuance of common shares to management in exchange for subsidiary shares		247,471		247,471
Issuance of common shares to employees		27,100		27,100
Issuance of common shares in the initial public offering		23,000,000		23,000,000

Basic weighted average shares outstanding		86,141,291		86,141,291
Dilutive securities — issuance of nonvested common shares to board of directors		17,500		—

Diluted weighted average shares outstanding		86,158,791		86,141,291

Pro forma basic earnings (loss) per share	$	2.22	$	(0.78	)
Pro forma dilutive earnings (loss) per share	$	2.22	$	(0.78	)


(†)		See Note 2 to consolidated financial statements.


(14)	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 $662,000, $447,000, $1,375,000, and $1,513,000 for the 174 days ended June 23, 2005, the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.

F-44

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(15)	Commitments and Contingent Liabilities

The minimum required payments for CVR’s lease agreements and unconditional purchase obligations are as follows (in thousands):


	Operating		Unconditional
Year Ending December 31,	Leases		Purchase Obligations

2008		4,207		25,235
2009		3,271		25,249
2010		1,679		52,781
2011		947		50,958
2012		195		48,352
Thereafter		10		366,363

	$	10,309	$	568,938

CVR leases various equipment and real properties under long-term operating leases. For the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, lease expense totaled approximately $1,755,000, $1,737,000, $3,822,000, and $3,854,000, 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 was paid in full in 2007. At December 31, 2006, approximately $1,615,000 was included in accounts payable for this agreement. Royalty fee expense reflected in direct operating expenses (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 was $1,042,000, $915,000, $2,135,000, and $1,035,000, respectively.

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, 2007, the remaining obligations of CRNF totaled $19.6 million through December 31, 2019. Total minimum annual committed contractual payments under the agreement will be $1.7 million.

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 product sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 totaled approximately $2,603,000, $4,372,000, $8,751,000, and $7,214,000, respectively.

During 1997, Farmland (subsequently assigned to CRP) entered into an Agreement of Capacity Lease and Operating Agreement with Williams Pipe Line Company (subsequently assigned to Magellan Pipe Line Company, L.P. (Magellan)) pursuant to which CRP leases pipeline capacity in certain pipelines

F-45

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

between Coffeyville, Kansas and Caney, Kansas and between Coffeyville, Kansas and Independence, Kansas. Pursuant to this agreement, CRP was obligated to pay a fixed monthly charge to Magellan for annual leased capacity of 6,300,000 barrels until the expiration of the agreement on April 30, 2007. Lease expense associated with this agreement and included in cost of product sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 totaled approximately $233,000, $194,000, $504,000, and $116,000, respectively.

During 2005, CRRM amended a Pipeline Capacity Lease Agreement withMid-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 product sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $156,000, $208,000, $800,000, and $800,000, 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 product sold (exclusive of depreciation and amortization) for the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $173,000, $1,613,000, and $1,400,000, respectively.

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. Lease expense associated with this contract agreement and included in cost of product sold (exclusive of depreciation and amortization) for the year ended December 31, 2007 totaled approximately $444,000.

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. Lease expense associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled approximately $4,609,000 and $6,980,000, respectively.

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CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

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. During 2007, CRRM entered into an Amended and Restated Terminalling Agreement with Plains that replaced the 2004 agreement. Pursuant to the Amended and Restated Terminalling Agreement, CRRM is obligated to pay fees on a minimum throughput volume commitment of 29,200,000 barrels per year. Fees are 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 product sold (exclusive of depreciation and amortization) for the 174-day period ended June 23, 2005, the 233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $812,000, $1,251,000, $2,406,000, and $2,396,000, respectively. The original term of the Amended and Restated Terminalling Agreement expires December 31, 2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement. Concurrently with the above-described Amended and Restated Terminalling Agreement, CRRM entered into a separate Terminalling Agreement with Plains whereby CRRM has obtained additional exclusive storage rights for working storage and terminalling services at several Plains tanks in Cushing, Oklahoma. CRRM is obligated to pay Plains fees based on the storage capacity of the tanks involved, and such fees are subject to change annually based on changes in the Producer Price Index (PPI-FG and PPI-NG). The term of the Terminalling Agreement is split up into two periods based on the tanks at issue, with the term for half of the tanks commencing once they are placed in service (but no later than January 1, 2008), and the term for the remaining half of the tanks commencing October 1, 2008. The original term of the Terminalling Agreement for both sets of tanks expires December 31, 2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement.

During 2005 CRNF entered into the Amended and RestatedOn-Site Product Supply Agreement with The Linde Group. Pursuant to the agreement, which expires in 2020, CRNF is required to take as available and pay approximately $300,000 per month, which amount is subject to annual inflation adjustments, for the supply of oxygen and nitrogen to the fertilizer operation. Expenses associated with this agreement, included in direct operating expenses (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007, totaled approximately $3,521,000 and $3,136,000, respectively.

During 2006, CRRM entered into a Lease Storage Agreement with TEPPCO Crude Pipeline, L.P. (TEPPCO) whereby CRRM leases 400,000 barrels of shell capacity at TEPPCO’s Cushing tank farm in Cushing, Oklahoma. In September 2006, CRRM exercised its option to increase the shell capacity leased at the facility subject to this agreement from 400,000 barrels to 550,000 barrels. Pursuant to the agreement, CRRM is obligated to pay a monthly per barrel fee regardless of the number of barrels of crude oil actually stored at the leased facilities. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the year ended December 31, 2007 totaled approximately $1,110,000.

During 2006, CRCT entered into a Pipeline Lease Agreement with Magellan whereby CRCT leases sixty-two miles of eight inch pipeline extending from Humboldt, Kansas to CRCT’s facilities located in Broome, Kansas. Pursuant to the lease agreement, CRCT agrees to operate and maintain the leased pipeline and agrees to pay Magellan a fixed annual rental in advance. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled approximately $76,000 and

F-47

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

$183,000, respectively. Pursuant to an amendment entered into in 2007, the lease agreement expires on July 31, 2009 with, at the Company’s option, up to two one year extensions.

During 2006, CRRM entered into a Transfer Agreement with Magellan pursuant to which CRRM obtained the right to capacity in a pipeline operated by Magellan between Coffeyville, Kansas and El Dorado, Kansas. Pursuant to the agreement, CRRM is obligated to pay a fixed monthly charge for the right to transfer up to 1,000,000 barrels per year through the pipeline. The initial term of the agreement expires on July 14, 2009; however the agreement contains two successive one year additional terms unless CRRM or Magellan provides termination notice as required in the agreement. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the year ended December 31, 2007 totaled approximately $79,000.

During 2007, CRRM executed a Petroleum Transportation Service Agreement with TransCanada Keystone Pipeline, LP (TransCanada). TransCanada is proposing to construct, own and operate a pipeline system and a related extension and expansion of the capacity that would terminate near Cushing, Oklahoma. TransCanada has agreed to transport a contracted volume amount of at least 25,000 barrels per day with a Cushing Delivery Point as the contract point of delivery. The contract term is a 10 year period which will commence upon the completion of the pipeline system. The expected date of commencement is March 2010 with termination of the transportation agreement estimated to be February 2020. The Company will pay a fixed and variable toll rate beginning during the month of commencement.

CRNF entered into a sales agreement with Cominco Fertilizer Partnership on November 20, 2007 to purchase equipment and materials which comprise a nitric acid plant. CRNF’s obligation related to the execution of the agreement in 2007 for the purchase of the assets was $3,500,000. As of December 31, 2007, $250,000 had been paid with $3,250,000 remaining as an accrued current obligation. Additionally, $3,000,000 was accrued related to the obligation to dismantle the unit. These amounts incurred are included inconstruction-in-progress at December 31, 2007. The total unpaid obligation at December 31, 2007 of $6,250,000 is included in other current liabilities on the Consolidated Balance Sheet.

As a result of the adoption of FIN 47 in 2005, CVR recorded a net asset retirement obligation of $636,000 which was included in other current liabilities at December 31, 2006 and December 31, 2007.

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.

Crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. As a result of the crude oil discharge, two putative class action lawsuits (one federal and one state) were filed seeking unspecified damages with class certification under applicable law for all residents, domiciliaries and property owners of Coffeyville, Kansas who were impacted by the oil release.

The Company filed a motion to dismiss the federal suit for lack of subject matter jurisdiction. On November 6, 2007, the judge in the federal class action lawsuit granted the Company’s motion to dismiss for lack of subject matter jurisdiction and no appeal was taken.

F-48

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

The District Court of Montgomery County, Kansas conducted an evidentiary hearing on the issue of class certification on October 24 and 25, 2007 and ruled against the class certification leaving only the original two plaintiffs. To date no other lawsuits have been filed as a result of flood related damages.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the Consent Order) with the EPA on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the Company’s refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The Company is currently remediating the crude oil discharge and expects its remedial actions to continue until May 2008.

The Company engaged experts to assess and test the areas affected by the crude oil spill. The Company commenced a program on July 19, 2007 to purchase approximately 330 homes and other commercial properties in connection with the flood and the crude oil release. The costs recorded as of December 31, 2007 related to the obligation of the homes being purchased, were approximately $13.1 million, and are included in “Net Costs Associated With Flood” in the accompanying consolidated statement of operations. Costs recorded related to personal property claims were approximately $1.7 million as of December 31, 2007. The costs recorded related to estimated commercial property to be purchased and associated claims were approximately $3.6 million as of December 31, 2007. The total amount of gross costs recorded for the twelve months ended December 31, 2007 related to the residential and commercial purchase and property claims program were approximately $18.4 million.

As of December 31, 2007, the total gross costs recorded for obligations other than the purchase of homes, commercial properties, and related personal property claims, approximated $26.5 million. The Company has recorded as of December 31, 2007, total costs (net of anticipated insurance recoveries recorded of $21.4 million) associated with remediation and third party property damage claims resolution of approximately $23.5 million. The Company has not estimated or accrued for, because management does not believe it is probable that there will be any, potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from class action lawsuits related to the flood.

It is difficult to estimate the ultimate cost of environmental remediation resulting from the crude oil discharge or the cost of third party property damage that the Company will ultimately be required to pay. The costs and damages that the Company will ultimately pay may be greater than the amounts described and projected above. Such excess costs and damages could be material to the consolidated financial statements.

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation, property damage claims, cleanup, resolution of class action lawsuits, and other claims brought by regulatory authorities. Although the Company believes that it will recover substantial sums under its environmental and liability insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements. The Company has received $10 million of insurance proceeds under its environmental insurance policy as of December 31, 2007.

As a result of the 2007 flood the refinery was not able to meet the annual average sulfur standard required in its “hardship waiver.” Management had provided timely notice to the EPA that the Company would not be able to meet the waiver requirement for 2007. Ordinarily, a refiner would purchase sulfur credits to meet the standard requirement. However, the Company’s “hardship waiver”

F-49

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

does not allow sulfur credits to be used in 2006 and 2007. The Company has been working with the EPA to resolve the matter. In anticipation of settlement, the refinery purchased $3.6 million worth of sulfur credits that would equal the amount of sulfur by which the Company exceeded the limit imposed by the “hardship waiver.” The Company will either use the credits by applying them towards its gasoline pool account or it will permanently retire the credits as part of the settlement. Because of the extraordinary nature of the 2007 flood, management does not anticipate the imposition of fines or penalties to resolve this matter.

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 ownsand/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.

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, CRNF 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, 2006 and December 31, 2007, environmental accruals of $7,223,000 and $7,646,000, 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 $1,828,000 and $2,802,000, respectively, included in other current liabilities. The Successor accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the EPA and are discounted at the appropriate risk free rates at December 31, 2006 and December 31, 2007, respectively. The accruals include estimated closure and post-closure costs of $1,857,000 and $1,549,000 for two landfills at December 31, 2006 and December 31, 2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):


Year Ending December 31,	Amount

2008	$	2,802
2009		687
2010		1,556
2011		313
2012		313
Thereafter		3,282

Undiscounted total		8,953
Less amounts representing interest at 3.90%		1,307

Accrued environmental liabilities at December 31, 2007	$	7,646

F-50

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

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 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 $27 million in 2005, $79 million in 2006, and $17 million in 2007, and based on information currently available, CVR anticipates spending approximately $29 million in 2008, $11 million in 2009, and $6 million in 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 the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 capital expenditures were approximately $6,066,000, $20,165,000, $144,794,000, and $122,341,000, 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.


(16)	Derivative Financial Instruments

Gain (loss) on derivatives consisted of the following (in thousands):


	Predecessor			Successor
	174 Days			233 Days			Year
	Ended June 23,			Ended December 31,			Ended December 31,
	2005			2005			2006			2007
Realized loss on swap agreements	$	—		$	(59,301	)	$	(46,769	)	$	(157,239	)
Unrealized gain (loss) on swap agreements		—			(235,852	)		126,771			(103,212	)
Loss on termination of swap		—			(25,000	)		—			—
Realized gain (loss) on other agreements		(7,665	)		(1,868	)		8,361			(15,346	)
Unrealized gain (loss) on other agreements		—			(1,696	)		2,412			(1,348	)
Realized gain (loss) on interest rate swap agreements		—			(104	)		4,398			4,115
Unrealized gain (loss) on interest rate swap agreements		—			7,759			(680	)		(8,948	)

Total gain (loss) on derivatives	$	(7,665	)	$	(316,062	)	$	94,493		$	(281,978	)

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 Company may enter into various derivative transactions. In addition, the Successor, as further described below, entered into certain

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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.

CVR has adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activitieswhich 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, 2007, CVR’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 17). The swap agreements were originally executed on June 16, 2005 in conjunction with the 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, 2007 the notional open amounts under the swap agreements were 42,309,750 barrels of crude oil; 888,504,750 gallons of unleaded gasoline and 888,504,750 gallons of heating oil. These positions resulted in unrealized gains (losses) for the233-day period ended December 31, 2005 and the years ended December 31, 2006 and December 31, 2007 of $(235,852,000), $126,771,000 and $(103,212,000), respectively, 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 $(59,301,000), $(46,769,000) and $(157,239,000) in realized (losses) on these swap agreements for the 233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.

Successor entered certain crude oil, heating oil, and gasoline option agreements with a related party (see Notes 1 and 17) 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.

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 $(7,665,000), $(3,564,000), $10,773,000, and $(16,694,000) for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, the years ended December 31, 2006, and December 31, 2007, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.

At December 31, 2007, CVR held derivative contracts known as interest rate swap agreements that converted Successor’s floating-rate bank debt (see Note 12) into 4.195% fixed-rate debt on a notional amount of $375,000,000. Half of the agreements are held with a related party (as described

F-52

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

in Note 17), 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, 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 (losses) on derivatives and quarterly settlements were $7,655,000, $3,718,000 and $(4,833,000) for the233-day period ended December 31, 2005 and the years ended December 31, 2006 and December 31, 2007, respectively.


(17)	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 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. An amount totaling approximately $1,000,000 relating to the agreement were expensed in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the 174 days ended June 23, 2005.

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 CVR.

CVR paid companies related to GS and Kelso each equal amounts totaling $6.0 million for transaction fees related to the Acquisition, as well as an additional $0.7 million paid to GS for reimbursed expenses related to the Acquisition. These expenditures were included in the cost of the Acquisition referred to in Note 1.

An affiliate of GS is one of the lenders in conjunction with the financing of the Acquisition. The Company 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 other financial costs and paid letter of credit fees of approximately $155,000 recorded in selling, general, and administrative expenses (exclusive of depreciation and amortization), to this affiliate of GS. Additionally, a fee in the amount of $125,000 was paid to this affiliate of GS for assistance with modification of the credit facility in June 2006.

An affiliate of GS is one of the lenders in conjunction with the refinancing that occurred on December 28, 2006. The Company paid this affiliate of GS a $8,063,000 million fee and expense reimbursements of $78,000 included in deferred financing costs.

On June 24, 2005, CALLC entered into management services agreements with each of GS and Kelso pursuant to which GS and Kelso agreed to provide CALLC with managerial and advisory services. In consideration for these services, an annual fee of $1.0 million each was paid to GS and

F-53

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Kelso, plus reimbursement for any out-of-pocket expenses. The agreements had a term ending on the date GS and Kelso ceased to own any interests in CALLC. Relating to the agreements, $1,310,000, $2,316,000 and $1,704,000 were expensed in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively. The agreements terminated upon consummation of CVR’s initial public offering on October 26, 2007. The Company paid a one-time fee of $5 million to each of GS and Kelso by reason of such termination on October 26, 2007.

CALLC 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 (as described in note 1) 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 16). Amounts totaling $(297,011,000), $80,002,000, and $(260,451,000) were reflected in gain (loss) on derivatives related to these swap agreements for the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively. In addition, the consolidated balance sheet at December 31, 2006 and December 31, 2007 includes liabilities of $36,895,000 and $262,415,000 included in current payable to swap counterparty and $72,806,000 and $88,230,000 included in long-term payable to swap counterparty, respectively.

On June 26, 2007, the Company entered into a letter agreement with the subsidiary of GS to defer a $45.0 million payment owed on July 8, 2007 to the GS subsidiary for the period ended September 30, 2007 until August 7, 2007. Interest accrued on the deferred amount of $45.0 million at the rate of LIBOR plus 3.25%.

As a result of the flood and the related temporary cessation of business operations, the Company entered into a subsequent letter agreement on July 11, 2007 in which the GS subsidiary agreed to defer an additional $43.7 million of the balance owed for the period ending June 30, 2007. This deferral was entered into on the conditions that each of GS and Kelso each agreed to guarantee one half of the payment and that interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

On July 26, 2007, the Company entered into a letter agreement in which the GS subsidiary agreed to defer to September 7, 2007 both the $45.0 million payment due August 7, 2007 along with accrued interest and the $43.7 million payment due July 25, 2007 with the related accrued interest. These payments were deferred on the conditions that GS and Kelso each agreed to guarantee one half of the payments. Additionally, interest accrues on the amount from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

On August 23, 2007, the Company entered into an additional letter agreement in which the GS subsidiary agreed to further defer both deferred payment amounts and the related accrued interest with payment being due on January 31, 2008. Additionally, it was further agreed that the $35 million payment to settle hedged volumes through August 15, 2007 would be deferred with payment being due on January 31, 2008. Interest accrues on all deferral amounts through the payment due date at LIBOR plus 1.50%. GS and Kelso have each agreed to guarantee one half of all payment deferrals. The GS Subsidiary further agreed to defer these payment amounts to August 31, 2008 if the Company closed an initial public offering prior to January 31, 2008. Due to the consummation of the initial public offering on October 26, 2007, these payment amounts are now deferred until August 31, 2008; however, the company is required to use 37.5% of its consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferral amounts.

F-54

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

These deferred payment amounts are included in the consolidated balance sheet at December 31, 2007 in current payable to swap counterparty. Interest relating to the deferred payment amounts reflected in interest expense and other financial costs for the year ended December 31, 2007 was $3,625,000. $3,625,000 is also included in other current liabilities at December 31, 2007.

On June 30, 2005, CVR entered into three interest-rate swap agreements with the same subsidiary of GS (as described in Note 16). Amounts totaling $3,826,000, $1,858,000, and $(2,405,000) were recognized related to these swap agreements for the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively, and are reflected in gain (loss) on derivatives. In addition, the consolidated balance sheet at December 31, 2006 and December 31, 2007 includes $1,534,000 and $0 in prepaid expenses and other current assets, $2,015,000 and $0 in other long-term assets, $0 and $371,000 in other current liabilities and $0 and $557,000 in other long-term liabilities related to the same agreements, respectively.

Effective December 30, 2005, CVR entered into a crude oil supply agreement with a subsidiary of GS (Supplier). Both parties will negotiate the cost of each barrel of crude oil to be purchased from a third party. CVR 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 was to December 31, 2006. CVR 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. On December 31, 2007, CVR and supplier entered into an amended and restated crude oil supply agreement. The terms of the agreement remained substantially the same. $1,623,000 and $360,000 were recorded on the consolidated balance sheet at December 31, 2006 and December 31, 2007, respectively, in prepaid expenses and other current assets for prepayment of crude oil. In addition, $31,751,000 and $43,773,000 were recorded in inventory and $13,459,000 and $42,666,000 were recorded in accounts payable at December 31, 2006 and December 31, 2007, respectively. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciated and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled $1,591,120,000 and $1,476,811,000 respectively. Interest expense associated with this agreement for the years ended December 31, 2006 and December 31, 2007 totaled $0 and $(376,000), respectively.

The Company had a note receivable with an executive member of management. During the period ended December 31, 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 $18,000. The total amount was charged to compensation expense.

On August 23, 2007, the Company entered into three new credit facilities, consisting of a $25 million secured facility, a $25 million unsecured facility and a $75 million unsecured facility. A subsidiary of GS was the sole lead arranger and sole bookrunner for each of these new credit facilities. These credit facilities and their arrangements are more fully described in Note 12, “Long-Term Debt”. The Company paid the subsidiary of GS a $1.3 million fee included in deferred financing costs. For the year ended December 31, 2007, interest expenses relating to these agreements were $867,000. The secured and unsecured facilities were paid in full on October 26, 2007 with proceeds from CVR’s initial public offering, see Note 1, “Organization and History of Company”, and both facilities terminated. Additionally, in connection with the consummation of the initial public offering, the $75 million unsecured facility also terminated.

F-55

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

As a result of the refinery turnaround in early 2007, CVR needed to delay the processing of quantities of crude oil that it purchased from various small independent producers. In order to facilitate this anticipated delay, CVR entered into a purchase, storage and sale agreement for gathered crude oil, dated March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant to the terms of the agreement, J. Aron agreed to purchase gathered crude oil from CVR, store the gathered crude oil and sell CVR the gathered crude oil on a forward basis. As of December 31, 2007, there were no longer any open commitments with regard to the agreement. Interest expense associated with this agreement included in interest expense and other financing costs was $196,000.

Goldman, Sachs & Co. was the lead underwriter of CVR’s initial public offering in October 2007. As lead underwriter, they were paid a customary underwriting discount of approximately $14.7 million, which includes $0.7 million of expense reimbursement.

On October 24, 2007, CVR paid a cash dividend, to its shareholders, including approximately $5.23 million that was ultimately distributed from CALLC II (Goldman Sachs Funds) and approximately $5.15 million distributed from CALLC to the Kelso Funds. Management collectively received approximately $0.13 million.


(18)	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 SFAS No. 131,Disclosures About Segments of an Enterprise and Related Information. All operations of the segments are located in the United States.

CVR changed its corporate selling, general and administrative allocation method to the operating segments in 2007. The effect of the change on operating income for174-day period ended June 23, 2005, the233-day period ended December 31, 2005 and the year ended December 31, 2006 would have been a decrease of $1.0 million, $1.4 million and $6.0 million, respectively, to the petroleum segment, an increase of $1.2 million, $1.4 million and $6.0 million, respectively, to the nitrogen fertilizer segment and a decrease of $0.2 million, $0.0 million and $0.0 million, respectively, to the other segment.

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 product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment through October 24, 2007.) After October 24, 2007, intercompany sales are recorded according to the interconnect agreement (see Note 1). The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in Petroleum net sales were $2,445,000, $2,782,000, $5,340,000, and $5,195,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.

Nitrogen Fertilizer

F-56

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.

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.


				Successor
	Predecessor
	174 Days			233 Days			Year
	Ended			Ended			Ended
	June 23,			December 31,			December 31,
	2005			2005			2006
	(in thousands)
Net sales
Petroleum	$	903,803		$	1,363,390		$	2,880,442
Nitrogen Fertilizer		79,348			93,652			162,465
Other		—			—			—
Intersegment elimination		(2,445	)		(2,782	)		(5,340	)

Total	$	980,706		$	1,454,260		$	3,037,567

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	761,719		$	1,156,208		$	2,422,718
Nitrogen Fertilizer		9,126			14,504			25,898
Other		—			—			—
Intersegment elimination		(2,778	)		(2,575	)		(5,242	)

Total	$	768,067		$	1,168,137		$	2,443,374

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	52,611		$	56,159		$	135,297
Nitrogen Fertilizer	$	28,303			29,154			63,683
Other		—			—			—

Total	$	80,914		$	85,313		$	198,980

Depreciation and amortization
Petroleum	$	771		$	15,567		$	33,017
Nitrogen Fertilizer		316			8,361			17,126
Other		41			26			862

Total	$	1,128		$	23,954		$	51,005

Operating income (loss)
Petroleum	$	76,654		$	123,045		$	245,578
Nitrogen Fertilizer		35,268			35,731			36,842
Other		333			(240	)		(812	)

Total	$	112,255		$	158,536		$	281,608

F-57

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


			Successor
	Predecessor
	174 Days		233 Days		Year
	Ended		Ended		Ended
	June 23,		December 31,		December 31,
	2005		2005		2006
	(in thousands)
Capital expenditures
Petroleum	$	10,790	$	42,108	$	223,552
Nitrogen fertilizer		1,435		2,017		13,258
Other		32		1,047		3,415

Total	$	12,257	$	45,172	$	240,225

Total assets
Petroleum					$	907,315
Nitrogen Fertilizer						417,657
Other						124,508

Total					$	1,449,480

Goodwill
Petroleum					$	42,806
Nitrogen Fertilizer						40,969
Other						—

Total					$	83,775


	Successor
	Year Ended December 31, 2007
	Previously
	Reported			Adjustment		As Restated(†)
	(in thousands)
Net sales
Petroleum	$	2,806,205		$	—	$	2,806,205
Nitrogen Fertilizer		165,855			—		165,855
Other		—			—		—
Intersegment elimination		(5,195	)		—		(5,195	)

Total	$	2,966,865		$	—	$	2,966,865

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	2,282,555		$	17,671	$	2,300,226
Nitrogen Fertilizer		13,042			—		13,042
Other		—			—		—
Intersegment elimination		(4,528	)		—		(4,528	)

Total	$	2,291,069		$	17,671	$	2,308,740

F-58

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


	Successor
	Year Ended December 31, 2007
	Previously
	Reported			Adjustment			As Restated(†)
	(in thousands)
Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	209,475		$	—		$	209,475
Nitrogen Fertilizer		66,663			—			66,663
Other		—			—			—

Total	$	276,138		$	—		$	276,138

Net costs associated with flood
Petroleum	$	36,669		$	—		$	36,669
Nitrogen Fertilizer		2,432			—			2,432
Other		2,422			—			2,422

Total	$	41,523		$	—		$	41,523

Depreciation and amortization
Petroleum	$	43,040		$	—		$	43,040
Nitrogen Fertilizer		16,819			—			16,819
Other		920			—			920

Total	$	60,779		$	—		$	60,779

Operating income (loss)
Petroleum	$	162,547		$	(17,671	)	$	144,876
Nitrogen Fertilizer		46,593			—			46,593
Other		(4,906	)		—			(4,906	)

Total	$	204,234		$	(17,671	)	$	186,563

Capital expenditures
Petroleum	$	261,562		$	—		$	261,562
Nitrogen Fertilizer		6,488			—			6,488
Other		543			—			543

Total	$	268,593		$	—		$	268,593

Total assets
Petroleum	$	1,271,712		$	5,412		$	1,277,124
Nitrogen Fertilizer		446,763			—			446,763
Other		137,593			6,876			144,469

Total	$	1,856,068		$	12,288		$	1,868,356

Goodwill
Petroleum	$	42,806		$	—		$	42,806
Nitrogen Fertilizer		40,969			—			40,969
Other		—			—			—

Total	$	83,775		$	—		$	83,775


(†)		See Note 2 to consolidated financial statements.

F-59

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(19)	Major Customers and Suppliers

Sales to major customers were as follows:


				Successor
	Predecessor
	174 Days			233 Days			Year			Year
	Ended			Ended			Ended			Ended
	June 23,			December 31,			December 31,			December 31,
	2005			2005			2006			2007
Petroleum
Customer A		17	%		16	%		2	%		3	%
Customer B		5	%		6	%		5	%		5	%
Customer C		17	%		15	%		15	%		12	%
Customer D		14	%		17	%		10	%		7	%
Customer E		11	%		11	%		10	%		9	%
Customer F		8	%		7	%		9	%		10	%

		72	%		72	%		51	%		46	%

Nitrogen Fertilizer
Customer G		16	%		10	%		5	%		3	%
Customer H		9	%		10	%		7	%		18	%

		25	%		20	%		12	%		21	%

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 17). Purchases contracted as a percentage of the total cost of product sold (exclusive of depreciation and amortization) for each of the periods were as follows:


				Successor
	Predecessor
	174 Days			233 Days			Year			Year
	Ended			Ended			Ended			Ended
	June 23,			December 31,			December 31,			December 31,
	2005			2005			2006			2007
										As restated(†)
Supplier A		82	%		73	%		—			—
Supplier B		—			—			67	%		63	%

		82	%		73	%		67	%		63	%


(†)		See Note 2 to consolidated financial statements.

The Nitrogen Fertilizer Segment maintains long-term contracts with one supplier. Purchases from this supplier as a percentage of direct operating expenses (exclusive of depreciation and amortization) were as follows:

Successor

Predecessor

174 Days

233 Days

Year

Ended

June 23,

December 31,

2005

2006

2007

Supplier

F-60

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(20)	Selected Quarterly Financial and Information (Unaudited)

Summarized quarterly financial data for the December 31, 2006 and 2007.


	Year Ended December 31, 2006
	Quarter
	First			Second			Third			Fourth
	(in thousands except share amounts)

Net sales	$	669,727		$	880,839		$	778,587		$	708,414
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		539,539			663,910			644,627			595,298
Direct operating expenses (exclusive of depreciation and amortization)		44,288			43,478			56,696			54,518
Selling, general and administrative (exclusive of depreciation and amortization)		8,493			11,976			12,327			29,804
Net costs associated with flood		—			—			—			—
Depreciation and amortization		12,004			12,018			12,788			14,195

Total operating costs and expenses		604,324			731,382			726,438			693,815

Operating income (loss)		65,403			149,457			52,149			14,599
Other income (expense):
Interest expense and other financing costs		(12,207	)		(10,129	)		(10,681	)		(10,863	)
Interest income		590			1,093			1,091			676
Gain (loss) on derivatives		(17,615	)		(108,847	)		171,209			49,746
Loss on extinguishment of debt		—			—			—			(23,360	)
Other income (expense)		58			(320	)		573			(1,211	)

Total other income (expense)		(29,174	)		(118,203	)		162,192			14,988

Income before income taxes and minority interest		36,229			31,254			214,341			29,587
Income tax expense (benefit)		14,106			11,620			85,302			8,812
Minority interest in (income) loss of subsidiaries		—			—			—			—

Net income	$	22,123		$	19,634		$	129,039		$	20,775

Unaudited Pro Forma Information (Note 13)
Net earnings per share
Basic	$	0.26		$	0.23		$	1.50		$	0.24
Diluted	$	0.26		$	0.23		$	1.50		$	0.24
Weighted average common shares outstanding
Basic		86,141,291			86,141,291			86,141,291			86,141,291
Diluted		86,158,791			86,158,791			86,158,791			86,158,791

F-61

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)

Quarterly Financial Information (Unaudited)


	Year Ended December 31, 2007
	Quarter
	First			Second
	(in thousands except share amounts)

Net sales	$	390,483		$	843,413
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		303,670			569,623
Direct operating expenses (exclusive of depreciation and amortization)		113,412			60,955
Selling, general and administrative (exclusive of depreciation and amortization)		13,150			14,937
Net costs associated with flood		—			2,139
Depreciation and amortization		14,235			17,957

Total operating costs and expenses		444,467			665,611

Operating income (loss)		(53,984	)		177,802
Other income (expense):
Interest expense and other financing costs		(11,857	)		(15,763	)
Interest income		452			161
Gain (loss) on derivatives		(136,959	)		(155,485	)
Loss on extinguishment of debt		—			—
Other income (expense)		1			101

Total other income (expense)		(148,363	)		(170,986	)

Income (loss) before income taxes and minority interest		(202,347	)		6,816
Income tax expense (benefit)		(47,298	)		(93,669	)
Minority interest in (income) loss of subsidiaries		676			(419	)

Net income (loss)	$	(154,373	)	$	100,066

Unaudited Pro Forma Information (Note 13)
Net earnings (loss) per share
Basic	$	(1.79	)	$	1.16
Diluted	$	(1.79	)	$	1.16
Weighted average common shares outstanding
Basic		86,141,291			86,141,291
Diluted		86,141,291			86,158,791

F-62

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


	Year Ended December 31, 2007
	Quarter
	Third									Fourth
	Previously						As			Previously						As
	Reported			Adjustment			Restated(†)			Reported			Adjustment			Restated(†)
	(in thousands except share amounts)

Net sales	$	585,978		$	—		$	585,978		$	1,146,991		$	—		$	1,146,991
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		446,170			7,072			453,242			971,606			10,599			982,205
Direct operating expenses (exclusive of depreciation and amortization)		44,440			—			44,440			57,331			—			57,331
Selling, general and administrative (exclusive of depreciation and amortization)		14,035			—			14,035			51,000			—			51,000
Net costs associated with flood		32,192			—			32,192			7,192			—			7,192
Depreciation and amortization		10,481			—			10,481			18,106			—			18,106

Total operating costs and expenses		547,318			7,072			554,390			1,105,235			10,599			1,115,834

Operating income (loss)		38,660			(7,072	)		31,588			41,756			(10,599	)		31,157
Other income (expense):
Interest expense and other financing costs		(18,340	)		—			(18,340	)		(15,166	)		—			(15,166	)
Interest income		151			—			151			336			—			336
Gain (loss) on derivatives		40,532			—			40,532			(30,066	)		—			(30,066	)
Loss on extinguishment of debt		—			—			—			(1,258	)		—			(1,258	)
Other income (expense)		53			—			53			201			—			201

Total other income (expense)		22,396			—			22,396			(45,953	)		—			(45,953	)

Income (loss) before income taxes and minority interest		61,056			(7,072	)		53,984			(4,197	)		(10,599	)		(14,796	)
Income tax expense (benefit)		47,610			(4,879	)		42,731			11,718			(1,997	)		9,721
Minority interest in (income) loss of subsidiaries		(47	)		—			(47	)		—			—			—

Net income (loss)	$	13,399		$	(2,193	)	$	11,206		$	(15,915	)	$	(8,602	)	$	(24,517	)

Unaudited Pro Forma Information (Note 13)
Net earnings (loss) per share
Basic	$	0.16		$	(0.03	)	$	0.13		$	(0.18	)	$	(0.10	)	$	(0.28	)
Diluted	$	0.16		$	(0.03	)	$	0.13		$	(0.18	)	$	(0.10	)	$	(0.28	)
Weighted average common shares outstanding
Basic		86,141,291						86,141,291			86,141,291						86,141,291
Diluted		86,158,791						86,158,791			86,141,291						86,141,291


(†)		See Note 2 to consolidated financial statements.

F-63

CVR ENERGY, INC. AND SUBSIDIARIES

Notes to Consolidated Financial Statements — (Continued)


(21)	Subsequent Events (unaudited)

On June 13, 2008, the Company announced that the managing general partner of the Partnership had decided to postpone indefinitely the Partnership’s initial public offering. The Partnership has notified the SEC that it intends to withdraw the registration statement it filed in February 2008.

On July 10, 2008, the Company filed two lawsuits in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the 2007 flood and crude oil discharge. See Note 10, “Flood” for additional information.

F-64

CVR ENERGY, INC. AND SUBSIDIARIES

~~Condensed Consolidated Balance Sheets~~CONDENSED CONSOLIDATED BALANCE SHEETS

March 31,
December 31,

2008

2007

(unaudited)
(in thousands of dollars)

ASSETS
Current assets:
Cash and cash equivalents $ 25,179 $ 30,509
Accounts receivable, net of allowance for doubtful accounts of $597 and $391, respectively 117,033 86,546
Inventories 288,415 254,655
Prepaid expenses and other current assets 13,071 14,186
Insurance receivable 74,275 73,860
Income tax receivable 26,166 31,367
Deferred income taxes 78,325 79,047

Total current assets 622,464 570,170
Property, plant, and equipment, net of accumulated depreciation 1,192,542 1,192,174
Intangible assets, net 450 473
Goodwill 83,775 83,775
Deferred financing costs, net 7,028 7,515
Insurance receivable 11,400 11,400
Other long-term assets 5,932 2,849

Total assets $ 1,923,591 $ 1,868,356

LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt $ 4,862 $ 4,874
Note payable and capital lease obligations 11,209 11,640
Payable to swap counterparty 294,984 262,415
Accounts payable 170,194 182,225
Personnel accruals 34,954 36,659
Accrued taxes other than income taxes 22,073 14,732
Deferred revenue 29,784 13,161
Other current liabilities 32,953 33,820

Total current liabilities 601,013 559,526
Long-term liabilities:
Long-term debt, less current portion 483,117 484,328
Accrued environmental liabilities 4,924 4,844
Deferred income taxes 287,974 286,986
Other long-term liabilities 4,447 1,122
Payable to swap counterparty 76,411 88,230

Total long-term liabilities 856,873 865,510
Commitments and contingencies
Minority interest in subsidiaries 10,600 10,600
Stockholders’ equity
Common stock $0.01 par value per share; 350,000,000 shares authorized; 86,141,291 shares issued and outstanding 861 861
Additionalpaid-in-capital
458,523 458,359
Retained earning (deficit) (4,279 ) (26,500 )

Total stockholders’ equity 455,105 432,720

Total liabilities and stockholders’ equity $ 1,923,591 $ 1,868,356


	June 30,			December 31,
	2008			2007
	(Unaudited)
	(In thousands of dollars)

ASSETS
Current assets:
Cash and cash equivalents	$	20,616		$	30,509
Accounts receivable, net of allowance for doubtful accounts of $4,328 and $391, respectively		137,136			86,546
Inventories		328,738			254,655
Prepaid expenses and other current assets		9,886			14,186
Insurance receivable		22,251			73,860
Income tax receivable		35,671			31,367
Deferred income taxes		79,996			79,047

Total current assets		634,294			570,170
Property, plant, and equipment, net of accumulated depreciation		1,189,921			1,192,174
Intangible assets, net		426			473
Goodwill		83,775			83,775
Deferred financing costs, net		6,537			7,515
Insurance receivable		58,663	��		11,400
Other long-term assets		5,566			2,849

Total assets	$	1,979,182		$	1,868,356


LIABILITIES AND EQUITY
Current liabilities:
Current portion of long-term debt	$	4,849		$	4,874
Revolving debt		21,500			—
Note payable and capital lease obligations		14,683			11,640
Payable to swap counterparty		371,583			262,415
Accounts payable		163,373			182,225
Personnel accruals		36,071			36,659
Accrued taxes other than income taxes		18,710			14,732
Deferred revenue		6,995			13,161
Other current liabilities		32,014			33,820

Total current liabilities		669,778			559,526
Long-term liabilities:
Long-term debt, less current portion		481,910			484,328
Accrued environmental liabilities		4,621			4,844
Deferred income taxes		285,922			286,986
Other long-term liabilities		1,566			1,122
Payable to swap counterparty		46,723			88,230

Total long-term liabilities		820,742			865,510
Commitments and contingencies
Minority interest in subsidiaries		10,600			10,600
Stockholders’ equity
Common stock $0.01 par value per share; 350,000,000 shares authorized; 86,141,291 shares issued and outstanding		861			861
Additionalpaid-in-capital		450,492			458,359
Retained earning (deficit)		26,709			(26,500	)

Total stockholders’ equity		478,062			432,720

Total liabilities and stockholders’ equity	$	1,979,182		$	1,868,356

See accompanying notes to the condensed consolidated financial statements.

F-65

CVR ENERGY, INC. AND SUBSIDIARIES

~~Condensed Consolidated Statements of Operations~~CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

Three Months Ended

March 31,

2008

2007

(unaudited)
(in thousands except share amounts)

Net sales $ 1,223,003 $ 390,483
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization) 1,036,194 303,670
Direct operating expenses (exclusive of depreciation and amortization) 60,556 113,412
Selling, general and administrative expenses (exclusive of depreciation and amortization) 13,497 13,150
Net costs associated with flood 5,763 —
Depreciation and amortization 19,635 14,235

Total operating costs and expenses 1,135,645 444,467

Operating income (loss) 87,358 (53,984 )
Other income (expense):
Interest expense and other financing costs (11,298 ) (11,857 )
Interest income 702 452
Loss on derivatives, net (47,871 ) (136,959 )
Other income, net 179 1

Total other income (expense) (58,288 ) (148,363 )

Income (loss) before income taxes and minority interest in subsidiaries 29,070 (202,347 )
Income tax expense (benefit) 6,849 (47,298 )
Minority interest in loss of subsidiaries — 676

Net income (loss) $ 22,221 $ (154,373 )

Net earnings per share
Basic $ 0.26
Diluted $ 0.26
Weighted average common shares outstanding
Basic 86,141,291
Diluted 86,158,791
Pro Forma Information (note 11)
Net (loss) per share
Basic $ (1.79 )
Diluted $ (1.79 )
Weighted average common shares outstanding
Basic 86,141,291
Diluted 86,141,291


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(Unaudited)
	(In thousands except share amounts)

Net sales	$	1,512,503		$	843,413		$	2,735,506		$	1,233,896
Operating costs and expenses:
Cost of product sold (exclusive of depreciation and amortization)		1,287,477			569,623			2,323,671			873,293
Direct operating expenses (exclusive of depreciation and amortization)		62,336			60,955			122,892			174,367
Selling, general and administrative expenses (exclusive of depreciation and amortization)		14,762			14,937			28,259			28,087
Net costs associated with flood		3,896			2,139			9,659			2,139
Depreciation and amortization		21,080			17,957			40,715			32,192

Total operating costs and expenses		1,389,551			665,611			2,525,196			1,110,078

Operating income		122,952			177,802			210,310			123,818
Other income (expense):
Interest expense and other financing costs		(9,460	)		(15,763	)		(20,758	)		(27,620	)
Interest income		601			161			1,303			613
Loss on derivatives, net		(79,305	)		(155,485	)		(127,176	)		(292,444	)
Other income, net		251			101			430			102

Total other income (expense)		(87,913	)		(170,986	)		(146,201	)		(319,349	)

Income (loss) before income taxes and minority interest in subsidiaries		35,039			6,816			64,109			(195,531	)
Income tax expense (benefit)		4,051			(93,669	)		10,900			(140,967	)
Minority interest in loss of subsidiaries		—			(419	)		—			257

Net income (loss)	$	30,988		$	100,066		$	53,209		$	(54,307	)

Net earnings per share
Basic	$	0.36					$	0.62
Diluted	$	0.36					$	0.62
Weighted average common shares outstanding
Basic		86,141,291						86,141,291
Diluted		86,158,791						86,158,791
Pro Forma Information (note 11)
Net income (loss) per share
Basic				$	1.16					$	(0.63	)
Diluted				$	1.16					$	(0.63	)
Weighted average common shares outstanding
Basic					86,141,291						86,141,291
Diluted					86,158,791						86,141,291

See accompanying notes to the condensed consolidated financial statements.

F-66

CVR ENERGY, INC. AND SUBSIDIARIES

~~Condensed Consolidated Statements of Cash Flows~~CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

Three Months Ended

March 31,

2008

2007

(unaudited)
(in thousands of dollars)

Cash flows from operating activities:
Net income (loss) $ 22,221 $ (154,373 )
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization 19,635 14,235
Provision for doubtful accounts 206 (235 )
Amortization of deferred financing costs 495 473
Loss on disposition of fixed assets 16 24
Share-based compensation (383 ) 3,742
Minority interest in loss of subsidiaries — (676 )
Changes in assets and liabilities:
Accounts receivable (30,693 ) 44,627
Inventories (31,642 ) (22,986 )
Prepaid expenses and other current assets 75 31
Insurance receivable 1,085 —
Insurance proceeds from flood (1,500 ) —
Other long-term assets (3,159 ) 923
Accounts payable (5,166 ) 46,357
Accrued income taxes 5,201 14,888
Deferred revenue 16,623 5,067
Other current liabilities 5,315 3,470
Payable to swap counterparty 20,750 129,344
Accrued environmental liabilities 80 485
Other long-term liabilities 3,325 —
Deferred income taxes 1,710 (41,291 )

Net cash provided by operating activities 24,194 44,105

Cash flows from investing activities:
Capital expenditures (26,156 ) (107,363 )

Net cash used in investing activities (26,156 ) (107,363 )

Cash flows from financing activities:
Revolving debt payments (123,000 ) —
Revolving debt borrowings 123,000 29,500
Principal payments on long-term debt (1,223 ) —
Deferred costs of CVR Energy, Inc. initial public offering — (553 )
Deferred costs of CVR Partners, LP initial public offering (2,145 ) —

Net cash (used in) provided by financing activities (3,368 ) 28,947

Net decrease in cash and cash equivalents (5,330 ) (34,311 )
Cash and cash equivalents, beginning of period 30,509 41,919

Cash and cash equivalents, end of period $ 25,179 $ 7,608

Supplemental disclosures:
Cash paid for income taxes, net of refunds (received) $ (63 ) $ (20,895 )
Cash paid for interest 11,841 39
Non-cash investing and financing activities:
Accrual of construction in progress additions (6,237 ) 13,204


	Six Months Ended
	June 30,
	2008			2007
	(Unaudited)
	(In thousands of dollars)

Cash flows from operating activities:
Net income (loss)	$	53,209		$	(54,307	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation and amortization		40,715			32,192
Provision for doubtful accounts		3,937			9
Amortization of deferred financing costs		989			951
Loss on disposition of fixed assets		1,550			1,155
Share-based compensation		(11,123	)		6,783
Minority interest in loss of subsidiaries		—			(257	)
Write-off of CVR Partners, LP initial public offering costs		2,560			—
Changes in assets and liabilities:
Accounts receivable		(54,527	)		(6,442	)
Inventories		(71,838	)		(17,810	)
Prepaid expenses and other current assets		801			(164	)
Insurance receivable		2,846			—
Insurance proceeds from flood		1,500			—
Other long-term assets		(2,873	)		(1,071	)
Accounts payable		(4,666	)		28,150
Accrued income taxes		(4,304	)		(101,369	)
Deferred revenue		(6,166	)		(7,428	)
Other current liabilities		4,839			14,620
Payable to swap counterparty		67,661			276,551
Accrued environmental liabilities		(223	)		218
Other long-term liabilities		444			—
Deferred income taxes		(2,013	)		(11,088	)

Net cash provided by operating activities		23,318			160,693

Cash flows from investing activities:
Capital expenditures		(49,635	)		(214,053	)

Net cash used in investing activities		(49,635	)		(214,053	)

Cash flows from financing activities:
Revolving debt payments		(288,000	)		(117,000	)
Revolving debt borrowings		309,500			157,000
Principal payments on long-term debt		(2,443	)		(1,937	)
Payment of capital lease obligation		(900	)		—
Payment of financing costs		—			(485	)
Deferred costs of CVR Partners, LP initial public offering		(1,712	)		—
Deferred costs of CVR Energy, Inc convertible debt offering		(21	)		—
Deferred costs of CVR Energy, Inc. initial public offering		—			(3,060	)

Net cash provided by financing activities		16,424			34,518

Net decrease in cash and cash equivalents		(9,893	)		(18,842	)
Cash and cash equivalents, beginning of period		30,509			41,919

Cash and cash equivalents, end of period	$	20,616		$	23,077

Supplemental disclosures:
Cash paid for income taxes, net of refunds (received)	$	17,216		$	(28,510	)
Cash paid for interest		22,229			17,589
Non-cash investing and financing activities:
Accrual of construction in progress additions		(14,924	)		(30,085	)
Assets acquired through capital lease		5,097			—

See accompanying notes to the condensed consolidated financial statements.

F-67

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

~~March 31,~~June 30, 2008

(unaudited)


(1)	Organization and History of the Company and Basis of Presentation

Organization

The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date after June 24, 2005 and prior to October 16, 2007 (the date of the restructuring as further discussed in this note) are to Coffeyville Acquisition LLC (CALLC) and its subsidiaries.

The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer of high value transportation fuels in the mid-continental United States and, through a limited partnership, a producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.

CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (CALLC II).

Initial Public Offering of CVR Energy, Inc.

On October 26, 2007, CVR Energy, Inc. completed an initial public offering of 23,000,000 shares of its common stock. The initial public offering price was $19.00 per share.

The net proceeds to CVR from the initial public offering were approximately $408.5 million, after deducting underwriting discounts and commissions, but before deduction of other offering expenses. The Company also incurred approximately $11.4 million of other costs related to the initial public offering. The net proceeds from this offering were used to repay $280.0 million of term debt under the Company’s credit facility and to repay all indebtedness under the Company’s $25.0 million unsecured facility and $25.0 million secured facility, including related accrued interest through the date of repayment of approximately $5.9 million. Additionally, $50.0 million of net proceeds were used to repay outstanding revolving loan indebtedness under the Company’s credit facility. The balance of the net proceeds received were used for general corporate purposes.

In connection with the initial public offering, CVR became the indirect owner of the subsidiaries of CALLC and CALLC II. This was accomplished by CVR issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with the 628,667.20 for 1 stock split of CVR’s common stock and the mergers of two newly formed direct subsidiaries of CVR into Coffeyville Refining & Marketing Holdings, Inc. (Refining Holdco) and Coffeyville Nitrogen Fertilizers, Inc. (CNF). Concurrent with the merger of the subsidiaries and in accordance with a previously executed agreement, the Company’s chief executive officer received 247,471 shares of CVR common stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully vested and were exchanged at fair market value.

The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in connection with the initial public offering. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, which does not include the non-vested shares noted below.

F-68

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

On October 24, 2007, 17,500 shares of non-vested common stock having a value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer

~~F-68~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

to the recipients until the shares have vested, recipients have dividend and voting rights with respect to these shares from the date of grant. The fair value of each share of non-vested common stock was measured based on the market price of the common stock as of the date of grant and is being amortized over the respective vesting periods. One-third of the non-vested award will vest on October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on October 24, 2010.

Options to purchase 10,300 shares of common stock at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. These awards will vest over a three year service period. Fair value was measured using an option-pricing model at the date of grant.

Nitrogen Fertilizer Limited Partnership

In conjunction with the consummation of CVR’s initial public offering, CVR transferred Coffeyville Resources Nitrogen Fertilizer, LLC (CRNF), its nitrogen fertilizer business, to CVR Partners, LP (the Partnership), a newly created limited partnership, ~~(Partnership)~~ in exchange for a managing general partner interest (managing GP interest), a special general partner interest (special GP interest, represented by special GP units) and a de minimis limited partner interest (LP interest, represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to Coffeyville Acquisition LLC III (CALLC III), an entity owned by CVR’s controlling stockholders and senior management at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing general partner interest was $10.6 million. This interest has been reflected as minority interest in the Consolidated Balance Sheet.

CVR owns all of the interests in the Partnership (other than the managing general partner interest and the associated incentive distribution rights (IDRs)) and is entitled to all cash distributed by the Partnership. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the amended and restated partnership agreement, generated by the Partnership through December 31, 2009 has been distributed in respect of the units held by CVR and any common units issued inby the ~~Partnership’s~~Partnership if it elects to pursue an initial public offering. ~~The~~In addition, the Partnership and its subsidiaries are currently guarantors under the credit facility of Coffeyville Resources, LLC (CRLLC), a wholly-owned subsidiary of CVR. There will be no distributions paid with respect to the IDR’s for so long as the Partnership or its subsidiaries are guarantors under the credit facility.

The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR, the Partnership, the managing general partner and various

F-69

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

of their subsidiaries also entered into a number of agreements to regulate certain business relations between the parties.

At ~~March 31,~~June 30, 2008, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing general partner interest and the IDRs. The managing general partner contributed ~~1% of~~

~~F-69~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

~~CRNF’s interest to~~assets into the Partnership in exchange for its managing general partner interest and the IDRs.

As of June 30, 2008, the Partnership had distributed $50.0 million to CVR from its Adjusted Operating Surplus.

On February 28, 2008, the Partnership filed a registration statement with the Securities and Exchange Commission (SEC) to effect ~~the contemplated~~an initial public offering of its common units representing limited partner interests. ~~The registration statement provided~~On June 13, 2008, the Company announced that ~~upon consummation~~the managing general partner of the Partnership had decided to postpone, indefinitely, the Partnership’s initial public offering CVR will indirectly own the Partnership’s special general partner and approximately 87% of the outstanding units of the Partnership. There can be no assurance that any such offering will be consummated on the terms described indue to then-existing market conditions for master limited partnerships. The Partnership, subsequently, withdrew the registration ~~statement or at all. The offering is under review by the SEC and as a result the terms and resulting structure disclosed below could be materially different.~~statement.

In connection with the Partnership’s initial public offering, CRLLC will contribute all of its special LP units to the Partnership’s special general partner and all of the Partnership’s special general partner interests and special limited partner interests will be converted into a combination of GP units and subordinated GP units. Following the initial public offering, as currently structured, the Partnership is expected to have the following partnership interests outstanding:


	•	~~5,250,000 common units representing limited partner interests, all of which the Partnership will sell in the initial public offering;~~

	•	~~18,750,000 GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner;~~

	•	~~18,000,000 subordinated GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner; and~~

	•	a managing general partner interest, which is not entitled to any distributions, which is held by the Partnership’s managing general partner, and incentive distribution rights representing limited partner interests, all of which will be held by the Partnership’s managing general partner.

Effective with the Partnership’s initial public offering, the partnership agreement will require that the Partnership distribute all of its cash on hand at the end of each quarter, less reserves established by its managing general partner, subject to a sustainability requirement in the event the Partnership elects to increase the quarterly distribution amount. The amount of available cash may be greater or less than the aggregate amount necessary to make the minimum quarterly distribution on all common units, GP units and subordinated units.

Subsequent to the initial public offering, as currently structured, the Partnership expects to make minimum quarterly distributions of $0.375 per common unit ($1.50 per common unit on an annualized basis) to the extent the Partnership has sufficient available cash. In general, cash distributions will be made each quarter as follows:


	•	~~First, to the holders of common units and GP units until each common unit and GP unit has received a minimum quarterly distribution of $0.375 plus any arrearages from prior quarters;~~

	•	~~Second, to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.375; and~~

	•	~~Third, to all unitholders, pro rata, until each unit has received a quarterly distribution of $0.4313.~~

~~If cash distributions exceed $0.4313 per unit in a quarter, the Partnership’s managing general partner, as holder of the IDRs, will receive increasing percentages, up to 48%, of the cash the~~

~~F-70~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

Partnership distributes in excess of $0.4313 per unit. However, the managing general partner will not be entitled to receive any distributions in respect of the IDRs until the Partnership has made cash distributions in an aggregate amount equal to the Partnership’s adjusted operating surplus generated during the period from the closing of the Partnership’s initial public offering until December 31, 2009.

During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units and GP units have received the minimum quarterly distribution of $0.375 per unit plus any arrearages from prior quarters. The subordination period begins on the closing date of the Partnership’s initial public offering and will end once the Partnership meets the financial tests in the partnership agreement. When the subordination period ends, all subordinated units will convert into GP units or common units on a one-for-one basis, and the common units and GP units will no longer be entitled to arrearages.

If the Partnership meets the financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after the first quarter whose last day is at least three years after the closing of Partnership Offering, 25% of the subordinated GP units will convert into GP units on a one-for-one basis. If the Partnership meets these financial tests for any three consecutive four-quarter periods ending on or after the first quarter whose last day is at least four years after the closing of the Partnership Offering, an additional 25% of the subordinated GP units will convert into GP units on a one-for-one basis. The early conversion of the second 25% of the subordinated GP units may not occur until at least one year following the end of the last four-quarter period in respect of which the first 25% of the subordinated GP units were converted. If the subordinated GP units have converted into subordinated LP units at the time the financial tests are met they will convert into common units, rather than GP units. In addition, the subordination period will end if the managing general partner is removed as the managing general partner where “cause” (as defined in the partnership agreement) does not exist and no units held by any holder of subordinated units or its affiliates are voted in favor of that removal.

If at any time the managing general partner and its affiliates own more than 80% of the common units, the managing general partner will have the right, but not the obligation, to purchase all of the remaining common units at a purchase price equal to the greater of (x) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (y) the highest~~per-unit~~ ~~price paid by the managing general partner or any of its affiliates for common units during the90-day~~ ~~period preceding the date such notice is first mailed.~~

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

~~F-71~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

rules and regulations of the SEC. The consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interests of minority investors in its subsidiaries are recorded as minority interest. All intercompany accounts and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under GAAP have been condensed or omitted pursuant to such rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2007 audited consolidated financial statements and notes thereto included in CVR’s Annual Report onForm 10-K/A for the year ended December 31, 2007.

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 of the Company as of ~~March 31,~~June 30, 2008 and December 31, 2007, the results of operations for the three and six months ended ~~March 31,~~June 30, 2008 and 2007, and the cash flows for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and 2007.

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, 2008 or any other interim period. The preparation of financial statements in conformity with U.S. generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.

In connection with CVR’s initial public offering, ~~$0.5~~$3.1 million of deferred offering costs for the ~~three~~six months ended ~~March 31,~~June 30, 2007 were previously presented in operating activities in the interim financial statements. Such amounts have now been reflected as financing activities for the ~~three~~six months ended ~~March 31,~~June 30, 2007 in the accompanying Consolidated Statements of Cash Flows. The impact on the prior financial statements of this revision is not considered material.

F-70

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(2)	Recent Accounting Pronouncements

In September 2006, the Financial Accounting Standards Board (FASB) issued Statement on Financial Accounting Standards (SFAS) No. 157,Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 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 standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At ~~March 31,~~June 30, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14, “Fair Value ~~Measurements”.~~Measurements.”

~~In February 2007, the FASB issued SFAS No. 159,~~~~The Fair Value Option for Financial Assets and Financial Liabilities~~. Under this standard, an entity is required to provide additional information that will assist investors and other users of financial information to more easily understand the effect of the Company’s choice to use fair value on its earnings. Further, the entity is required to display the

~~F-72~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 107,~~Disclosures about Fair Value of Financial Instruments~~. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of SFAS 159 did not impact the Company’s consolidated financial statements as of the quarter ended March 31, 2008.

~~In December 2007, the FASB issued SFAS No. 141(R),~~~~Business Combinations~~. This statement defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of the acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business combinations for which the acquisition date is on or after January 1, 2009.

~~In December 2007, the FASB issued SFAS No. 160,~~~~Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.~~SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.

In May 2008, the FASB issued final FASB Staff Position (“FSP”) No. APB14-1,Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversions (Including Partial Cash Settlement).The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,Accounting for Derivative Instruments and Hedging Activities.Under the FSP, cash settled convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the liability of equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and the interim periods within those fiscal years, and will require issuers of convertible debt that can be settled in cash to record the additional expense incurred. The Company is currently evaluating the FSP in conjunction with its proposed convertible debt offering.


(3)	Share Based Compensation

Prior to CVR’s initial public offering, CVR’s subsidiaries were held and operated by CALLC, a limited liability company. Management of CVR holds an equity interest in CALLC. CALLC ~~had~~ issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with CVR’s initial public offering in October 2007, CALLC was split into two entities: CALLC and CALLC II. In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting

F-71

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. CALLC was historically the primary reporting company and CVR’s predecessor. In connection with the ~~restructuring~~transfer of the ~~Company related~~managing general partner of the Partnership to ~~the Partnership,~~CALLC III, CALLC III issued non-voting override units to certain management members of CALLC III.

CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with SFAS No. 123(R),Share-Based PaymentsandEITF 00-12,Accounting by an Investor for

~~F-73~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

Stock-Based Compensation Granted to Employees of an Equity Method Investee. CVR has recorded non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.

In accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair value based measurement method in accounting for share-based compensation. In accordance withEITF 00-12, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance inEITF 96-18,Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires remeasurement at each reporting period. At ~~March 31,~~June 30, 2008, CVR’s common stock closing price was utilized to determine the fair value of the override units of CALLC and CALLC II. The estimated fair value per unit reflects a ratio of override units to shares of common stock. The estimated fair value of the override units of CALLC III has been determined using a binomial and probability-weighted expected return method which utilizes CALLC III’s cash flow projections, which are representative of the nature of interests held by CALLC III in the Partnership.

The following ~~describes~~table provides key information for the share-based compensation plans related to the override units of CALLC, CALLC II, and CALLC ~~III and CRLLC, CVR’s indirect wholly owned subsidiary.~~III. Compensation expense amounts are disclosed in thousands.

~~919,630 Override Operating Units at an Adjusted Benchmark Value of $11.31 per Unit~~


						*Compensation Expense Increase					*Compensation Expense Increase
	Benchmark					(Decrease) for the Three Months					(Decrease) for the Six Months
	Value		Awards			Ended June 30,					Ended June 30,
Award Type	(per Unit)		Issued		Grant Date	2008			2007		2008			2007

Override Operating Units(a)	$	11.31		919,630	June 2005	$	(3,967	)	$	280	$	(4,525	)		565
Override Operating Units(b)	$	34.72		72,492	December 2006		(261	)		96		(255	)		196
Override Value Units(c)	$	11.31		1,839,265	June 2005		(3,731	)		169		(3,198	)		339
Override Value Units(d)	$	34.72		144,966	December 2006		(165	)		52		(74	)		103
Override Units(e)	$	10.00		138,281	October 2007		(2	)		—		(2	)		—
Override Units(f)	$	10.00		642,219	February 2008		1			—		2			—

					Total	$	(8,125	)	$	597	$	(8,052	)	$	1,203

In June 2005, CALLC issued 919,630 non-voting override operating units to certain management members holding common units of CALLC. There were no required capital contributions for the override operating units.


*		— As CVR’s stock price increases or decreases compensation expense increases or is reversed in correlation

~~In accordance with SFAS 123(R),~~~~Share Based Compensation~~, using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,605,000. Pursuant to the forfeiture schedule described below, CVR recognized 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 of $(558,000) and $285,000 was recognized for the three months ending March 31, 2008 and 2007, respectively.

In connection with the split of CALLC into two entities on October 16, 2007, management’s equity interest in CALLC was split so that half of management’s equity interest is in CALLC and half is in CALLC II. The restructuring resulted in a modification of the existing awards under SFAS 123(R). However, because the fair value of the modified award equaled the fair value of the original award before the modification, there was no accounting consequence as a result of the modification. However, due to the restructuring, the employees of CVR and the Partnership no longer hold share-based awards in a parent company. Due to the change in status of the employees related to the awards, CVR recognized compensation expense for the newly measured cost attributable to the remaining vesting (service) period prospectively from the date of the change in status.

~~F-74~~F-72

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Significant assumptions used in the valuation were as follows:~~

Valuation Assumptions


(a)		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 $3,605,000. Significant assumptions used in the valuation were as follows:


	Grant	Remeasurement
	~~Grant~~ Date	Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule in (b) below	Based on forfeiture schedule in (b) below
Grant date fair value	$5.16 per share	N/A
~~March 31,~~June 30, 2008 CVR closing stock price	N/A	$~~23.03~~19.25
~~March 31,~~June 30, 2008 estimated fair value	N/A	$~~47.88~~40.05 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	N/A

~~72,492 Override Operating Units at a Benchmark Value of $34.72 per Unit~~


(b)		In accordance with SFAS 123(R), using a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections, the estimated fair value of the override operating units on December 28, 2006 was $473,000. Significant assumptions used in the valuation were as follows:

On December 28, 2006, CALLC issued 72,492 additional non-voting override operating units to a management member who held common units of CALLC. There were no required capital contributions for the override operating units.

In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections resulted in an estimated fair value of the override operating units on December 28, 2006 of $473,000. Management believed that this method was preferable for the valuation of the override units as it allowed a better integration of the cash flows with other inputs, including the timing of potential exit events that impact the estimated fair value of the override units. These override operating units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with the accounting method noted above and pursuant to the forfeiture schedule described below, CVR recognized compensation expense of $6,000 and $100,000 for the periods ending March 31, 2008 and 2007, respectively.

~~Significant assumptions used in the valuation were as follows:~~


	Grant	Remeasurement
	~~Grant~~ Date	Date

Estimated forfeiture rate	None	None
Explicit service period	Based on forfeiture schedule below	Based on forfeiture
	~~schedule below~~	schedule below
Grant date fair value	$8.15 per share	N/A
~~March 31,~~June 30, 2008 CVR closing stock price	N/A	$~~23.03~~19.25
~~March 31,~~June 30, 2008 estimated fair value	N/A	$~~28.68~~20.86 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	N/A

~~F-75~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to~~On the ~~Condensed Consolidated Financial Statements — (Continued)~~

tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units. Override operating units are forfeited upon termination of employment for cause. 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:


Minimum	Forfeiture
Period Held	Rate

2 years		75	%
3 years		50	%
4 years		25	%
5 years		0	%

F-73

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(c)		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 $4,065,000. Significant assumptions used in the valuation were as follows:


	~~Forfeiture~~Grant
~~Minimum Period Held~~	~~Rate~~

~~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 convert into an equivalent number of override value units.~~

~~1,839,265 Override Value Units at an Adjusted Benchmark Value of $11.31 per Unit~~

In June 2005, CALLC issued 1,839,265 non-voting override value units to certain management members who held common units of CALLC. There were no required capital contributions for the override value units.

~~Significant assumptions used in the valuation were as follows:~~


		Remeasurement
	~~Grant~~ Date	Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant date fair value	$2.91 per share	N/A
~~March 31,~~June 30, 2008 CVR closing stock price	N/A	$~~23.03~~19.25
~~March 31,~~June 30, 2008 estimated fair value	N/A	$~~47.88~~40.05 per share
Marketability and minority interest discounts	24% discount	15% discount
Volatility	37%	N/A

~~144,966 Override Value Units at a Benchmark Value of $34.72 per Unit~~


(d)		In accordance with SFAS 123(R), using a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections, the estimated fair value of the override value units on December 28, 2006 was $945,000. Significant assumptions used in the valuation were as follows:

On December 28, 2006, CALLC issued 144,966 additional non-voting override value units to a management member who held common units of CALLC. There were no required capital contributions for the override value units.

~~F-76~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

operating units with the adjusted benchmark value of $11.31 per unit. In accordance with the accounting method noted above, CVR recognized compensation expense of $91,000, and $52,000 for the three months ending March 31, 2008 and 2007, respectively.

~~Significant assumptions used in the valuation were as follows:~~


	Grant	Remeasurement
	~~Grant~~ Date	Date

Estimated forfeiture rate	None	None
Derived service period	6 years	6 years
Grant date fair value	$8.15 per share	N/A
~~March 31,~~June 30, 2008 CVR closing stock price	N/A	$~~23.03~~19.25
~~March 31,~~June 30, 2008 estimated fair value	N/A	$~~28.68~~20.86 per share
Marketability and minority interest discounts	20% discount	15% discount
Volatility	41%	N/A

Unless the compensation committee of the board of directors of CVR 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%~~75	%
3 years		~~50%~~50	%
4 years		~~25%~~25	%
5 years		0%0	%

At March 31, 2008, assuming no change in the estimated fair value at March 31, 2008, there was approximately $59.2 million of unrecognized compensation expense related to non-voting override units. This is expected to be recognized over a remaining period of four years as follows (in thousands):

Override
Override

Operating Units

Value Units

Nine months ending December 31, 2008 $ 4,927 $ 11,688
Year ending December 31, 2009 3,762 15,585
Year ending December 31, 2010 1,120 15,584
Year ending December 31, 2011 — 6,569

$ 9,809 $ 49,426


(e)		In accordance with SFAS 123(R),Share Based Compensation,using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flows projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair

~~138,281 Override Units with a Benchmark Amount of $10~~

In October 2007, CALLC III issued 138,281 non-voting override units to certain management members who held common units of CALLC III. There were no required capital contributions for the override units.

~~In accordance with SFAS 123(R),~~~~Share Based Compensation~~, using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flow projections, the estimated fair value of the operating units at March 31, 2008 was immaterial. CVR recognizes compensation

~~F-77~~F-74

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~costs for this plan based on the fair value of the awards at the end of each reporting period in accordance withEITF 00-12~~ ~~using the guidance inEITF 96-18.~~ ~~In accordance withEITF 00-12,~~ as a noncontributing investor, CVR also recognized income equal to the amount that its interest in the Partnership’s net book value has increased (that is, its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation costs. This amount equaled the compensation expense recognized for these awards for the three months ended March 31, 2008. Pursuant to the forfeiture schedule reflected above, CVR recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed. As of March 31, 2008, these override units are


		value of the override units was approximately $3,000. As of June 30, 2008 these units were fully vested. Significant assumptions used in the valuation were as follows:

~~Significant assumptions used in the valuation were as follows:~~


Estimated forfeiture rate		None
~~March 31,~~June 30, 2008 estimated fair value		$~~0.004~~0.007 per share
Marketability and minority interest discount		15% discount
Volatility		36.2%

~~642,219 Override Units with a Benchmark Amount of $10~~


(f)		In accordance with SFAS 123(R),Share Based Compensation,using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flows projections which includes expected future earnings and the anticipated timing of IDRs, the estimated grant date fair value of the override units was approximately $3,000. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to a forfeiture schedule. Significant assumptions used in the valuation were as follows:

~~On February 15, 2008, CALLC III issued 642,219 non-voting override units to certain management members of CALLC III. There were no required capital contributions for the override units.~~

~~In accordance with SFAS 123(R),~~~~Share Based Compensation,~~using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flows projections, the estimated fair value of the operating units at March 31, 2008 was immaterial. CVR recognizes compensation costs for this plan based on the fair value of the awards at the end of each reporting period in accordance with~~EITF 00-12~~ ~~using the guidance inEITF 96-18.~~ ~~In accordance withEITF 00-12,~~ as a noncontributing investor, CVR also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is, its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation costs. CVR recognized compensation expense of $600 for the three months ended March 31, 2008. Pursuant to the forfeiture schedule of the amended and restated partnership agreement of CALLC III, CVR recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed. Of the 642,219 units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to the forfeiture schedule.

~~Significant assumptions used in the valuation were as follows:~~


Estimated forfeiture rate		None
Derived Service Period		Based on forfeiture schedule
~~March 31,~~June 30, 2008 estimated fair value		$~~0.004~~0.007 per share
Marketability and minority interest discount		15% discount
Volatility		36.2%

At June 30, 2008, assuming no change in the estimated fair value at June 30, 2008, there was approximately $44.1 million of unrecognized compensation expense related to non-voting override units. This is expected to be recognized over a remaining period of approximately three years as follows (in thousands):


	Override		Override
	Operating		Value
	Units		Units

Six months ending December 31, 2008	$	2,220	$	6,468
Year ending December 31, 2009		3,120		12,937
Year ending December 31, 2010		930		12,937
Year ending December 31, 2011		—		5,445

	$	6,270	$	37,787

Phantom Unit Appreciation Plan

The Company, 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. As of

~~F-78~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

~~March 31,~~ June 30, 2008, the issued Profits Interest (combined phantom ~~plan~~points and override units) represented 15% of combined common unit interest and Profits Interest of CALLC and CALLC II. The Profits Interest was comprised of 11.1% and 3.9% of override interest and phantom interest, respectively. In accordance with SFAS 123(R), using the ~~March 31,~~June 30, 2008 CVR closing stock ~~closing~~ price to determine the Company’s equity value, through an independent valuation process, the service phantom interest and performance phantom interest were both valued at ~~$47.88~~$40.05 per point. CVR has recorded approximately ~~$28,670,000~~$25,961,000 and $29,217,000 in personnel accruals as of ~~March 31,~~June 30, 2008 and December 31, 2007, respectively. Compensation expense

F-75

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

for the three and six month periods ending ~~March 31,~~June 30, 2008 ~~and 2007~~ related to the Phantom Unit Appreciation Plan was ~~$(547,000)~~reversed by $(2,709,000) and ~~$3,136,000,~~$(3,256,000), respectively. Compensation expense for the three and six month periods ending June 30, 2007 was $2,444,000 and $5,580,000, respectively.

At ~~March 31,~~June 30, 2008, assuming no change in the estimated fair value at ~~March 31,~~June 30, 2008, there was approximately ~~$20.6~~$15.4 million of unrecognized compensation expense related to the Phantom Unit Appreciation Plan. This is expected to be recognized over a remaining period of ~~four~~approximately three years.

Long Term Incentive Plan

CVR has a Long Term Incentive ~~Plan. There~~Plan which permits the grant of options, stock appreciation rights, or SARS, non-vested shares, non-vested share units, dividend equivalent rights, share awards and performance awards.

During the quarter there were no ~~awards granted under this plan in the first quarter~~forfeitures or vesting of ~~2008.~~

stock options or non-vested shares. On October 24, 2007, 17,500 shares of non-vested common stock having a fair value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights on these shares from the date of grant. The fair value of each share of non-vested common stock was measured based on the market price of the common stock as of the date of grant and will be amortized over the respective vesting periods. One-third will vest on October 24,June 10, 2008, ~~2009 and 2010, respectively.~~

~~Options~~options to purchase ~~10,300~~4,350 shares of common stock at an exercise price of ~~$19.00~~$24.96 per share were granted to an outside ~~directors on October 22, 2007. Options~~director upon his election to ~~purchase 8,600 shares~~the Company’s board of ~~common stock at an exercise price of $24.73 per share were granted to outside directors on December 21, 2007.~~directors.

~~During the quarter there were no issuances, forfeitures or vesting of stock options or non-vested shares.~~

As of ~~March 31,~~June 30, 2008, there was approximately ~~$0.2~~$0.1 million of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately one year. Compensation expense recorded for the three month periods ending ~~March 31,~~June 30, 2008 and 2007 related to the non-vested common stock and common stock options was ~~$56,000~~$94,000 and $0, respectively. Compensation expense recorded for the ~~three~~six month periods ending ~~March 31,~~June 30, 2008 and 2007 related to the non-vested common stock and common stock options was ~~$36,000~~$185,000 and $0, respectively.


(4)	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 thefirst-in, first-out (FIFO) cost, or market, for fertilizer products, 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 towork-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 moving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

Inventories consisted of the following (in thousands):


	June 30,		December 31,
	2008		2007

Finished goods	$	145,978	$	109,394
Raw materials and catalysts		127,902		92,104
In-process inventories		28,363		29,817
Parts and supplies		26,495		23,340

	$	328,738	$	254,655

~~F-79~~F-76

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~Inventories consisted of the following (in thousands):~~

March 31,
December 31,

2008

2007

Finished goods $ 123,814 $ 109,394
Raw materials and catalysts 123,042 92,104
In-process inventories 17,045 29,817
Parts and supplies 24,514 23,340

$ 288,415 $ 254,655


(5)	Property, Plant, and Equipment

A summary of costs for property, plant, and equipment is as follows (in thousands):

March 31,
December 31,

2008

2007

Land and improvements $ 13,170 $ 13,058
Buildings 19,351 17,541
Machinery and equipment 1,277,292 1,108,858
Automotive equipment 5,752 5,171
Furniture and fixtures 6,420 6,304
Leasehold improvements 929 929
Construction in progress 30,859 182,046

1,353,773 1,333,907
Accumulated depreciation 161,231 141,733

$ 1,192,542 $ 1,192,174


	June 30,		December 31,
	2008		2007

Land and improvements	$	18,588	$	13,058
Buildings		19,170		17,541
Machinery and equipment		1,277,760		1,108,858
Automotive equipment		6,269		5,171
Furniture and fixtures		7,362		6,304
Leasehold improvements		929		929
Construction in progress		41,498		182,046

		1,371,576		1,333,907
Accumulated depreciation		181,655		141,733

	$	1,189,921	$	1,192,174

Capitalized interest recognized as a reduction in interest expense for the three month periods ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 30, 2007 totaled approximately ~~$1,118,000~~$203,000 and ~~$4,079,000,~~$2,328,000, respectively. Capitalized interest for the six month periods ended June 30, 2008 and June 30, 2007 totaled approximately $1,321,000 and $6,407,000, respectively. Land and buildings that are under a capital lease obligation approximate $5,097,000.


(6)	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. The ~~Coffeyville~~ nitrogen fertilizer plant last completed a major scheduled turnaround in the third quarter of 2006 and is scheduled to complete a turnaround in the fourth quarter of 2008. The ~~Coffeyville~~ refinery started a major scheduled turnaround in February 2007 with completion in April 2007. Costs of ~~$66,003,000~~$10,795,000 and $76,798,000 associated with the 2007 refinery turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the three and six months ending ~~March 31, 2007.~~June 30, 2007, respectively.


(7)	Cost Classifications

Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of ~~$600,000~~$611,000 and ~~$619,000~~$577,000 for the three months ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 30, 2007, respectively. For the six months ended June 30, 2008 and 2007 cost of product sold excludes depreciation and amortization of $1,210,000 and $1,197,000, respectively.

Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses excludes depreciation and amortization of $20,108,000 and $17,089,000 for the three months ended June 30, 2008 and 2007, respectively. For the six months ended June 30, 2008 and 2007, direct operating expenses excludes depreciation and amortization of $38,811,000 and $30,619,000, respectively.

~~F-80~~F-77

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

~~depreciation and amortization of $18,703,000 and $13,530,000 for the three months ended March 31, 2008 and March 31, 2007, respectively.~~

Selling, general and administrative expenses (exclusive of depreciation and amortization) ~~consists~~consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of ~~$332,000~~$361,000 and ~~$86,000~~$291,000 for the three months ended ~~March 31,~~June 30, 2008 and ~~March 31,~~June 30, 2007, respectively. For the six months ended June 30, 2008 and 2007, selling, general and administrative expenses excludes depreciation and amortization of $694,000 and $376,000, respectively.


(8)	Note Payable and Capital Lease Obligations

The Company entered into an insurance premium finance agreement with Cananwill, Inc. in July 2007 to finance the purchase of its property, liability, cargo and terrorism policies. The original balance of the note was $7.6 million and required repayment in nine equal installments with final payment due in April 2008. As of December 31, 2007 the Company owed $3.4 million related to this agreement. The balance due was paid in full in April 2008. As of March 31, 2008 and December 31, 2007, $0.8 and $3.4 million related to this insurance premium finance agreement was included in note payable and capital lease obligations on the Consolidated Balance Sheet, respectively.

The Company entered into two capital leases in 2007 to lease platinum required in the manufacturing of a new catalyst. The recorded lease obligations fluctuate with the platinum market price. The leases ~~will~~ terminate on the date an equal amount of platinum is returned to each lessor, with the difference to be paid in cash. One lease was settled and terminated in January 2008. At ~~March 31,~~June 30, 2008 and December 31, 2007 the lease obligations were recorded at approximately ~~$10.4~~$10.5 million and $8.2 million on the Consolidated Balance Sheets, respectively.


~~(9)~~	~~Flood and Insurance Related Matters~~

The Company also entered into a capital lease for real property used for corporate purposes on May 29, 2008. The lease has an initial lease term of one year with an option to renew for three additional one-year periods. The Company has the option to purchase the property during the initial lease term or during the renewal periods if the lease is renewed. In connection with the capital lease the Company recorded a capital asset and capital lease obligation of $5.1 million. The capital lease obligation was reduced by $0.9 million payment made during the quarter resulting in a capital lease obligation of $4.2 million as of June 30, 2008.

(9) Flood, Crude Oil Discharge and Insurance Related Matters

On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. As a result, the Company’s refinery and nitrogen fertilizer plant were severely flooded, resulting in significant damage to the refinery assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The Company maintained property damage insurance which included damage caused by a flood, of up to $300 million per occurrence, subject to deductibles and other limitations. The deductible associated with the property damage was $2.5 million.

~~Management continues to work closely with~~

Additionally, crude oil was discharged from the Company’s ~~insurance carriers and claims adjusters to ascertain the full amount of insurance proceeds~~refinery on July 1, 2007 due to the ~~Company as a result~~short amount of time to shut down and save the refinery in preparation of the flood that occurred on June 30, 2007. The Company maintained insurance policies related to environmental cleanup costs and potential liability to third parties for bodily injury or property damage. The policies were subject to a $1.0 million self-insured retention.

The Company has submitted voluminous claims information to, and continues to respond to information requests from and negotiate with, the insurers with respect to costs and damages related to the 2007 flood and ~~losses.~~crude oil discharge. See Note 12, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007.

F-78

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of June 30, 2008, the Company has recorded total gross costs associated with the repair of, and other matters relating to the damage to the Company’s facilities and with third party and property damage remediation incurred due to the crude oil discharge of approximately $153.6 million. Total anticipated insurance recoveries of approximately $102.4 million have been recorded as of June 30, 2008 (of which $21.5 million had already been received as of June 30, 2008 by the Company from insurance carriers). At ~~March 31,~~June 30, 2008, total accounts receivable from insurance ~~was $85.7~~were $80.9 million. The receivable balance is segregated between current and long-term in the Company’s Consolidated Balance Sheet in relation to the nature and classification of the items to be settled. As of June 30, 2008, $58.7 million of the amounts receivable from insurers were not anticipated to be collected in the next twelve months, and therefore has been classified as a non-current asset.

Management believes the recovery of the receivable from the insurance carriers is probable. Approximately $11.4 million of the receivable recorded at March 31, 2008 relates to the crude oil discharge and the remaining $74.3 million relates to the flood damage to the Company’s facilities. While management believes that the Company’s property insurance should cover substantially all of the estimated total costs associated with the physical damage to the property, the Company’s insurance carriers have cited potential coverage limitations and defenses, which while unlikely to preclude recovery, are anticipated to delay collection for more than twelve months.

The Company’s property insurers have raised a question as to whether the Company’s facilities are principally located in “Zone A,” which was, at the time of the flood, subject to a $10 million insurance limit for flood or “Zone B” which was, at the time of the flood, subject to a $300 million insurance limit for flood. The Company has reached an agreement with certain of its property insurers representing approximately 32.5% of its total property coverage for the flood that ~~might preclude such~~the facilities are principally located in “Zone B” and therefore subject to the $300 million limit for the flood. The remaining property insurers have not, at this time, agreed to this position. The Company’s primary environmental liability insurance carrier has asserted that the pollution liability claims are for “cleanup,” which is subject to a ~~result.~~$10 million sub-limit, rather than “property damage,” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While the Company will vigorously contest the primary carrier’s position, the Company contends that if that position were upheld, the Company’s umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. On July 10, 2008, the Company filed two lawsuits against certain of its insurance carriers. One lawsuit was filed against the nonsettling property damage insurance carriers and the second lawsuit was filed against carriers under the environmental insurance policies. The lawsuits involved the Zone A/Zone B issue and the cleanup, property damage issue described above. The Company intends to pursue the litigation vigorously. Considering the effect of the lawsuits, the Company continues to believe its receivable of $80.9 million is probable of recovery.

~~F-81~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

48 days, a substantial portion of the lost profits incurred because of the flood cannot be claimed under insurance. The Company continues to assess its policies to determine how much, if any, of its lost profits after the45-day period are recoverable. No amounts for recovery of lost profits under the Company’s business interruption policy have been recorded in the accompanying consolidated financial statements.

The Company has recorded net pretax costs in total since the occurrence of the flood of approximately ~~$47.3~~$51.2 million associated with both the flood and related crude oil discharge as

F-79

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

discussed in Note 12, “Commitments and Contingent ~~Liabilities”, including $5.8 million of net pretax costs in the first quarter of 2008. These amounts are~~Liabilities.” This amount is net of anticipated insurance recoveries of ~~$107.2 million including $1.8 million of recoveries for the first quarter of 2008. These costs are reported in “Net costs associated with flood” in the Consolidated Statements of Operations.~~$102.4 million.

Total gross costs recorded due to the flood and related oil discharge that were included in the Consolidated Statements of Operations for the three months ended March 31, 2008 were $7.6 million. Of these gross costs for the three month period ended March 31, 2008, $3.8 million were associated with repair and other matters as a result of the flood damage to the Company’s facilities. Included in this cost was $0.3 million of professional fees and $3.5 million for other repair and related costs. There were also $3.8 million of costs recorded for the three month period ended March 31, 2008 related to the third party and property damage remediation as a result of the crude oil discharge.

Below is a summary of the gross cost associated with the flood and crude oil discharge and reconciliation of the insurance receivable (in millions):

For the Three

Months Ended

Total Costs

March 31, 2008

Total gross costs incurred $ 154.5 $ 7.6
Total insurance receivable (107.2 ) (1.8 )

Net costs associated with the flood $ 47.3 $ 5.8

Receivable

Reconciliation

Total insurance receivable $ 107.2
Less insurance proceeds received (21.5 )

Insurance receivable $ 85.7


				For the Three			For the Three		For the Six		For the Six
				Months Ended			Months Ended		Months Ended		Months Ended
				June 30,			June 30,		June 30,		June 30,
	Total			2008			2007		2008		2007

Total gross costs incurred	$	153.6		$	(0.9	)	$	2.1	$	6.7	$	2.1
Total insurance receivable		(102.4	)		4.8			—		3.0		—

Net costs associated with the flood	$	51.2		$	3.9		$	2.1	$	9.7	$	2.1

~~The Company anticipates that approximately $2.1 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods.~~


	Receivable
	Reconciliation

Total insurance receivable	$	102.4
Less insurance proceeds received through June 30, 2008		(21.5	)

Insurance receivable	$	80.9

Although the Company believes that it will recover substantial sums under its insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company ultimately receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements.

In 2007, the Company ~~had~~ received insurance proceeds of $10.0 million under its property insurance policy and $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge. In the first quarter of 2008, the Company received $1.5 million under its Builder’s Risk Insurance Policy. In July 2008, the Company received $13.0 million under its property insurance policy. See Note 12, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007.

~~F-82~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~


(10)	Income Taxes

The Company adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertain Tax Positions — an interpretation of FASB No. 109~~(FIN~~ (FIN 48) on January 1, 2007. The adoption of FIN 48 did not affect the Company’s financial position or results of operations. The Company does not have any unrecognized tax benefits as of ~~March 31,~~June 30, 2008.

~~The~~As of June 30, 2008, the Company did not ~~accrue or recognize~~have an accrual for any amounts for interest or penalties ~~in its financial statements for the three months ended March 31, 2008.~~related to uncertain tax positions. The ~~Company will~~Company’s accounting policy with respect to interest and penalties related to tax uncertainties is to classify ~~interest to be paid on an underpayment of income taxes and any related penalties~~these amounts as income ~~tax expense if it is determined, in a subsequent period, that a tax position is not more likely than not of being sustained.~~taxes.

CVR and its subsidiaries file U.S. federal and various state income and franchise tax returns. The ~~Company is currently under a~~Company’s U.S. federal income tax ~~examination~~return for its 2005 tax ~~year.~~year is currently under examination. The Company has not been subject to any other U.S. federal, state or local income and franchise tax examinations by taxing authorities with respect to other tax ~~authorities~~returns. The Texas taxing authority has recently contacted the Company to inform them that they will be examining the fertilizer businesses’ Texas franchise tax return for ~~any tax year.~~the 2004 to 2007 franchise periods. The Company’s U.S. federal and

F-80

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

state tax years subject to examination are 2004 to 2007. As of ~~March 31,~~June 30, 2008, no taxing authority has proposed any adjustments to the Company’s tax positions.

The Company’s effective tax ~~rates~~rate for the ~~three~~six months ended ~~March 31,~~June 30, 2008 and 2007 ~~were 23.6%~~was 17.0% and ~~23.4%~~72.1%, respectively, as compared to the federal statutory tax rate of 35%. The effective tax rate is lower than the statutory rate for the six months ended June 30, 2008 due to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program (HPIP). The annualized effective tax rate in 2008 is lower than 2007 due to the correlation between the amount of credits projected to be generated in 2007 in comparison with the projected pre-tax loss levels in 2007.


(11)	Earnings (Loss) Per Share

On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of its common stock. Also, in connection with the initial public offering, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of the subsidiaries of CALLC and CALLC II and all of their refinery and fertilizer assets. This reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with a 628,667.20 for 1 stock split and the merger of two newly formed direct subsidiaries of CVR. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding non-vested shares issued. See Note 1, “Organization and History of Company and Basis of Presentation”.

2008 Earnings Per Share

Earnings per share for the three and six months ended ~~March 31,~~June 30, 2008 is calculated as noted below.

Earnings

Shares

Per Share

Basic earnings per share $ 22,221,000 86,141,291 $ 0.26
Diluted earnings per share $ 22,221,000 86,158,791 $ 0.26


	Three Months Ended						Six Months Ended
	June 30, 2008						June 30, 2008
	Earnings		Shares		Per Share		Earnings		Shares		Per Share

Basic earnings per share	$	30,988,000		86,141,291	$	0.36	$	53,209,000		86,141,291	$	0.62
Diluted earnings per share	$	30,988,000		86,158,791	$	0.36	$	53,209,000		86,158,791	$	0.62

Outstanding stock options totaling ~~18,900~~23,250 common shares were excluded from the diluted earnings per share calculation for the three and six months ended ~~March 31,~~June 30, 2008 as they were antidilutive.

2007 Earnings (Loss) Per Share

The computation of basic and diluted loss per share for the ~~quarter~~three and six months ended ~~March 31,~~June 30, 2007 is calculated on a pro forma basis assuming the capital structure in place after the completion of the initial public offering was in place for the entire period.

~~F-83~~F-81

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Pro forma ~~loss~~earnings (loss) per share for the three and six months ended ~~March 31,~~June 30, 2007 is calculated as noted below. For the ~~three~~six months ended ~~March 31,~~June 30, 2007, 17,500 non-vested shares of common stock ~~and 18,900 common stock options~~ have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive:

March 31, 2007

(unaudited)

Net (loss) $ (154,373,000 )
Pro forma weighted average shares outstanding:
Original CVR shares of common stock 100
Effect of 628,667.20 to 1 stock split 62,866,620
Issuance of shares of common stock to management in exchange for subsidiary shares 247,471
Issuance of shares of common stock to employees 27,100
Issuance of shares of common stock in the initial public offering 23,000,000

Basic weighted average shares outstanding 86,141,291
Dilutive securities — issuance of non-vested shares of common stock to board of directors —

Diluted weighted average shares outstanding 86,141,291

Pro forma basic loss per share $ (1.79 )
Pro forma dilutive loss per share $ (1.79 )


	For the Three Months		For the Six Months
	Ended June 30,		Ended June 30,
	2007		2007
	(Unaudited)		(Unaudited)

Net income (loss)	$	100,066,000	$	(54,307,000	)
Pro forma weighted average shares outstanding:
Original CVR shares of common stock		100		100
Effect of 628,667.20 to 1 stock split		62,866,620		62,866,620
Issuance of shares of common stock to management in exchange for subsidiary shares		247,471		247,471
Issuance of shares of common stock to employees		27,100		27,100
Issuance of shares of common stock in the initial public offering		23,000,000		23,000,000

Basic weighted average shares outstanding		86,141,291		86,141,291
Dilutive securities — issuance of non-vested shares of common stock to board of directors		17,500		—

Diluted weighted average shares outstanding		86,158,791		86,141,291

Pro forma basic earnings ( loss) per share	$	1.16	$	(0.63	)
Pro forma dilutive earnings (loss) per share	$	1.16	$	(0.63	)


(12)	Commitments and Contingent Liabilities

The minimum required payments for the Company’s lease agreements and unconditional purchase obligations are as follows (in thousands):

Operating
Unconditional

Leases

Purchase Obligations

Nine months ending December 31, 2008 $ 2,833 $ 20,757
Year ending December 31, 2009 3,266 28,229
Year ending December 31, 2010 1,680 55,762
Year ending December 31, 2011 948 53,939
Year ending December 31, 2012 196 51,333
Thereafter 10 372,325

$ 8,933 $ 582,345


	Operating		Unconditional
	Leases		Purchase Obligations

Six months ending December 31, 2008	$	1,881	$	14,396
Year ending December 31, 2009		3,293		28,723
Year ending December 31, 2010		2,169		56,256
Year ending December 31, 2011		950		54,432
Year ending December 31, 2012		198		51,827
Thereafter		11		378,330

	$	8,502	$	583,964

The Company leases various equipment, including rail cars, and real properties under long-term operating ~~leases.~~leases, expiring at various dates. In the normal course of business, the Company also has long-term commitments to purchase services such as natural gas, electricity, water and transportation services. For the three months ended ~~March 31,~~June 30, 2008 and 2007, lease expense totaled ~~$1,071,000~~$1,003,000 and ~~$1,007,000,~~$955,000, respectively. For the six months ended June 30, 2008 and 2007, lease expense totaled $2,074,000 and $1,962,000, respectively. The lease agreements have various remaining terms. Some

F-82

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

agreements are renewable, at the Company’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, the Company 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 lawsuits are recognized when the related outcome and costs are probable and can be reasonably estimated. It is possible that ~~Management’s~~management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the

~~F-84~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

opinion of management, the ultimate resolution of the Company’s litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

With respect to the state suit, the District Court of Montgomery County, Kansas conducted an evidentiary hearing on the issue of class certification on October 24 and October 25, 2007 and ruled against the class certification leaving only the original two plaintiffs. ~~To date no other lawsuits have been filed as a result of flood related damages.~~The state suit was later settled with the two original plaintiffs and the case was dismissed.

As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (Consent Order) with the Environmental Protection Agency (EPA) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the Company’s refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The Company ~~is currently~~substantially completed remediating the damage caused by the crude oil discharge in July 2008 and expects ~~its primary~~any remaining minor remedial actions to ~~continue through May 2008 with continuing minor activities for a period thereafter.~~

be completed by December 31, 2008. The Company engaged experts to assess and test the areas affected by the crude oil spill. The Company commenced a program on July 19, 2007 to purchase approximately 330 homes and other commercial properties in connection with the flood and the crude oil release. Total costs recorded to date are $13.4 million, which include costs incurred in 2007 of $13.1 million and costs for the three months ended March 31, 2008 of $0.3 million. Total costs recorded related to personal property claims were approximately $1.7 million, which were all recorded in 2007. Total costs recorded related to estimated commercial property to be purchased and associated claims were approximately $3.6 million, which were all recorded in 2007. The total amount of gross costs recorded for the three months ended March 31, 2008 relatedis currently preparing its final report to the ~~residential and commercial purchase and property claims program were approximately $0.3 million. As~~EPA to satisfy the ~~crude oil spill took place in~~final requirement of the ~~second and third quarter of 2007, no costs associated with the spill were incurred in the first quarter of 2007.~~Consent Order.

As of ~~March 31,~~June 30, 2008, the total gross costs recorded for obligations other than the purchase of homes, commercial properties and related personal property claims approximated $30.0 million. The Company has recorded as of March 31, 2008 total costs (net of anticipated insurance recoveries recorded of $21.4 million) associated with remediation and third party property damage ~~claims resolution~~as of ~~approximately $27.3~~the result of the crude oil discharge for obligations approximated $52.3 million. The Company has not estimated or accrued for ~~because management does not believe it is probable that there will be~~ any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from ~~class action~~ lawsuits related to the ~~flood.~~flood as management does not believe any such fines or penalties assessed would be material nor can be estimated.

~~It is difficult~~The Company also recently received sixteen notices of claims under the Oil Pollution Act from private claimants in an aggregate amount of approximately $4.4 million. No lawsuits related to ~~estimate the ultimate cost of environmental remediation resulting from the crude oil discharge or the cost of third party property damage that the Company will ultimately be required~~

~~F-85~~

these claims have yet been filed.

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to~~While the ~~Condensed Consolidated Financial Statements — (Continued)~~

~~to pay. The~~remediation efforts were substantially completed in July 2008, the costs and damages that the Company will ultimately pay may be greater than the amounts described and projected above. Such excess costs and damages could be material to the consolidated financial statements.

F-83

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Company is seeking insurance coverage for this release and for the ultimate costs for remediation, property damage claims, cleanup, resolution of class action lawsuits, and other claims brought by regulatory authorities. Our primary environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup,” which is subject to a $10 million sub-limit, rather than “property damage,” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While we will vigorously contest the primary carrier’s position, we contend that if that position were upheld, our umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. Each insurer, however, has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses. Although the Company believes that it ~~will recover~~is probable substantial sums under ~~its~~the environmental and liability insurance policies will be recovered, the Company iscan not ~~sure~~be certain of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements. The Company received $10.0 million of insurance proceeds under its environmental insurance policy in 2007.

On July 10, 2008, the Company filed two lawsuits in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the flood and crude oil discharge. One of the lawsuits was filed against the insurance carriers under the environmental policies.

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~~Orders issued 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, CRNF 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 ~~March 31,~~June 30, 2008 and December 31, 2007, environmental accruals of ~~$7,713,000~~$7,150,000 and $7,646,000, 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 ~~$2,789,000~~$2,529,000 and $2,802,000, respectively, included in other current liabilities. The Company’s accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the EPA and are discounted at the appropriate risk free rates at ~~March 31,~~June 30, 2008 and December 31, 2007, respectively. The accruals include estimated closure and post-closure costs of ~~$1,580,000~~$1,512,000 and $1,549,000 for two landfills at ~~March 31,~~June 30, 2008 and December 31,

~~F-86~~F-84

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):

Amount

Nine months ending December 31, 2008 2,617
Year ending December 31, 2009 687
Year ending December 31, 2010 1,556
Year ending December 31, 2011 313
Year ending December 31, 2012 313
Thereafter 3,282

Undiscounted total 8,768
Less amounts representing interest at 3.13% 1,055

Accrued environmental liabilities at March 31, 2008 $ 7,713


	Amount

Six months ending December 31, 2008		2,186
Year ending December 31, 2009		687
Year ending December 31, 2010		1,556
Year ending December 31, 2011		313	��
Year ending December 31, 2012		313
Thereafter		3,282

Undiscounted total		8,337
Less amounts representing interest at 3.80%		1,187

Accrued environmental liabilities at June 30, 2008	$	7,150

The EPA has issued regulations ~~intended~~intending to limit ~~amounts~~the amount 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 spent approximately ~~$17~~$16.8 million in 2007, ~~$79~~$79.0 million in 2006 and ~~$27~~$27.0 million in 2005 to comply with the low-sulfur rules. CVR ~~has~~ spent $2$8.2 million in the first ~~three~~six months of 2008 and, based on information currently available, anticipates spending approximately ~~$17~~$9.7 million in the last ~~nine~~six months of 2008 and ~~$26~~$27.3 million in 2009 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 three month periods ended ~~March 31,~~June 30, 2008 and 2007, capital expenditures were ~~$15,473,000~~$13,888,000 and ~~$50,687,000, respectively,~~$35,894,000, respectively. For the six month periods ended June 30, 2008 and 2007, capital expenditures were $29,361,000 and $86,581,000, respectively. These expenditures 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 Company’s business, financial condition, or results of operations.

F-85

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


(13)	Derivative Financial Instruments

Loss on derivatives, net consisted of the following (in thousands):

Three Months Ended

March 31,

2008

2007

Realized loss on swap agreements $ (21,516 ) $ (8,534 )
Unrealized loss on swap agreements (13,907 ) (119,704 )
Realized loss on other agreements (7,993 ) (2,763 )
Unrealized gain (loss) on other agreements 1,157 (5,332 )
Realized gain on interest rate swap agreements 522 1,241
Unrealized loss on interest rate swap agreements (6,134 ) (1,867 )

Total loss on derivatives $ (47,871 ) $ (136,959 )

~~F-87~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007

Realized loss on swap agreements	$	(52,437	)	$	(88,681	)	$	(73,953	)	$	(97,215	)
Unrealized loss on swap agreements		(15,990	)		(68,787	)		(29,896	)		(188,490	)
Realized loss on other agreements		(13,021	)		(4,824	)		(21,014	)		(7,587	)
Unrealized gain (loss) on other agreements		(1,781	)		3,768			(625	)		(1,563	)
Realized gain (loss) on interest rate swap agreements		(947	)		1,077			(425	)		2,317
Unrealized gain (loss) on interest rate swap agreements		4,871			1,962			(1,263	)		94

Total loss on derivatives, net	$	(79,305	)	$	(155,485	)	$	(127,176	)	$	(292,444	)

CVR is subject to crude oil and finished goods price fluctuations caused by supply and demand conditions, weather, economic conditions, and other ~~factors and to interest rate fluctuations.~~factors. To manage this 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, CALLC, as further described below, entered into certain commodity derivate ~~contracts~~contracts. CVR is also subject to interest rate fluctuations. To manage interest rate risk and to meet the requirements of the credit agreements CALLC entered into an interest rate swap, as further described below as required by the long-term debt agreements.

CVR has adopted SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. 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 loss on derivatives, net in the Consolidated Statements of Operations. For the purposes of segment reporting, realized and unrealized gains or losses related to the commodity derivative contracts are reported in the Petroleum Segment.

Cash Flow Swap

At ~~March 31,~~June 30, 2008, CVR’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, “Related Party Transactions”). The swap agreements were originally executed by CALLC on June 16, 2005 and were required under the terms of the Company’s long-term debt ~~agreements.~~agreement. 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.~~execution. At ~~March 31,~~June 30, 2008 the notional open amounts under the swap agreements were ~~36,190,000~~30,070,250 barrels of crude oil, ~~759,990,000~~631,475,250 gallons of heating oil and ~~759,990,000~~631,475,250 gallons of unleaded gasoline. These positions resulted in unrealized losses for the three months ended March 31, 2008 and 2007 of $13,907,000 and $119,704,000, respectively. The Petroleum Segment recorded $21,516,000 and $8,534,000 in realized losses on these swap agreements for the three month periods ended March 31, 2008 and 2007, respectively.

F-86

The Petroleum Segment also recorded mark-to-market net losses, in loss on derivatives, net exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, of $6,836,000 and $8,095,000, for the three month periods ended March 31, 2008 and 2007, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Interest Rate Swap

At ~~March 31,~~June 30, 2008, CRLLC held derivative contracts known as interest rate swap agreements that converted CRLLC’s floating-rate bank debt into 4.195% fixed-rate debt on a notional amount of ~~$325,000,000.~~$250,000,000. Half of the agreements are held with a related party (as described in Note 15, “Related Party Transactions”), and the other half are held with a financial institution that is a lender under CRLLC’s long-term debt ~~agreements.~~agreement. The swap agreements carry the following terms:


	Notional		Fixed
Period Covered	Amount		Interest Rate

~~June 30, 2007 to March 31, 2008~~		~~325 million~~		~~4.195~~	%
March 31, 2008 to March 30, 2009	$	250 million		4.195	%
March 31, 2009 to March 30, 2010		180 million		4.195	%
March 31, 2010 to June 29, 2010		110 million		4.195	%

~~F-88~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

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 losses on derivatives and quarterly settlements were $5,612,000 and $626,000 for the three month periods ended March 31, 2008 and 2007, respectively.~~


(14)	Fair Value Measurements

In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. This statement established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value, and required additional disclosures about fair value measurements. SFAS 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.

The Company adopted SFAS 157 on January 1, 2008 with the exception of nonfinancial assets and nonfinancial liabilities that were deferred by FASB Staff Position157-2 as discussed in Note 2 to the Condensed Consolidated Financial Statements. As of ~~March 31,~~June 30, 2008, the Company has not applied SFAS 157 to goodwill and intangible assets in accordance with FASB Staff Position157-2.

SFAS 157 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). SFAS 157 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:


	•	Level 1— Quoted prices in active market for identical assets and liabilities


	•	Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities)


	•	Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value)

F-87

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of ~~March 31,~~June 30, 2008 (in thousands):

Level 1

Level 2

Level 3

Total

Cash Flow Swap — $ (13,907 ) — $ (13,907 )
Interest Rate Swap — (6,134 ) — (6,134 )
Other Derivative Agreements — 1,157 — 1,157


	Level 1		Level 2			Level 3		Total

Cash Flow Swap		—	$	(418,306	)		—	$	(418,306	)
Interest Rate Swap		—		(3,133	)		—		(3,133	)
Other Derivative Agreements		—		5,678			—		5,678

The Company’s derivative contracts giving rise to assets or liabilities under Level 2 are valued using pricing models based on other significant observable inputs.


(15)	Related Party Transactions

Management Services Agreements

GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates VII, L.P. and related entity (Kelso) through their majority ownership of CALLC and CALLC II are majority owners of CVR.

On June 24, 2005, CALLC entered into management services agreements with each of GS and Kelso pursuant to which GS and Kelso agreed to provide CALLC with managerial and advisory services.

~~F-89~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

In consideration for these services, an annual fee of $1.0 million was paid to each of GS and Kelso, plus reimbursement for any out-of-pocket expenses. The agreements terminated upon consummation of CVR’s initial public offering on October 26, 2007. Relating to the agreements, $0the Company recorded $544,000 and ~~$538,000 were expensed~~$1,082,000 in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the three and six months ended ~~March 31, 2008 and March 31,~~June 30, 2007, respectively. ~~The Company paid a one-time fee of $5.0 million to each of GS and Kelso by reason of the termination of the~~As these agreements were terminated on October 26, ~~2007.~~2007 there have been no expenses recorded in 2008.

Cash Flow Swap

CALLC entered into certain crude oil, heating oil and gasoline swap agreements with a subsidiary of ~~GS.~~GS, J. Aron & Company (J. Aron). Additional swap agreements with ~~this subsidiary of GS~~J. Aron were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in Note 13, “Derivative Financial Instruments”). These agreements were assigned to ~~Coffeyville Resources LLC, a subsidiary of CVR.~~CRLLC on June 24, 2005. Losses totaling ~~$35,423,000~~$68,427,000 and ~~$128,238,000~~$157,468,000 were recognized related to these swap agreements for the three months ended ~~March 31,~~June 30, 2008 and 2007, respectively, and are reflected in loss on derivatives, net in the Consolidated Statements of Operations. For the six months ended June 30, 2008 and 2007 the Company recognized losses of $103,849,000 and $285,705,000, respectively, which are reflected in loss on derivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at ~~March 31,~~June 30, 2008 and December 31, 2007 includes liabilities of ~~$294,984,000~~$371,583,000 and $262,415,000, respectively, included in current payable to swap counterparty, and ~~$76,411,000~~$46,723,000 and $88,230,000, respectively, included in long-term payable to swap counterparty.

J. Aron Deferral

As a result of the flood and the ~~related~~ temporary cessation of business operations ~~the Company entered into a subsequent letter agreement on July 11, 2007~~ in which the GS subsidiary agreed to defer an additional $43.7 million of the balance owed for the period ending June 30, 2007. This deferral was entered into on the conditions that each of GS and Kelso agreed to guarantee one half of the payment and that interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

~~On July 26,~~ 2007, the Company entered into ~~a letter agreement in which the GS subsidiary agreed~~three separate deferral agreements for amounts owed to ~~defer to September 7, 2007 both the $45.0 million payment due August 7, 2007 along with~~J. Aron. The amount deferred, excluding accrued interest, ~~and the $43.7 million payment due July 25, 2007 with the related accrued interest.~~totaled $123.7 million. These ~~payments~~amounts were ultimately deferred on the conditions that GS and Kelso each agreed to guarantee one half of the payments. Additionally, interest accrues on the amount from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.

On August 23, 2007, the Company entered into an additional letter agreement in which the GS subsidiary agreed to further defer both deferred payment amounts and the related accrued interest with payment being due on January 31, 2008. Additionally, it was further agreed that the $35 million payment to settle hedged volumes through August 15, 2007 would be deferred with payment being due on January 31, 2008. Interest accrues on all deferral amounts through the payment due date at LIBOR plus 1.50%. GS and Kelso have each agreed to guarantee one half of all payment deferrals. The GS subsidiary further agreed to defer these payment amounts to August 31, ~~2008 if the Company closed an initial public offering prior to January 31,~~ 2008. Due to the consummation of the initial public offering on October 26, 2007, these payment amounts are now deferred until August 31, 2008; however, the company is required to use 37.5% of its consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferral amounts. As ~~of March 31, 2008 the Company was not required to pay any~~discussed in further detail below, a portion of the deferred ~~amount.~~amounts may be further deferred until July 31, 2009.

~~F-90~~F-88

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

These deferred payment amounts are included in the Consolidated Balance Sheet at ~~March 31,~~June 30, 2008 in current payable to swap counterparty. The deferred balance owed to the GS subsidiary, excluding accrued interest payable, ~~totalled~~totaled $123.7 million at ~~March 31,~~June 30, 2008. Approximately ~~$4,874,000~~$6,210,000 of accrued interest payable related to the deferred payments is included in other current liabilities at ~~March~~June 30, 2008.

On July 29, 2008, CRLLC entered into a revised letter agreement with the J. Aron to defer further $87.5 million of the deferred payment amounts under the 2007 deferral agreements. The unpaid deferred amounts and all accrued and unpaid interest are due and payable in full on December 15, 2008. If the Company receives proceeds, net of fees, under a convertible debt offering, in an aggregate principal amount of at least $125.0 million by December 15, 2008, the maturity date will be automatically extended to July 31, 2009 provided also that there has been no default by the Company in the performance of its obligations under the revised letter agreement. GS and Kelso each agreed to guarantee one half of the deferred payment of $87.5 million. CRLLC has agreed to repay deferred amounts equal to the sum of $36.2 million plus all accrued and unpaid interest by no later than August 31, 2008.

Beginning on August 31, 2008, interest shall accrue and be payable on the unpaid deferred amount of $87.5 million at the rate of LIBOR plus 2.75%. Under the terms of the deferral, the Company will be required to use the substantial majority of any gross proceeds from the pending convertible debt offering (or other debt) in excess of $125.0 million to prepay a portion of the deferred amounts. There is no certainty that the convertible debt offering will be completed. The revised agreement requires CRLLC to prepay the deferred amount each quarter with the greater of 50% of free cash flow or $5.0 million. Failure to make the quarterly prepayments will result in an increase in the interest rate that accrues on the deferred amounts.

Interest Rate Swap

On June 30, 2005, CALLC entered into three interest-rate swap agreements with ~~the same subsidiary of GS~~J. Aron (as described in Note 13, “Derivative Financial Instruments”). ~~Losses~~Gains totaling ~~$2,813,000~~$1,962,000 and ~~$313,000~~$1,523,000 were recognized related to these swap agreements for the three months ended ~~March 31,~~June 30, 2008 and 2007, respectively, and are reflected in loss on derivatives, net in the Consolidated Statements of Operations. For the six months ended June 20, 2008 and 2007, the Company recognized losses totaling $851,000 and gains totaling $1,211,000, respectively related to these swap agreements which are reflected in loss on derivatives, net, in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at ~~March 31,~~June 30, 2008 and December 31, 2007 includes ~~$1,778,000~~$783,000 and $371,000, respectively, in other current liabilities and ~~$2,223,000~~$783,000 and $557,000, respectively, in other long-term liabilities related to the same agreements.

~~Effective December 30, 2005,~~

Crude Oil Supply Agreement

Coffeyville Resources Refining & Marketing, LLC (CRRM), a subsidiary of the Company ~~entered into~~is a counterparty to a crude oil supply agreement with ~~a subsidiary of GS (Supplier).~~J. Aron. Under the agreement, the parties agreed to negotiate the cost of each barrel of crude oil to be purchased from a third party, and ~~CVR~~CRRM agreed to pay ~~Supplier~~J. Aron 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 initial term of the agreement was to December 31, 2006. CVR and Supplier agreed to extend the term of the supply agreement for an additional 12 month period, from January 1, 2007 through December 31, 2007, and in connection with the extension amended certain terms and conditions of the supply agreement. On December 31, 2007, CVR and supplier entered into an amended and restated crude oil supply agreement. The terms of the agreement remained substantially the same. $241,000Company recorded $0 and $360,000 ~~were recorded~~ on the ~~consolidated balance sheet~~Consolidated Balance Sheets at ~~March 31,~~June 30, 2008 and December 31, 2007, respectively, in prepaid expenses and other current assets for the prepayment of crude oil. In addition, ~~$62,039,000~~$64,960,000 and $43,773,000 were recorded in inventory and ~~$27,909,000~~$17,381,000 and $42,666,000 were recorded in accounts payable at ~~March 31,~~June 30, 2008 and

F-89

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

December 31, 2007, respectively. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the three month ~~period~~periods ended ~~March 31,~~June 30, 2008 and 2007 totaled ~~$766,213,000~~$907,915,000 and ~~$176,307,000,~~$344,607,000, respectively. ~~Interest expense~~For the six months ended June 30, 2008 and 2007, the Company recognized expenses of $1,674,128,000 and $520,914,000, respectively, associated with this agreement ~~for the three month period ended March 31, 2008~~included in cost of product sold (exclusive of depreciation and ~~2007 totaled $14,000 and $(1,029,000), respectively.~~amortization).


(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 SFAS No. 131,Disclosures about Segments of an Enterprise and Related Information. All operations of the segments are located within the United States.

~~F-91~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

Petroleum

Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products including pet coke. CVR sells the pet coke to the Partnership for use in the manufacturing of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For CVR, a per-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of product sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the coke supply agreement that became effective October 24, 2007, is based on the lesser of a coke price derived from the priced received by the fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a coke price index for pet coke. Prior to October 25, 2007 intercompany sales were based upon a price of $15 per ton. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in petroleum net sales were ~~$2,806,000~~$2,800,000 and ~~$580,000~~$1,301,000 for the three months ended ~~March 31,~~June 30, 2008 and 2007, respectively. Intercompany sales included in petroleum net sales were $5,606,000 and $1,881,000 for the six months ended June 30, 2008 and 2007, respectively.

Intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “— Nitrogen Fertilizer” was ~~$5,291,000~~$2,600,000 and ~~$2,829,000~~$5,189,000 for the three months ended ~~March 31,~~June 30, 2008 and 2007, respectively. The intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “— Nitrogen Fertilizer” was $7,891,000 and $8,018,000 for the six months ended June 30, 2008 and 2007, respectively.

Nitrogen Fertilizer

The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was ~~$2,545,000~~$2,325,000 and ~~$850,000~~$1,116,000 for the three months ended ~~March 31,~~June 30, 2008 and 2007, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was $4,871,000 and $1,966,000 for the six months ended June 30, 2008 and 2007, respectively.

Beginning in 2008, the Nitrogen Fertilizer Segment ~~made a change as to~~changed the method of classification of intercompany hydrogen sales to the Petroleum Segment. In 2008, these amounts ~~are~~have been reflected as “Net Sales” for the fertilizer plant. Prior to 2008, the Nitrogen Fertilizer Segment reflected these transactions as a reduction of cost of product sold (exclusive of ~~depreciation~~deprecation and amortization). For the quarters ended ~~March 31,~~June 30, 2008 and 2007, the net sales generated from intercompany hydrogen sales were ~~$5,291,000~~$2,600,000 and ~~$2,829,000,~~$5,189,000, respectively. For the six months ended June 30, 2008 and 2007, hydrogen sales were $7,891,000 and $8,018,000, respectively. As noted above, the net sales of ~~$2,829,000~~

F-90

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

$5,189,000 and $8,018,000 were included as a reduction to the cost of product sold (exclusive of depreciation and amortization) for the three and six months ended June 30, 2007. As these intercompany sales are eliminated, there is no financial statement impact on the consolidated financial statements.

~~F-92~~

~~CVR ENERGY, INC. AND SUBSIDIARIES~~

~~Notes to the Condensed Consolidated Financial Statements — (Continued)~~

Other Segment

Three Months

Ended March 31,

2008

2007

(in thousands)

Net sales
Petroleum $ 1,168,500 $ 352,488
Nitrogen Fertilizer 62,600 38,575
Intersegment eliminations (8,097 ) (580 )

Total $ 1,223,003 $ 390,483

Cost of product sold (exclusive of depreciation and amortization) Petroleum $ 1,035,085 $ 298,460
Nitrogen Fertilizer 8,945 6,060
Intersegment eliminations (7,836 ) (850 )

Total $ 1,036,194 $ 303,670

Direct operating expenses (exclusive of depreciation and amortization) Petroleum $ 40,290 $ 96,674
Nitrogen Fertilizer 20,266 16,738
Other — —

Total $ 60,556 $ 113,412

Net costs associated with flood
Petroleum $ 5,533 $ —
Nitrogen Fertilizer (17 ) —
Other 247 —

Total $ 5,763 $ —

Depreciation and amortization
Petroleum $ 14,877 $ 9,794
Nitrogen Fertilizer 4,477 4,394
Other 281 47

Total $ 19,635 $ 14,235

Operating income (loss)
Petroleum $ 63,618 $ (63,468 )
Nitrogen Fertilizer 26,017 9,319
Other (2,277 ) 165

Total $ 87,358 $ (53,984 )

Capital expenditures
Petroleum $ 22,541 $ 106,501
Nitrogen Fertilizer 2,817 402
Other 798 460

Total $ 26,156 $ 107,363


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2008			2007			2008			2007
	(In thousands)						(In thousands)

Net sales
Petroleum	$	1,459,101		$	808,954		$	2,627,602		$	1,161,442
Nitrogen Fertilizer		58,802			35,760			121,401			74,335
Intersegment eliminations		(5,400	)		(1,301	)		(13,497	)		(1,881	)

Total	$	1,512,503		$	843,413		$	2,735,506		$	1,233,896

Cost of product sold (exclusive of depreciation and amortization)
Petroleum	$	1,285,556		$	570,610		$	2,320,642		$	869,069
Nitrogen Fertilizer		6,846			129			15,791			6,190
Intersegment eliminations		(4,925	)		(1,116	)		(12,762	)		(1,966	)

Total	$	1,287,477		$	569,623		$	2,323,671		$	873,293

Direct operating expenses (exclusive of depreciation and amortization)
Petroleum	$	42,684		$	44,467		$	82,974		$	141,141
Nitrogen Fertilizer		19,652			16,488			39,918			33,226
Other		—			—			—			—

Total	$	62,336		$	60,955		$	122,892		$	174,367

Net costs associated with flood
Petroleum	$	3,369		$	2,035		$	8,902		$	2,035
Nitrogen Fertilizer		34			104			17			104
Other		493			—			740			—

Total	$	3,896		$	2,139		$	9,659		$	2,139

Depreciation and amortization
Petroleum	$	16,273		$	13,285		$	31,150		$	23,079
Nitrogen Fertilizer		4,486			4,397			8,963			8,791
Other		321			275			602			322

Total	$	21,080		$	17,957		$	40,715		$	32,192

Operating income (loss)
Petroleum	$	101,878		$	166,338		$	165,495		$	102,870
Nitrogen Fertilizer		23,145			11,710			49,162			21,029
Other		(2,071	)		(246	)		(4,347	)		(81	)

Total	$	122,952		$	177,802		$	210,310		$	123,818

~~F-93~~F-91

CVR ENERGY, INC. AND SUBSIDIARIES

~~Notes to the Condensed Consolidated Financial Statements~~NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	Three Months				Three Months Ended					Six Months Ended
	Ended		Year Ended		June 30,					June 30,
	March 31,		December 31,		2008		2007			2008		2007
	2008		2007		(In thousands)					(In thousands)

Total assets
Capital expenditures
Petroleum	$	1,352,961	$	1,277,124	$	16,589	$	104,586		$	39,130	$	211,087
Nitrogen Fertilizer		496,326		446,763		6,302		2,244			9,119		2,646
Other		74,304		144,469		588		(140	)		1,386		320

Total	$	1,923,591	$	1,868,356	$	23,479	$	106,690		$	49,635	$	214,053

Goodwill
Petroleum	$	42,806	$	42,806
Nitrogen Fertilizer		40,969		40,969
Other		—		—

Total	$	83,775	$	83,775


	As of June 30,		As of December 31,
	2008		2007

Total assets
Petroleum	$	1,398,869	$	1,277,124
Nitrogen Fertilizer		465,837		446,763
Other		114,476		144,469

Total	$	1,979,182	$	1,868,356

Goodwill
Petroleum	$	42,806	$	42,806
Nitrogen Fertilizer		40,969		40,969

Total	$	83,775	$	83,775


(17)	Subsequent Events

Secondary Offering

CVR filed a registration statement with the SEC on June ~~13,~~19, 2008 in which CVR’s majority stockholders and chairman planned to offer 10 million shares of the Company’s common stock. The Company announced on July 30, 2008 that the majority stockholders elected not to proceed with the proposed secondary offering at the current time due to then-existing market conditions. The registration statement remains on file with the SEC, and the selling stockholders may elect to proceed with the equity offering in the future.

SemGroup L.P Bankruptcy

Subsequent to June 30, 2008 SemGroup, L.P., a customer, filed a petition for bankruptcy under Chapter 11 of the Bankruptcy Code. At June 30, 2008, SemGroup, L.P. owed the Company ~~announced that~~approximately $3.7 million. While the ~~managing general partner~~Company will seek payment of the ~~Partnership had decided~~pre-petition amount, the Company believes the likelihood of recovery is no longer probable. The receivable balance of $3.7 million was fully reserved as of June 30, 2008. The Company has no further exposure related to ~~postpone indefinitely~~ the ~~Partnership’s initial public offering. The Partnership has notified the SEC that it intends to withdraw the registration statement it filed in February 2008.~~bankruptcy filing of SemGroup, L.P.

Insurance Renewal

On July ~~10,~~1, 2008, we renewedand/or renegotiated our primary lines of insurance including workers compensation, automobile and general liability, umbrella and excess liability, property and business interruption, cargo, terrorism and crime. Due to a combination of factors including replacement cost escalation, our outstanding claim related to the flood of June 2007 and flooding in the Midwest in the spring of 2008, the cost of these primary lines of insurance, especially with respect to

F-92

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONDENSED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

property and business interruption coverage, increased substantially. For the annual period of July 1, 2008 to July 1, 2009, the cost for these primary lines of coverage increased approximately 45% to $15.7 million from $10.8 million for the annual period of July 1, 2007 to July 1, 2008. The Company entered into an insurance premium financing agreement in July 2008 to finance $10.0 million of the $15.7 million insurance premium.

Convertible Notes Offering

On June 19, 2008, CVR filed ~~two lawsuits~~a registration statement with the SEC in connection with a proposed offering of $125.0 million aggregate principal amount of CVR’s Convertible Senior Notes due 2013. CVR filed an amendment to the aforementioned registration statement on July 25, 2008. Under the proposed terms, CVR may sell up to an additional $18.75 million aggregate principal amount of notes upon exercise of an over-allotment option that CVR expects to grant to the underwriters in connection with the offering.

As proposed, the notes will be convertible, under certain circumstances, into cash, shares of CVR common stock or a combination of cash and shares, at CVR’s election. It is CVR’s current intent to settle the principal amount of any conversions in cash for the principal amount of the notes and a combination of cash and shares for the excess, if any, of the conversion value above the principal amount. The coupon, conversion price and other terms of the notes will be determined at the time of pricing the offering. CVR intends to use the net proceeds from the offering for general corporate purposes, which may include using a portion of the proceeds for future capital investments. Any proceeds, net of fees, in excess of $125.0 million will be used to prepay a portion of the amounts owed to J. Aron under the revised deferral agreement. A portion of the proceeds will be used to purchase government securities in an amount equal to the first six interest payments due under the notes. The government securities will be deposited into an escrow account under a pledge and escrow agreement which will secure payment of the first six scheduled interest payments on the notes.

There can be no assurance that any such offering will be consummated on the terms discussed in the United States District Court for the District of Kansas against certain of the Company’s insurance carriers with regard to the Company’s insurance coverage for the 2007 flood and crude oil discharge. See Note 9, “Flood and Insurance Related Matters” for additional information.registration statement or at all.

~~F-94~~F-93

(CVR ENERGY NITROGEN FERTILIZER BUSINESS)

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 notes offered hereby, but only under circumstances 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		29
Cautionary Note Regarding Forward-Looking Statements		73
Ratio of Earnings to Fixed Charges		76
Use of Proceeds		77
Dividend Policy		78
Market Price of Our Common Stock		79
Capitalization		80
Selected Historical Consolidated Financial Data		81
Management’s Discussion and Analysis of Financial Condition and Results of Operations		88
Industry Overview		~~150~~152
Business		~~158~~160
Flood and Crude Oil Discharge		~~182~~184
Management		~~187~~189
Compensation Discussion and Analysis		~~194~~196
Principal Stockholders		~~222~~224
Certain Relationships and Related Party Transactions		~~226~~228
The Nitrogen Fertilizer Limited Partnership		~~235~~237
Description of Our Indebtedness and the Cash Flow Swap		~~272~~274
Description of the Notes		~~279~~281
Description of Capital Stock		~~308~~310
Shares Eligible for Future Sale		~~311~~313
Material United States Federal Income Tax Considerations		~~312~~314
Underwriting		~~321~~323
Legal Matters		~~325~~327
Experts		~~325~~327
Where You Can Find More Information		~~325~~327
Glossary of Selected Terms		~~326~~328
Index to Consolidated Financial Statements		F-1

$125,000,000

CVR Energy, Inc.

% Convertible Senior
Notes Due 2013

PROSPECTUS

Goldman, Sachs & Co.

Citi

Deutsche Bank Securities

Credit Suisse

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 and the Financial Industry Regulatory Authority (“FINRA”) filing fee.


SEC registration fee	$	5,650	$	5,650
FINRA filing fee		14,875		14,875
Accounting fees and expenses		300,000		425,000
Legal fees and expenses		450,000		625,000
Printing and engraving expenses		350,000		500,000
Transfer agent and registrar fees and expenses		15,000		15,000
Miscellaneous expenses		14,475		14,475

Total	$	1,150,000	$	1,600,000


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.

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

II-1

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, and the underwriters will contain indemnification and contribution provisions.


Item 15.	*Recent Sales of Unregistered Securities.*

We issued 100 shares of common stock to Coffeyville Acquisition LLC in September 2006 for nominal consideration. The issuance was exempt from registration in accordance with Section 4(2) of the Securities Act of 1933, as amended. We issued 247,471 shares of common stock to our chief executive officer in October 2007 in exchange for shares he owned in Coffeyville Nitrogen Fertilizer, Inc. and Coffeyville Refining and Marketing Holdings, Inc. The issuance was exempt from registration in accordance with Rule 701 under the Securities Act of 1933, as amended.


Item 16.	*Exhibits and Financial Statement Schedules.*

(a) The exhibits to this Registration Statement are listed on the Exhibit Index page hereof, which is incorporated by reference in this Item 16.

(b) The financial statement schedules are omitted because they are inapplicable or the requested information is shown in the consolidated financial statements of CVR Energy, Inc. or related notes thereto.


Item 17.	*Undertakings.*

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 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.

II-2

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.

II-3

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 2425^th day of ~~July~~August 2008.

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)	~~July 24,~~August 25, 2008

* James T. Rens	Chief Financial Officer (Principal Financial and Accounting Officer)	~~July 24,~~August 25, 2008

* Scott L. Lebovitz	Director	~~July 24,~~August 25, 2008

* Regis B. Lippert	Director	~~July 24,~~August 25, 2008

* George E. Matelich	Director	~~July 24,~~August 25, 2008

* Steve A. Nordaker	Director	~~July 24,~~August 25, 2008

* Stanley de J. Osborne	Director	~~July 24,~~August 25, 2008

* Kenneth A. Pontarelli	Director	~~July 24,~~August 25, 2008

* Mark Tomkins	Director	~~July 24,~~August 25, 2008

*By: /s/ John J. Lipinski John J. Lipinski, as attorney-in-fact

II-4

EXHIBIT INDEX

Number

Exhibit Title

1 .1 Form of Underwriting Agreement.
3 .1** Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
3 .2** Amended and Restated Bylaws of CVR Energy, Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
4 .1** Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
4 .2 Form of Indenture for the Convertible Senior Notes due 2013.
4 .3 Form of Convertible Senior Notes due 2013 (see 4.2).
5 .1 Opinion of Fried, Frank, Harris, Shriver & Jacobson LLP.
10 .1** Second Amended and Restated Credit and Guaranty Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .1.1** First Amendment to Second Amended and Restated Credit and Guaranty Agreement, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .2** Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, 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, as collateral agent (filed as Exhibit 10.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .3†** Swap agreements with J. Aron & Company (filed as Exhibit 10.5 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .3.1** Letter agreements between Coffeyville Resources, LLC and J. Aron & Company, dated as of June 26, 2007, July 11, 2007, July 26, 2007 and August 23, 2007 (filed as Exhibit 10.5.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .4†** License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between Texaco Development Corporation and Farmland Industries, Inc., as amended (filed as Exhibit 10.4 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .5†** Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The Linde Group (f/k/a The BOC Group, Inc.) and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .6†** Amended and Restated Crude Oil Supply Agreement, dated as of December 31, 2007, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K, filed on January 7, 2008 and incorporated by reference herein).


Number			Exhibit Title

	1	.1**	Form of Underwriting Agreement.
	3	.1**	Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	3	.2**	Amended and Restated Bylaws of CVR Energy, Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	4	.1**	Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	4	.2	Form of Indenture for the Convertible Senior Notes due 2013.
	4	.3**	Form of Convertible Senior Notes due 2013 (see 4.2).
	5	.1**	Opinion of Fried, Frank, Harris, Shriver & Jacobson LLP.
	10	.1**	Second Amended and Restated Credit and Guaranty Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.1.1**	First Amendment to Second Amended and Restated Credit and Guaranty Agreement, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.2**	Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, 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, as collateral agent (filed as Exhibit 10.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.3†**	Swap agreements with J. Aron & Company (filed as Exhibit 10.5 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.3.1**	Letter agreements between Coffeyville Resources, LLC and J. Aron & Company, dated as of June 26, 2007, July 11, 2007, July 26, 2007 and August 23, 2007 (filed as Exhibit 10.5.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.3.2**	Letter agreement between Coffeyville Resources, LLC and J. Aron & Company, dated as of July 29, 2008 (filed as exhibit 10.1 to the Company’s Current Report onForm 8-K filed on August 4, 2008 and incorporated by reference herein).
	10	.4†**	License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between Texaco Development Corporation and Farmland Industries, Inc., as amended (filed as Exhibit 10.4 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.5†**	Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The Linde Group (f/k/a The BOC Group, Inc.) and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).


Number			Exhibit Title

	10	.6†**	Amended and Restated Crude Oil Supply Agreement, dated as of December 31, 2007, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K, filed on January 7, 2008 and incorporated by reference herein).
	10	.6.1**	Amendment Agreement, dated as of July 31, 2008, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.3 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2008 and incorporated by reference herein).
	10	.7†**	Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.14 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.8**	Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (filed as Exhibit 10.15 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.9**	Purchase, Storage and Sale Agreement for Gathered Crude, dated as of March 20, 2007, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.22 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.10**	Stockholders Agreement of CVR Energy, Inc., dated as of October 16, 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (filed as Exhibit 10.20 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.11**	Registration Rights Agreement, dated as of October 16, 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (filed as Exhibit 10.21 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.12**	Management Registration Rights Agreement, dated as of October 24, 2007, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.27 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.13**	Stock Purchase Agreement, dated as of May 15, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.13.1**	Amendment No. 1 to the Stock Purchase Agreement, dated as of June 24, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.13.2**	Amendment No. 2 to the Stock Purchase Agreement, dated as of July 25, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.14**	First Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated as of October 24, 2007, by and among CVR GP, LLC, CVR Special GP, LLC and Coffeyville Resources, LLC (filed as Exhibit 10.4 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.15**	Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.5 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).


Number			Exhibit Title

	10	.16**	Cross Easement Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.17**	Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.7 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.17.1**	Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.17.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.17.2**	Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended June 30, 2008 and incorporated by reference herein).
	10	.18**	Feedstock and Shared Services Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.8 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.19**	Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.9 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.20**	Services Agreement, dated as of October 25, 2007, by and among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and CVR Energy, Inc. (filed as Exhibit 10.10 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.21**	Omnibus Agreement, dated as of October 24, 2007 by and among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR Partners, LP (filed as Exhibit 10.11 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.22**	Contribution, Conveyance and Assumption Agreement, dated as of October 24, 2007, by and among Coffeyville Resources, LLC, CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP (filed as Exhibit 10.26 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.23**	Registration Rights Agreement, dated as of October 24, 2007, by and among CVR Partners, LP, CVR Special GP, LLC and Coffeyville Resources, LLC (filed as Exhibit 10.24 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.24**	Amended and Restated Employment Agreement, dated as of January 1, 2008, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.24 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.25**	Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and Stanley A. Riemann (filed as Exhibit 10.25 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.26**	Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and James T. Rens (filed as Exhibit 10.26 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).

Number

Exhibit Title

10 .17.1** Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.17.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .17.2 Second Supplement to Environmental Agreement, dated as of July 23, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC.
10 .18** Feedstock and Shared Services Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.8 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .19** Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.9 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .20** Services Agreement, dated as of October 25, 2007, by and among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and CVR Energy, Inc. (filed as Exhibit 10.10 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .21** Omnibus Agreement, dated as of October 24, 2007 by and among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR Partners, LP (filed as Exhibit 10.11 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .22** Contribution, Conveyance and Assumption Agreement, dated as of October 24, 2007, by and among Coffeyville Resources, LLC, CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP (filed as Exhibit 10.26 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .23** Registration Rights Agreement, dated as of October 24, 2007, by and among CVR Partners, LP, CVR Special GP, LLC and Coffeyville Resources, LLC (filed as Exhibit 10.24 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .24** Amended and Restated Employment Agreement, dated as of January 1, 2008, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.24 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .25** Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and Stanley A. Riemann (filed as Exhibit 10.25 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .26** Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and James T. Rens (filed as Exhibit 10.26 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .27** Employment Agreement, dated as of October 23, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .27.1** First Amendment to Employment Agreement, dated as of November 30, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).


Number			Exhibit Title

	10	.27**	Employment Agreement, dated as of October 23, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.27.1**	First Amendment to Employment Agreement, dated as of November 30, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.28**	Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and Robert W. Haugen (filed as Exhibit 10.28 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.29**	CVR Energy, Inc. 2007 Long Term Incentive Plan (filed as Exhibit 10.13 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.29.1**	Form of Nonqualified Stock Option Agreement (filed as Exhibit 10.33.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.29.2**	Form of Director Stock Option Agreement (filed as Exhibit 10.33.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.29.3**	Form of Director Restricted Stock Agreement (filed as Exhibit 10.33.3 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.30**	Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), as amended (filed as Exhibit 10.3 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.31**	Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (filed as Exhibit 10.12 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.32**	Stockholders Agreement of Coffeyville Nitrogen Fertilizer, Inc., dated as of March 9, 2007, by and among Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Acquisition LLC and John J. Lipinski (filed as Exhibit 10.17 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.33**	Stockholders Agreement of Coffeyville Refining & Marketing Holdings, Inc., dated as of August 22, 2007, by and among Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Acquisition LLC and John J. Lipinski (filed as Exhibit 10.18 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.34**	Subscription Agreement, dated as of March 9, 2007, by Coffeyville Nitrogen Fertilizers, Inc. and John J. Lipinski (filed as Exhibit 10.19 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.35**	Subscription Agreement, dated as of August 22, 2007, by Coffeyville Refining & Marketing Holdings, Inc. and John J. Lipinski (filed as Exhibit 10.20 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated herein by reference).
	10	.36**	Amended and Restated Recapitalization Agreement, dated as of October 16, 2007, by and among Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc. (filed as Exhibit 10.3 to the Company’s Quarterly Report onForm 10-Q for the quarterly period September 30, 2007 and incorporated by reference herein).
	10	.37**	Subscription Agreement, dated as of October 16, 2007, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.21 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.38**	Redemption Agreement, dated as of October 16, 2007, by and among Coffeyville Acquisition LLC and the Redeemed Parties signatory thereto (filed as Exhibit 10.19 to the Company’s Quarterly Report on~~Form 10-Q~~ ~~for the quarterly period ended September 30, 2007 and incorporated by reference herein).~~

Number

Exhibit Title

10 .39** Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.4 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .39.1** Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.15 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .40** First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.16 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .40.1** Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.17 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .41** Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition III LLC, dated as of February 15, 2008 (filed as Exhibit 10.41 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
10 .42** Letter Agreement, dated as of October 24, 2007, by and among Coffeyville Acquisition LLC, Goldman, Sachs & Co. and Kelso & Company, L.P. (filed as Exhibit 10.23 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
10 .43** Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Refining & Marketing, LLC and various unions of the Metal Trades Department (filed as Exhibit 10.46 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .44** Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Crude Transportation, LLC and the Paper, Allied-Industrial, Chemical & Energy Workers International Union (filed as Exhibit 10.47 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
10 .45** Consulting Agreement dated May 2, 2008, by and between General Wesley Clark and CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2008 and incorporated by reference herein).
10 .46 Form of Pledge and Escrow Agreement
12 .1** Computation of Ratio of Earnings to Fixed Charges.
21 .1** List of Subsidiaries of CVR Energy, Inc. (filed as Exhibit 21.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
23 .1 Consent of KPMG LLP.
23 .2 Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1).
23 .3** Consent of Blue, Johnson & Associates.
25 .1 Statement of Eligibility of Trustee onForm T-1.


Number			Exhibit Title

	10	.38**	Redemption Agreement, dated as of October 16, 2007, by and among Coffeyville Acquisition LLC and the Redeemed Parties signatory thereto (filed as Exhibit 10.19 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.39**	Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.4 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.39.1**	Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.15 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.40**	First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.16 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.40.1**	Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.17 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.41**	Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition III LLC, dated as of February 15, 2008 (filed as Exhibit 10.41 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	10	.42**	Letter Agreement, dated as of October 24, 2007, by and among Coffeyville Acquisition LLC, Goldman, Sachs & Co. and Kelso & Company, L.P. (filed as Exhibit 10.23 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein).
	10	.43**	Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Refining & Marketing, LLC and various unions of the Metal Trades Department (filed as Exhibit 10.46 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.44**	Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Crude Transportation, LLC and the Paper, Allied-Industrial, Chemical & Energy Workers International Union (filed as Exhibit 10.47 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein).
	10	.45**	Consulting Agreement dated May 2, 2008, by and between General Wesley Clark and CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2008 and incorporated by reference herein).
	10	.46**	Form of Pledge and Escrow Agreement
	12	.1	Computation of Ratio of Earnings to Fixed Charges.
	21	.1**	List of Subsidiaries of CVR Energy, Inc. (filed as Exhibit 21.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein).
	23	.1	Consent of KPMG LLP.
	23	.2**	Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1).
	23	.3**	Consent of Blue, Johnson & Associates.
	25	.1**	Statement of Eligibility of Trustee onForm T-1.


**		Previously filed.


†		Confidential treatment has been granted for certain provisions of this exhibit by the Securities and Exchange Commission.


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


Large accelerated filer o	Accelerated filer o	Non-accelerated filer þ	Smaller reporting company o
		(Do not check if a smaller reporting company)


	Per Note		Total


Public offering price		%	$

Underwriting discount		%	$

Proceeds, before expenses, to us		%	$


Issuer		CVR Energy, Inc.

Notes Offered		$125,000,000 in aggregate original principal amount of % Convertible Senior Notes due 2013 (the “notes”), which may increase to up to $143,750,000 in aggregate principal amount of the notes if the underwriters exercise in full their option to purchase additional notes solely to cover over-allotments.

Maturity Date		The notes will mature on , 2013, unless earlier converted or repurchased.


~~Base~~ ~~Conversion~~ ~~Rate~~		+ ((		~~(Daily VWAP of our common stock on such date~~ ~~− Base Conversion Price)~~ ~~Daily VWAP of our common stock on such date~~		) x		~~Incremental Share~~ ~~Factor~~		)


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


(1)		Includes $18,750,000 principal amount of notes which the underwriters have the option to purchase solely to cover over-allotments.


(3)		An indeterminate number of shares of common stock may be issued from time to time upon conversion of the notes.


(4)		No additional consideration will be received for the common stock issuable upon conversion of the notes. No additional registration fee is required pursuant to Rule 457(i) under the Securities Act.


	•	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.

	•	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.


	•	Crack spreads are increasing in terms of absolute value with dramatically higher crude oil costs, but are substantially narrower as a percentage of crude oil costs, which has reduced oil refinery profitability.


	•	A shift in market fundamentals for global petroleum refiners. The most profitable end products for refiners have shifted from gasoline products to distillate products.

	•	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.

	•	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.


	•	Nitrogen fertilizer prices in the United States are experiencing all-time highs. Based on industry projections, including from Blue Johnson, these high prices are forecast to continue for the next several years.

	•	Nitrogen fertilizer prices have been decoupled from their historical correlation with natural gas prices in recent years, and increased substantially more than natural gas prices in 2007 and


		2008 (based on data provided by Blue Johnson). Moreover, natural gas prices are currently higher in the United States and Canada compared to prevailing prices in the years prior to 2004. High North American natural gas prices contribute to the currently high prices for nitrogen-based fertilizers in the United States.


	•	The Energy Independence and Security Act of 2007 requires fuel producers to use at least 36 billion gallons of biofuel (such as ethanol) by 2022, a nearly five-fold increase over current levels. The increase in grain production necessary to meet this requirement is expected to result in rising demand for nitrogen-based fertilizers.

	•	World population and economic growth, combined with changing dietary trends in many nations, has significantly increased demand for U.S. agricultural production and exports. Increasing U.S. crop production requires higher application rates of fertilizers, primarily nitrogen-based fertilizers.


	•	Debt was used as part of the acquisition financing in June 2005 which required the introduction of a financial risk management tool intended to mitigate a portion of the 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.


*		CVR GP, LLC, which we refer to as Fertilizer GP, is the managing general partner of CVR Partners, LP. As managing general partner, Fertilizer GP holds incentive distribution rights, or IDRs, which entitle it to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases its distributions above an amount specified in the limited partnership agreement. The IDRs will only be payable after the Partnership has distributed all aggregated adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009.


Interest		We will pay interest on the notes at a rate of % per year, payable semi-annually in arrears in cash on and of each year, beginning on , 2009.


Interest Escrow		Until , 2011, our interest payment obligations under the notes will be secured by a pledge of the escrow account described below and the assets therein pursuant to a pledge and escrow agreement. From the proceeds of this offering, the underwriters will, on our behalf, purchase and deposit with the escrow agent on the closing date of this offering government securities (as defined herein). Approximately $ million (plus an additional approximately $ million if the underwriters’ over-allotment option is exercised in full) of the proceeds from this offering will be used to purchase government securities to be deposited in the escrow account and pledged to the trustee as security for our obligations under the notes and the indenture. The notes will not otherwise be secured. See “Description of the Notes — Interest Escrow.”


Ranking		The notes will be our general senior unsecured obligations (except as described above under “— Interest Escrow”), ranking equal in right of payment to all of our senior unsecured indebtedness; senior in right of payment to indebtedness that is contractually subordinated to the notes; structurally subordinated to (i) all existing and future claims of our subsidiaries’ creditors, including trade creditors, and (ii) any preferred stock which our subsidiaries may issue to the extent of its liquidation preference; and effectively subordinated to any of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness.


		The indenture for the notes will not restrict us or our subsidiaries from incurring additional debt or other liabilities, including secured debt. We are a holding company. Our subsidiaries conduct all of our operations and own substantially all of our assets. As a result, we are dependent on the cash flow of our subsidiaries to meet our debt obligations. None of our subsidiaries will guarantee any of our obligations under, or have any obligation to pay amounts due on, the notes. At June 30,


		2008, our subsidiaries had $508.3 million aggregate principal amount of long-term debt outstanding (all of which was secured) and could borrow an additional $91.1 million under our credit facility. If our subsidiaries were to incur additional debt or liabilities, our ability to pay our obligations on the notes, including cash payments upon conversion or repurchase, could be adversely affected.


Conversion Rights		Holders may convert their notes, in whole or in part, at any time prior to the close of business on the scheduled trading day (as defined herein) immediately preceding , 2013, at the applicable conversion rate (as defined herein), under the following circumstances:


		• during the five business day period after any five consecutive trading day period (the “measurement period”) during which the trading price (as defined herein) per $1,000 in principal amount of the notes for each day of the measurement period was less than 98% of the product of the last reported sale price (as defined herein) of our common stock and the ~~trading price~~applicable conversion rate on such date;


		• during any calendar quarter (and only during such calendar quarter) after the calendar quarter ending on September 30, 2008, if the last reported sale price of our common stock for 20 or more trading days in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the ~~base~~applicable conversion price in effect on the last trading day of the immediately preceding calendar quarter; or


		• upon the occurrence of specified corporate events described under “Description of the Notes — Conversion Rights — Conversion upon Specified Corporate Events.”


		~~The “~~~~trading price conversion rate~~” on any day will be (i) if the last reported sale price of our common stock on the trading day immediately preceding such day is less than or equal to the base conversion price (as defined herein), the base conversion rate or (ii) if such last reported sale price of our common stock is greater than the base conversion price, the base conversion rate plus a number of shares equal to the product of (a) the incremental share factor and (b) (1) the difference between such last reported sale price and the base conversion price divided by (2) such last reported sale price.


		At the option of the holder, regardless of the foregoing circumstances, a holder may convert its notes at any time on or after , 2013 but prior to the close of business on the scheduled trading day immediately preceding the maturity date of the notes.


		The “~~base~~ conversion rate” for the notes will initially be shares of common stock per $1,000 in principal amount of notes, which is equivalent to an initial ~~base~~ conversion price of approximately $ per share of common stock, subject to


		certain adjustments as described under “Description of the Notes — Conversion Rights — ~~Base~~ Conversion Rate Adjustments.”


		~~For purposes of calculation of the daily conversion value or the daily share settlement rate, as applicable, the “~~~~applicable conversion rate~~~~” for the relevant VWAP trading day (as defined herein) will be determined as follows:~~


		• if the daily VWAP (as defined herein) of our common stock on such date is less than or equal to the base conversion price, the applicable conversion rate for such date will be equal to the base conversion rate; and


		~~• if the daily VWAP of our common stock on such date is greater than the base conversion price, the applicable conversion rate for such date will be equal to the following:~~


		In addition, if a holder elects to convert his notes in connection with a make-whole fundamental change (as defined herein), we will increase the ~~base~~ conversion rate with respect to such holder’s notes by an additional number of shares of common stock as described under “Description of the Notes — Conversion Rights — Adjustment to Shares Delivered upon Conversion in Connection with a Make-Whole Fundamental Change.” No additional shares will be added to the ~~base~~ conversion rate if the price paid per share of our common stock in connection with the make-whole fundamental change is greater than $ per share or if such price is less than $ per share (in each


		case, subject to adjustment). Notwithstanding the foregoing, in no event will the applicable conversion rate of the notes exceed shares of common stock per $1,000 in principal amount of notes (subject to adjustment).