CVR ENERGY INC - Quarter Report: 2007 September (Form 10-Q)

 

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

 

Form 10-Q

 

 

 

Commission file number 001-33492

 

 

CVR ENERGY, INC.

(Exact name of registrant as specified in its charter)

 

 

 

 

Registrant’s telephone number, including area code:

(281) 207-3200

 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.  (1) Yes þ  No o.     (2) Yes o  No þ.

 

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

 

Large accelerated filer o     Accelerated Filer o     Non-accelerated Filer þ

 

Indicate by check mark whether the registrant is a shell company (as defined by Rule 12b-2 of the Exchange Act).  Yes o     No þ.

 

There were 86,141,291 shares of the registrant’s Common Stock outstanding at December 4, 2007.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

INDEX TO QUARTERLY REPORT ON FORM 10-Q

For The Quarter Ended September 30, 2007

 

 

PART I. FINANCIAL INFORMATION

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONSOLIDATED BALANCE SHEETS

 

 

The accompanying notes are an integral part of the condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

 

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

 

 

The accompanying notes are an integral part of these condensed consolidated financial statements.

CVR ENERGY, INC. AND SUBSIDIARIES

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
SEPTEMBER 30, 2007
(UNAUDITED)

 

 

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. See Note 15 (“Business Segments”) for a further discussion of the company’s business segments.

 

CALLC formed CVR Energy, Inc. (CVR) 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 will record a write-off of unamortized deferred financing fees of approximately $1.3 million in the fourth quarter of 2007.

 

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 mergers of two newly formed direct subsidiaries of

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding restricted shares issued.

 

On October 24, 2007, 17,500 shares of restricted stock having a value of $365,400 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. 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 and fair value will be measured using an option-pricing model at the date of grant. 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 will be $565,848 related to the shares issued.

 

Nitrogen Fertilizer Limited Partnership

 

In conjunction with the consummation of the 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). 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.

 

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’s ownership of the special GP interest, it will initially own all of the interests in the Partnership (other than the managing general partner interest and associated IDRs described below) and will initially be entitled to all cash that is distributed by the Partnership. The managing general partner will not be entitled to participate in Partnership distributions except in respect of associated incentive distribution rights, or IDRs, which entitle the managing general partner to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases its distributions above an amount specified in the partnership agreement. 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 partnership agreement, generated by the Partnership during the period from its formation through December 31, 2009 has been distributed in respect of the special GP interests, which CVR will hold, and/or the Partnership’s common and subordinated interests (none of which are yet outstanding, but

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

which would be issued if the Partnership issues equity in the future). In addition, there will be no distributions paid on the managing general partner’s IDRs for so long as the Partnership or its subsidiaries are guarantors under CRLLC’s credit facility. 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.

 

Basis of Presentation

 

The accompanying unaudited condensed consolidated financial statements were prepared in accordance with U.S. generally accepted accounting principles (GAAP) and in accordance with the rules and regulations of the Securities and Exchange Commission. The consolidated financial statements include the accounts of CVR Energy, Inc. and its wholly-owned subsidiaries. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under GAAP have not been included pursuant to such rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 2006 audited financial statements and notes thereto of CVR.

 

In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of December 31, 2006 and September 30, 2007, the results of operations for the three and nine months ended September 30, 2006 and 2007, and the cash flows for the nine months ended September 30, 2006 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, 2007 or any other interim period. The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that 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.

 

 

Earnings per share are calculated on a pro forma basis, based upon the actual number of shares outstanding at the time of the initial public offering in October 2007. Pro forma earnings per share have been based upon the transactions that occurred to effect the initial public offering, including the merger of Refining Holdco and CNF with two of CVR’s direct wholly owned subsidiaries; the effect of the 628,667.20 for 1 stock split of CVR’s common stock; the issuance of 247,471 shares of common stock to CVR’s chief executive officer in exchange for his shares in two of CVR’s subsidiaries; the issuance of 27,100 shares of common stock to CVR’s employees; and CVR’s issuance of 23,000,000 shares of common stock in the offering. For the nine month period ended September 30, 2007, the 17,500 nonvested restricted shares of CVR common stock to be issued to two directors have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such shares in the number of weighted average shares outstanding would be antidilutive.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Pro forma earnings (loss) per share for the three and nine month periods ended September 30, 2006 and 2007 is calculated as follows:

 

 

The pro forma balance sheet assumes the following transactions occurred on September 30, 2007:

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

 

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 statement is effective for financial statements issued for 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 SFAS No. 159, The Fair Value Option for Financial Assets and Financial Liabilities (SFAS 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 SFAS No. 107, Disclosures about Fair Value of Financial Instruments. SFAS 159 is effective for fiscal years beginning after November 15, 2007. The Company is currently evaluating the potential adoption impact that SFAS 159 will have on its financial statements.

 

 

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 as described below. Subsequent to September 30, 2007 and in connection with the split of CALLC into two entities, management’s equity interest in CALLC 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. As of September 30, 2007, 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 Emerging Issues Task Force (EITF) Topic No. D-98, Classification and Measurement of Redeemable Securities, common units held by management were initially recorded at fair value at the date of issuance and have been classified in temporary equity as Management Voting Common Units Subject to Redemption (capital subject to redemption) in the accompanying condensed consolidated balance sheets. The put rights and call rights were eliminated in October 2007.

 

CVR accounted for changes in redemption value of management common units in the period the changes occurred and adjusted the carrying value of the capital subject to redemption to equal the redemption value at the end of each reporting period with an equal and offsetting adjustment to Members’ Equity. None of the capital subject to redemption was redeemable at December 31, 2006 or September 30, 2007.

 

At September 30, 2007, the capital subject to redemption was revalued through an independent appraisal process, and the value was determined to be $43.05 per unit. The valuation was based upon a calculation utilizing

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

the initial public offering share price. This methodology provided the best estimate of the value as it was based upon actual information supporting the value. The recognition of the value of $43.05 per unit increased the carrying value of the capital subject to redemption by $2,035,354 for the nine months ended September 30, 2007 with an equal and offsetting decrease to Members’ Equity. The increase was primarily attributable to favorable market conditions in the fertilizer sector.

 

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. 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 $3,604,950. Pursuant to the forfeiture schedule described below, the Company is recognizing compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in-substance, multiple awards. Compensation expense of $177,943 and $743,137 were recognized for the three and nine month periods ending September 30, 2007, respectively. Compensation expenses of $291,679 and $865,527 were recognized for the three and nine month periods ending September 30, 2006, respectively. Significant assumptions used in the valuation were as follows:

 

 

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. 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 the company’s cash flow projections resulted in an estimated fair value of the override operating units on December 28, 2006 was $472,648. 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. Pursuant to the forfeiture schedule described below, the Company is recognizing compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in-substance, multiple awards. Compensation expense for the three and nine month periods ended September 30, 2007 was $40,532 and $236,433, respectively. Significant assumptions used in the valuation were as follows:

 

 

Override operating units participate in distributions from CALLC (and, following the split of CALLC into two entities, CALLC II) in proportion to the number of total common, non-forfeited override operating and participating override value units issued. Distributions to override operating units will be reduced until the total cumulative reductions are equal to the benchmark value. Override operating units are forfeited upon termination of

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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:

 

 

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 nonvoting override value units to certain management members holding common units. 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 $4,064,776. For the override value units, CVR is recognizing compensation expense ratably over the implied service period of 6 years. Compensation expense of $508,097 was recognized for both the nine months ending September 30, 2006 and 2007. Compensation expense of $169,366 was recognized for both the three months ending September, 30, 2006 and 2007. Significant assumptions used in the valuation were as follows:

 

 

144,966 override value units at a benchmark value of $34.72 per unit

 

On December 28, 2006, CALLC issued additional nonvoting override value units to a certain management member who holds common units. 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 the Company’s cash flow projections resulted in an estimated fair value of the override value units on December 28, 2006 of $945,178. 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 is recognizing compensation expense ratably over the implied service period of 6 years. Compensation expense for the three and nine month periods ended September 30, 2007 was $51,555 and $154,666. Significant assumptions used in the valuation were as follows:

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Value units fully participate in cash distributions by CALLC (and, following the split of CALLC into two entities, CALLC II) when the amount of such cash distributions to certain investors (Current Common Value) is equal to four times the original contributed capital of such investors (including the Delayed Draw Capital required to be contributed pursuant to the long term credit agreements). If the Current Common Value is less than two times the original contributed capital of such investors at the time of a distribution, none of the override value units participate. In the event the Current Common Value is greater than two times the original contributed capital of such investors but less than four times, the number of participating override value units is the product of 1) the number of issued override value units and 2) a fraction, the numerator of which is the Current Common Value minus two times original contributed capital, and the denominator of which is two times the original contributed capital. Distributions to participating override value units will be reduced until the total cumulative reductions are equal to the benchmark value. On the tenth anniversary of any override value unit (including any override value unit issued on the conversion of an override operating unit) the “two times” threshold referenced above will become “10 times” and the “four times” threshold referenced above will become “12 times”. Unless the compensation committee of the board of directors of CALLC (and, following the split of CALLC into two entities, CALLC II) 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:

 

 

At September 30, 2007, there was approximately $4.6 million of unrecognized compensation expense related to nonvoting override units. This is expected to be recognized over a period of five years as follows:

 

 

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 September 30, 2007, the issued Profits Interest (combined phantom plan and override units) represented 15% of combined common unit interest and Profits Interest of CALLC. 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 proposed initial public offering price to determine the Company’s equity value, through an independent valuation process, the

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

service phantom interest was valued at $39.61 per point and the performance phantom interest was valued at $39.61 per point. CVR has recorded $10,817,390 and $20,458,877 in personnel accruals as of December 31, 2006 and September 30, 2007, respectively. Compensation expense for the three and nine month periods ended September 30, 2007 related to the Phantom Unit Plan was $4,061,877 and $9,641,487, respectively. Compensation expense for the three and nine months ended September 30, 2006 related to the Phantom Unit Plan was ($475,754) and $900,496, respectively.

 

At September 30, 2007 there was approximately $21.1 million of unrecognized compensation expense related to the Phantom Unit Plan. This is expected to be recognized over a period of five years.

 

Subsequent to September 30, 2007, in connection with the Company’s initial public offering, the Company has created a second phantom unit appreciation plan with respect to CALLC II which mirrors in all respects the Phantom Unit Appreciation Plan as it relates to CALLC.

 

 

Inventories consist primarily of crude oil, blending stock and components, work in progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of moving-average cost, which approximates the first-in, first-out (FIFO) method, or market for fertilizer products and at the lower of FIFO cost or market for refined fuels and by-products for all periods presented. Refinery unfinished and finished products inventory values were determined using the ability-to-bare process, whereby raw materials and production costs are allocated to work-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.

 

Inventories consisted of the following (in thousands):

 

 

 

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 plant last completed a major scheduled turnaround in the third quarter of 2006. The Coffeyville refinery started a major scheduled turnaround in February 2007 with completion in April 2007. Costs of $76,754,014 associated with the 2007 turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the nine months ended September 30, 2007. No costs were incurred for the three months ended September 30, 2007. Costs of $4,069,189 and $4,407,137 associated primarily with the 2006 turnaround for the nitrogen plant were included in direct operating expenses (exclusive of depreciation and amortization) for the three and nine months ended September 30, 2006, respectively.

 

 

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 $595,046 and $1,791,563 for the three and nine months ended September 30, 2007, respectively.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

Cost of product sold excludes depreciation and amortization of $529,738 and $1,553,030 for the three and nine months ended September 30, 2006, 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 $9,582,478 and $40,201,920 for the three and nine months ended September 30, 2007, respectively. Direct operating expenses exclude depreciation and amortization of $11,682,825 and $34,528,780 for the three and nine months ended September 30, 2006, respectively. Direct operating expenses also exclude depreciation of $7,627,072 for both the three and nine months ended September 30, 2007 that is included in “Net costs associated with flood” on the consolidated statement of operations as a result of the assets being idled 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 $303,541 and $680,040 for the three and nine months ended September 30, 2007, respectively. Selling, general and administrative expense excludes depreciation and amortization of $574,973 and $727,834 for the three and nine months ended September 30, 2006, respectively.

 

 

As a result of the flood and crude oil discharge, see Note 10, “Flood”, and Note 12, “Commitments and Contingent Liabilities”, the Company’s subsidiaries entered into three new credit facilities in August 2007. Two of these facilities were subsequently repaid in full with proceeds from the initial public offering and the third facility terminated in connection with the initial public offering. CRLLC entered into a new $25 million senior secured term loan (the $25 million secured facility). The facility was secured by the same collateral that secured the Company’s existing Credit Facility. Interest was payable in cash, at the Company’s option, at the base rate plus 1.0% or the reserve adjusted Eurodollar rate plus 2.00%. CRLLC also entered into a new $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 1.0% or the reserve adjusted Eurodollar rate plus 2.00%. A subsidiary of CALLC, Refining Holdco, entered into a new $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 borrower’s option, at the base rate plus 1.50% or at the reserve adjusted Eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amount was ever drawn on the $75 million unsecured facility.

 

The sole lead arranger and sole bookrunner for each of these facilities was Goldman Sachs Credit Partners L.P. The Company’s obligations under the $25 million secured facility and the $25 million unsecured facility were guaranteed by substantially all of the Company’s subsidiaries. The $75 million unsecured facility was guaranteed by CALLC. In addition, each of GS Capital Partners V, L.P. and Kelso Investment Associates VII, L.P. guaranteed 50% of the aggregate amount of each of the three facilities. The maturity of each of these three facilities was January 31, 2008, with an automatic extension to August 23, 2008 upon completion of an initial public offering. The secured and unsecured credit facilities were paid in full on October 26, 2007 with proceeds from CVR’s initial public offering, see Note 1, “Organization, Initial Public Offering, and Basis of Presentation”, and both facilities were terminated. Interest accrued of approximately $0.2 million through the payment date on these two facilities was also paid with proceeds from the initial public offering. Additionally, in connection with the consummation of the initial public offering, the $75 million unsecured facility also terminated.

 

In connection with the repayment of the $25 million secured facility and the $25 million unsecured facility with the proceeds of CVR’s initial public offering, the Company expects to write off approximately $1.3 million of deferred financing fees in the fourth quarter of 2007.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

The Company repaid $280 million of term debt with proceeds from the initial public offering. Associated accrued interest was paid of $5.7 million. After the initial public offering, the Company had approximately $491.1 million of First Lien Tranche D term loans outstanding and $7.2 million of outstanding borrowings under its Revolving Loan Facility.

 

 

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 approximately $5.9 million note will be repaid in nine equal installments with final payment in April 2008.

 

 

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 from insurance at September 30, 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.

 

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 this 45-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 the 45-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 September 30, 2007, the Company has recorded pretax costs of approximately $34.3 million associated with the flood and related crude oil discharge as discussed in Note 12, “Commitments and Contingent Liabilities”, including $32.2 million in the third quarter of 2007. These amounts were net of anticipated insurance recoveries of approximately $96.4 million. The components of the net costs as of September 30, 2007 include $3.5 million for uninsured losses within the Company’s insurance deductibles; $7.6 million for depreciation for the temporarily idled facilities; $5.1 million as a result of other uninsured expenses incurred which included salaries of $1.2 million, professional fees of $1.1 million and other miscellaneous amounts of $2.8 million. The $34.3 million net costs also included approximately $18.1 million recorded with respect to the environmental remediation and property damage as discussed in Note 12, “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 three and nine months ended September 30, 2007 were approximately $128.6 million and $130.7 million. Of these gross costs for the nine month period ended September 30, 2007, approximately $91.2 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, $5.9 million of

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

salaries, $2.9 million of professional fees and $74.8 million for other repair and related costs. There were approximately $39.5 million costs recorded for the nine month period ended September 30, 2007 related to the third party and property damage remediation as a result of the crude oil discharge. Total accounts receivable from insurers for flood related matters approximated $96.4 million at September 30, 2007, for which we believe collection is probable, including $21.4 million related to the crude oil discharge and $75.0 million as a result of the flood damage to the Company’s facilities.

 

The Company anticipates that approximately $15.5 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods. The total third party cost to repair the refinery is currently estimated at approximately $86 million, and the total third party cost to repair the nitrogen fertilizer facility is currently estimated at approximately $4 million. 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.

 

As of September 30, 2007, the Company had not received any insurance proceeds. As of November 30, 2007, the Company received insurance proceeds of $10 million under its property insurance policy, and an additional $10 million under its environmental policies related to recovery of certain costs associated with the 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.

 

 

In June 2006, the FASB issued FASB Interpretation No. (FIN) 48, Accounting for Uncertain Tax Positions — an interpretation of FASB No. 109. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with FASB 109, by prescribing a minimum financial statement recognition threshold and measurement attribute for a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition.

 

The Company adopted the provisions of 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 September 30, 2007.

 

Accordingly, the Company did not accrue or recognize any amounts for interest or penalties in its financial statements for the three and nine months ended September 30, 2007. The Company will classify interest to be paid on an underpayment of income taxes and any related penalties 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.

 

CVR Energy and its subsidiaries file U.S. federal and various state income tax returns. The Company has not been subject to U.S. federal, state and local income tax examinations by tax authorities for any tax year. The U.S. federal and state tax years subject to examination are 2004 to 2006.

 

The Company’s effective tax rate for the three and nine months ended September 30, 2007 was 78.0% and 69.4%, respectively, as compared to the federal statutory tax rate of 35%. The effective tax rate is higher primarily due to the correlation between the amount of credits which are projected to be generated for the production of ultra low sulfur diesel fuel in 2007 and the reduced level of projected pre-tax income for 2007.

 

The Company received credit certification from the Kansas Department of Commerce under the High Performance Incentive Program (HPIP) subsequent to September 30, 2007. Under the HPIP program, the Company anticipates that it will record a significant state income tax benefit in the fourth quarter of 2007 related to credits

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

earned on certain property placed in service for 2007 and 2006. The recognition of the credit earned will significantly increase the income tax benefit recorded in the fourth quarter of 2007.

 

 

The minimum required payments for the Company’s lease agreements and unconditional purchase obligations are as follows:

 

 

The Company leases various equipment and real properties under long-term operating leases. For the three and nine months ended September 30, 2007, lease expense totaled $850,354, and $2,812,202, respectively. For the three and nine months ended September 30, 2006, lease expense totaled $985,251 and $2,823,689, respectively. The lease agreements have various remaining terms. Some 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.

 

The Company executed a Petroleum Transportation Service Agreement in June 2007 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 the fourth quarter of 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.

 

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 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. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.

 

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.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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. Due to the uncertainty of the state suit, the Company is unable to estimate a range of possible loss at this time for this exposure in excess of the amount accrued for the proposed purchase of homes and commercial property noted below. The Company intends to defend the state suit vigorously. Presently, the Company does not expect that the resolution of the suit will have a significant adverse effect on its business and results of operations.

 

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 December 2007.

 

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 320 homes and other commercial properties in connection with the flood and the crude oil release. The costs recorded as of September 30, 2007 related to the obligation of the homes being purchased, were approximately $11.5 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 September 30, 2007. The costs recorded related to estimated commercial property to be purchased and associated claims were approximately $3.6 million as of September 30, 2007. The total amount of gross costs recorded for the three and nine months ended September 30, 2007 related to the residential and commercial purchase and property claims program were approximately $16.8 million.

 

As of September 30, 2007, the total costs recorded for obligations other than the purchase of homes, commercial properties, and related personal property claims, approximated $22.7 million. The Company has recorded as of September 30, 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 $18.1 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 November 30, 2007.

 

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

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

CVR owns and/or operates manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.

 

The Company agreed to perform corrective action pursuant to two Administrative Orders on Consent issued to Farmland Industries, Inc. (predecessor entity to the Company) under the Resource Conservation and Recovery Act, as amended (RCRA), for the Coffeyville, Kansas refinery and Phillipsburg, Kansas terminal. In 2005, Coffeyville Resources Nitrogen Fertilizers, LLC agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (VCPRP) to address a reported release of urea ammonium nitrate (UAN) at the Coffeyville UAN loading rack. As of December 31, 2006 and September 30, 2007, environmental accruals of $7,222,754 and $7,177,347, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Orders and the VCPRP, including amounts totaling $1,827,649 and $1,573,463, respectively, included in other current liabilities. The accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the Environmental Protection Agency (the EPA) and are discounted at the appropriate risk free rates at December 31, 2006 and September 30, 2007, respectively. The accruals include estimated closure and post-closure costs of $1,857,000 and $1,809,000 for two landfills at December 31, 2006 and September 30, 2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):

 

 

In March 2004, a predecessor entity to CVR entered into a Consent Decree with the EPA and the Kansas Department of Health and Environment (KDHE) related to Farmland Industries, Inc.’s prior operation of the Company’s oil refinery. Under the Consent Decree, the Company agreed to install controls on certain process equipment and make certain operational changes at the refinery. As a result of this agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to impose civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Pursuant to the Consent Decree, in the short term, the Company has increased the use of catalyst additives to the fluid catalytic cracking unit at the facility to reduce emissions of SO₂. The Company will begin adding catalyst to reduce oxides of nitrogen, or NOx, in 2008. In the longer term, the Company will install controls to minimize SO₂ emissions and will install controls or otherwise reduce NOx emissions by January 1, 2011. 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. The estimated costs do not include the cleanup obligations that

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

the Company assumed pursuant to the Consent Decree under the Administrative Orders on Consent previously described.

 

The EPA is continuing with its 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. At this time, management does not know how, if at all, the Petroleum Refining Initiative will affect the Company as the current Consent Decree covers some, but not all, of the “marquee” issues.

 

On November 15, 2007, the Governor of Kansas, Kathleen Sebelius, signed the Midwestern Greenhouse Gas Accord, whereby six states and the Canadian Province of Manitoba agreed to endeavor to establish greenhouse gas reduction targets and develop a market-based and multi-sector cap-and-trade mechanism to achieve these reduction targets. At the time, management does not know to what extent the Midwestern Greenhouse Gas Accord will affect the Company, and its facilities that emit greenhouse gases, could be regulated.

 

Periodically, the Company receives communications from various federal, state and local governmental authorities asserting violation(s) of environmental laws and/or regulations. These governmental entities may also propose or assess fines or require corrective action for these asserted violations. The Company intends to respond in a timely manner to all such communications and to take appropriate corrective action. The Company does not anticipate that any such matters currently asserted will have a material adverse impact on the financial condition, results of operations or cash flows.

 

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 the Company a petition for a technical hardship waiver with respect to the date for compliance in meeting the sulfur-lowering standards. CVR has spent approximately $2 million in 2004, $27 million in 2005, $79 million in 2006, $17 million in the first nine months of 2007 and, based on information currently available, anticipates spending approximately $0 million in the last three months of 2007, $5 million in 2008, $18 million in 2009, and $22 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 the nine month period ended September 30, 2006 and 2007, capital expenditures were $172,950,392 and $102,775,474, 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.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

Loss on derivatives consisted of the following:

 

 

CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR may enter into various derivative transactions. In addition, CALLC, as further described below, entered into certain commodity derivate contracts and an interest rate swap as required by the long-term debt agreements.

 

CVR has adopted SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities, (SFAS 133). SFAS 133 imposes extensive record-keeping requirements in order to designate a derivative financial instrument as a hedge. CVR holds derivative instruments, such as exchange-traded crude oil futures, certain over-the-counter forward swap agreements, and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as loss on derivatives.

 

At September 30, 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 14, “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. The notional quantities on the date of execution were 100,911,000 barrels of crude oil; 1,889,459,250 gallons of heating oil and 2,348,802,750 gallons of unleaded gasoline. The swap agreements were executed at the prevailing market rate at the time of execution and management believes the swap agreements provide an economic hedge on future transactions. At September 30, 2007 the notional open amounts under the swap agreements were 48,496,750 barrels of crude oil, 1,018,431,750 gallons of heating oil and 1,018,431,750 gallons of unleaded gasoline. These positions resulted in unrealized gains (losses) for the three and nine month periods ended September 30, 2007 of $90,196,226 and $(98,294,206), 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. Unrealized gains were recorded for the three and nine month periods ended September 30, 2006 of $178,545,946 and $80,322,487. The Petroleum Segment recorded $(45,351,557) and $(142,566,824) in realized gains (losses) on these swap agreements for the three and nine month periods ended September 30, 2007, respectively. Realized gains (losses) for the three and nine months ended September 30, 2006 were recorded of $(12,735,079) and $(46,147,786), respectively.

 

The Petroleum Segment also recorded mark-to-market net gains (losses), exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, in gain (loss) on derivatives of $(520,569), and $(9,671,097), for the three and nine month periods ended September 30, 2007, respectively and $9,936,444 and $7,676,963 for the three and nine month periods ended September 30, 2006, 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 CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

At September 30, 2007, 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. Half of the agreements are held with a related party (as described in Note 14, “Related Party Transactions”), and the other half are held with a financial institution that is a lender under CRLLC’s long-term debt agreements. The swap agreements carry the following terms:

 

 

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 $(3,791,605) and $(1,379,812) for the three and nine month periods ended September 30, 2007, respectively. Mark-to-market net gains (losses) on derivatives and quarterly settlements were $(4,538,416) and $2,895,189 for the three and nine month periods ended September 30, 2006, respectively.

 

 

GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates VII, L.P. and related entity (Kelso) were majority owners of CALLC as of September 30, 2007.

 

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 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, $500,000 and $1,581,849 was expensed in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the three and nine months ended September 30, and 2007, respectively. $518,264 and $1,566,891 were expensed in selling, general, and administrative expense (exclusive of depreciation and amortization) for the three and nine months ended September 30, 2006. 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. 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 13, “Derivative Financial Instruments”). Amounts totaling $44,844,669 and $(240,861,030) were recognized related to these swap agreements for the three and nine months ended September 30, 2007, respectively, and are reflected in gain (loss) on derivatives. Amounts totaling $165,810,867 and $34,174,701 were recognized for the three and nine months ended September 30, 2006, respectively. In addition, the consolidated balance sheet at December 31, 2006 and September 30, 2007 includes liabilities of $36,894,802 and $241,427,327 included in current payable to swap counterparty and $72,806,486 and $99,202,285 included in long-term payable to swap counterparty.

 

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%.

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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.

 

These deferred payment amounts are included in the consolidated balance sheet at September 30, 2007 in current payable to swap counterparty. Interest relating to the deferred payment amounts reflected in interest expense for the three and nine month periods ended September 30, 2007 was $1,505,950 and $1,505,950, respectively. $1,505,950 is also included in other current liabilities at September 30, 2007.

 

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 9, “Long-Term Debt”. The Company paid the subsidiary of GS a $1.3 million fee included in deferred financing costs. For both the three and nine month periods ended September 30, 2007, interest expenses relating to these agreements were $567,209. This amount is included in other current liabilities at September 30, 2007. 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, Initial Public Offering, and Basis of Presentation”, and both facilities terminated. Additionally, in connection with the consummation of the initial public offering, the $75 million unsecured facility also terminated.

 

On June 30, 2005, CALLC entered into three interest-rate swap agreements with the same subsidiary of GS (as described in Note 13, “Derivative Financial Instruments”). Gains (losses) totaling $(1,893,613) and $(682,869) were recognized related to these swap agreements for the three and nine months ended September 30, 2007, respectively, and are reflected in gain (loss) on derivatives. Gains (losses) totaling $(2,280,293) and $1,441,526 were recognized related to these swap agreements for the three and nine months ended September 30, 2006, respectively. In addition, the consolidated balance sheet at December 31, 2006 and September 30, 2007 includes $1,533,738 and $443,477 in prepaid expenses and other current assets and $2,014,504 and $776,084 in other long-term assets related to the same agreements, respectively.

 

Effective December 30, 2005, the Company entered into a crude oil supply agreement with a subsidiary of GS (Supplier). This agreement replaced a similar contract held with an independent party. 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

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

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, 2006 through December 31, 2007 and in connection with the extension amended certain terms and conditions of the Supply Agreement. $1,622,824 and $912,091 were recorded on the consolidated balance sheet at December 31, 2006 and September 30, 2007, respectively, in prepaid expenses and other current assets for prepayment of crude oil. In addition, $31,750,784 and $41,644,294 were recorded in inventory and $13,458,977 and $24,995,809 were recorded in accounts payable at December 31, 2006 and September 30, 2007, respectively. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the three and nine month periods ended September 30, 2007 totaled $249,657,118 and $765,799,978, respectively. Expenses associated with this agreement, in cost of product sold (exclusive of depreciation and amortization) for the three and nine month periods ended September 30, 2006 were $444,871,411 and $1,230,270,562, respectively. Interest expense associated with this agreement for the three and nine month periods ended September 30, 2007 totaled $57,148 and $(865,265), respectively.

 

On October 24, 2007, CVR paid a cash dividend, see Note 16, “Dividends”, 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.

 

 

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.

 

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. The intercompany transactions are eliminated in the Other Segment. Intercompany sales included in Petroleum net sales were $679,785 and $2,560,380 for the three and nine month periods ended September 30, 2007, respectively. Intercompany sales included in petroleum net sales were $1,233,255 and $3,961,995 for the three and nine month periods ended September 30, 2006.

 

Nitrogen Fertilizer

 

The principal products of the Nitrogen Fertilizer Segment are anhydrous ammonia and urea ammonia nitrate solution (UAN). Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was $630,836, and $2,596,814 for the three and nine month periods ended September 30, 2007, respectively. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer was $1,134,167 and $3,804,870 for the three and nine month periods ended September 30, 2006.

 

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.

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

CVR ENERGY, INC. AND SUBSIDIARIES

 

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

 

 

 

CVR declared a cash dividend of $0.168 per share on its common stock to shareholders of record on October 16, 2007. The total cash required for the dividend declared was $10.6 million.

 

 

During the fourth quarter of 2007, a subsidiary of the Company, CRRM, entered into an agreement for additional crude oil storage and terminalling services with a counterparty beginning January 1, 2008 and ending on December 31, 2014. Average monthly commitments under this agreement for the first nine months will approximate $124,000 with the average monthly commitments for the remaining term increasing to approximately $250,000. This increase results from increased storage capacity beginning on October 1, 2008 and is subject to potential rate acceleration. In conjunction with this agreement, the Company’s subsidiary also extended the term of its current crude oil storage and terminalling agreement with the same counterparty to December 31, 2014.

 

 

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

 

Forward-Looking Statements

 

This Form 10-Q, including this management’s discussion and analysis, contains “forward-looking statements” as defined by the Securities and Exchange Commission (“SEC”). Such statements are those concerning contemplated transactions and strategic plans, expectations and objectives for future operations. These include, without limitation:

 

 

Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Form 10-Q, including this management’s discussion and analysis, are reasonable, we can give no assurance that such plans, intentions or expectations will be achieved. These statements are based on assumptions made by us based on our experience and perception of historical trends, current conditions, expected future developments and other factors that we believe are appropriate in the circumstances. Such statements are subject to a number of risks and uncertainties, many of which are beyond our control. You are cautioned that any such statements are not guarantees of future performance and that actual results or developments may differ materially from those projected in the forward-looking statements as a result of various factors, including but not limited to those set forth under “Risk Factors” and contained elsewhere in this Report.

 

All forward-looking statements contained in this Form 10-Q only speak as of the date of this document. We undertake no obligation to update or revise publicly any forward-looking statements to reflect events or circumstances that occur after the date of this Form 10-Q, or to reflect the occurrence of unanticipated events.

 

Company Overview

 

We are an independent refiner and marketer of high value transportation fuels and a producer of ammonia and UAN fertilizers.

 

We operate under two business segments: Petroleum and Nitrogen Fertilizer. Our petroleum business includes a 113,500 bpd complex full coking sour crude refinery in Coffeyville, Kansas. In addition, supporting businesses include (1) a crude oil gathering system serving central Kansas, northern Oklahoma, and southwest Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, and (3) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and at throughput terminals on Midstream Partners L.P.’s (Magellan) 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 variety in the world capable of being transported by pipeline.

 

The nitrogen fertilizer segment consists of our interest in CVR Partners, LP, a limited partnership controlled by our affiliates, which operates a nitrogen fertilizer plant and the nitrogen fertilizer business. The nitrogen fertilizer business is the lowest cost producer of ammonia and UAN in North America, assuming natural gas prices remain at current levels. The fertilizer plant is the only commercial facility in North America utilizing a coke gasification

process to produce nitrogen fertilizers. Its redundant train gasifier provides exceptional on-stream reliability and the use of low cost by-product pet coke feed from the adjacent oil refinery as feedstock (rather than natural gas) to produce hydrogen provides the facility with a significant competitive advantage compared to high and volatile natural gas prices. The plant’s competition utilizes natural gas to produce ammonia.

 

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. 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 million of CVR’s outstanding term loan debt and to repay in full the $25 million secured credit facility and the $25 million unsecured credit facility. We also repaid $50 million of indebtedness under our revolving credit facility. Associated with the repayment of the $25 million secured facility and the $25 million unsecured facility, we expect to record a write-off of unamortized deferred financing fees of approximately $1.3 million in the fourth quarter of 2007.

 

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 CVR issuing 62,866,720 shares of its common stock to certain entities controlled by its majority stockholder in exchange for the interests in certain subsidiaries of CALLC. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding any restricted shares issued.

 

Major Influences on Results of Operations

 

Petroleum Business.  Our earnings and cash flows from our petroleum operations are primarily affected by the relationship between refined product prices and the prices for crude oil and other feedstocks. Feedstocks are petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. The cost to acquire feedstocks and the price for which refined products are ultimately sold depend on factors beyond our control, including the supply of, and demand for, crude oil, as well as gasoline and other refined products which, in turn, depend on, among other factors, changes in domestic and foreign economies, weather conditions, domestic and foreign political affairs, production levels, the availability of imports, the marketing of competitive fuels and the extent of government regulation. Because we apply first-in, first-out, 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 reduction in product margins. Moreover, the refining industry typically experiences seasonal fluctuations in demand for refined products, such as increases in the demand for gasoline during the summer driving season and for home heating oil during the winter, primarily in the Northeast.

 

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

expressed in dollars per barrel and is a proxy for the per barrel margin that a sweet crude refinery would earn assuming it produced and sold the benchmark production of gasoline and distillate.

 

Although the 2-1-1 crack spread is a benchmark for our refinery margin, because our refinery has certain feedstock costs and/or logistical advantages as compared to a benchmark refinery and our product yield is less than total refinery throughput, the crack spread does not account for all the factors that affect refinery margin. Our refinery is able to process a blend of crude oil that includes quantities of heavy and medium sour crude oil that has historically cost less than WTI crude oil. We measure the cost advantage of our crude oil slate by calculating the spread between the price of our delivered crude oil to the price of WTI crude oil, a light sweet crude oil. The spread is referred to as our crude discount. Our refinery margin can be impacted significantly by the consumed crude differential. Our consumed crude differential will move directionally with changes in the WTS differential to WTI and the Maya differential to WTI as both these differentials indicate the relative price of heavier, more sour, slate to WTI. The correlation between our consumed crude differential and published differentials will vary depending on the volume of light medium sour crude and heavy sour crude we purchase as a percent of our total crude volume and will correlate more closely with such published differentials the heavier and more sour the crude oil slate.

 

We produce a high volume of high value products, such as gasoline and distillates. We benefit from the fact that our marketing region consumes more refined products than it produces so that the market prices of our products have to be high enough to cover the logistics cost for 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.

 

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.

 

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.

 

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 the majority of the coke feedstock needed by the nitrogen fertilizer 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 sell at the floor price, 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.

 

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. UAN production is a major contributor to our profitability. 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.

 

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.

 

Factors Affecting Comparability of Our Financial Results

 

Our historical results of operations for the periods presented may not be comparable with prior periods or to our results of operations in the future for the reasons discussed below.

 

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 the nitrogen fertilizer plant, which are located in close proximity to the Verdigris River, were severely flooded, sustained major damage and required extensive repairs. Total costs incurred and recorded as of September 30, 2007 related to the third party costs to repair the refinery and fertilizer facilities were approximately $71.4 million and $3.1 million, respectively. The total third party cost to repair the refinery is currently estimated at approximately $86 million, and the total third party cost to repair the nitrogen fertilizer facility is currently estimated at approximately $4 million.

 

As a result of the flooding, our refinery and 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 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. The nitrogen fertilizer facility initiated startup at its production facility on July 13, 2007.

 

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 are currently remediating the contamination caused by the crude oil discharge. Total net costs recorded as of September 30, 2007 associated with remediation efforts and third party property damage incurred by the crude oil discharge are approximately $18.1 million. This amount is net of anticipated insurance recoveries of $21.4 million. Subsequent to September 30, 2007, we received $10 million of insurance proceeds under our environmental insurance policy.

 

Our results for the nine months ended September 30, 2007 include pretax costs of $34.3 million associated with the flood and related crude oil discharge. This amount is net of anticipated insurance recoveries of $96.4 million. We anticipate that approximately $15.5 million in third party costs related to the repair of the flood damaged property will be recorded in future periods.

 

The flood and crude oil discharge had a significant adverse impact on our third quarter financial results. We reported reduced revenue due to the closure of our facilities for a portion of the third quarter, as well as significant costs related to the flood as a result of the necessary repairs to our facilities and environmental remediation.

 

Refinancing and Prior Indebtedness

 

On December 28, 2006, we entered into a new credit facility and used the proceeds thereof to repay our 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 million of tranche D term loans, a $150 million revolving credit facility, and a funded letter of credit facility of $150 million issued in support of the Cash Flow Swap. The credit facility is secured by substantially all of Coffeyville Resources, LLC’s assets. As a result, interest expense related to the term debt outstanding of $771.1 million for the nine months ended September 30, 2007 was significantly higher than interest expense on term debt outstanding of $527.8 million at September 30, 2006. Consolidated interest expense for the nine months ended September 30, 2007 was $46.0 million as compared to interest expense of $33.0 million for the nine months ended September 30, 2006.

 

The flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. As a result of this, in August 2007, our subsidiaries entered into a $25 million secured facility, a $25 million unsecured facility and a $75 million unsecured facility. No amounts were drawn under the $75 million unsecured facility. Our statement of operations for the nine months ended September 30, 2007 includes $1.1 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 million of term debt with initial public offering proceeds. Additionally, we repaid the $25 million secured facility and $25 million unsecured facility in their entirety with a portion of the net proceeds from the initial public offering. Also, the $75 million credit facility terminated upon consummation of the initial public offering.

 

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 & Company (“J. Aron”) with respect to the Cash Flow Swap, which is a series of commodity derivative arrangements whereby if crack spreads fall below a fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above a fixed level, we agreed to pay the difference to J. Aron. These deferral agreements deferred to January 31, 2008 the payment of approximately $123.7 million (plus accrued interest) which we owed to J. Aron. J. Aron has agreed to further defer these payments to August 31, 2008 but we will be required to use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts.

 

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, Inc. as a result of a series of steps. As a result, in the future, we will 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 will reflect the impact of these expenses and will affect the comparability with our financial statements of periods subsequent to the initial public offering.

 

2007 Turnaround

 

In April 2007, we completed a planned turnaround of our refining plant at a total cost approximating $81 million. The majority of these costs were expensed in the first quarter of 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, but had very little impact on our 2006 results.

Results of Operations

 

The following tables summarize the financial data and key operating statistics for CVR and our two operating segments for the three and nine months ended September 30, 2006 and 2007. The summary financial data for our two operating segments does not include certain SG&A expenses and depreciation and amortization related to our corporate offices. The following data should be read in conjunction with our condensed consolidated financial statements and the notes thereto included elsewhere in this Form 10-Q. All information in “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, except for the balance sheet data as of December 31, 2006, is unaudited.