product sold excluding depreciation and amortization was an increase in direct operating expenses associated with repairs and maintenance ($6.5 million), equipment rental ($0.6 million) environmental ($0.4 million), utilities ($0.3 million), and insurance ($0.3 million). These increases in direct operating expenses were partially offset by reductions in expenses associated with turnaround ($2.6 million), royalties and other expense ($1.1 million), reimbursed expense ($0.6 million), catalyst ($0.3 million), chemicals ($0.3 million) and slag disposal ($0.2 million).
Year Ended December 31, 2005 (Non-GAAP Combined)2006 Compared to Yearthe 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2004 (Non-GAAP Combined)2005 (Nitrogen Fertilizer Business).
Net Sales. Nitrogen fertilizer net sales increased $60.1 million, or 53%, to $173.0were $162.5 million for the year ended December 31, 2006 compared to $79.3 million for the 174 days ended June 23, 2005 and $93.7 million for the 233 days ended December 31, 2005. The decrease of $10.5 million from the year ended December 31, 2006 as compared to net sales of $112.9 millionthe combined periods for the year ended December 31, 2004. This increase2005 was the result of increasesboth decreases in bothselling prices ($1.6 million) and reductions in overall sales volumes and selling prices($8.9 million) of the fertilizer products as compared to the year ended December 31, 2005.
Net sales for the year ended December 31, 2006 included $121.1 million from the sale of UAN, $42.1 million from the sale of ammonia and $6.8 million from the sale of hydrogen to CVR Energy. Net sales for the year ended December 31, 2005 included $122.2 million from the sale of UAN, as compared$48.6 million from the sale of ammonia and $2.7 million from the sale of hydrogen to 2004.CVR Energy.
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In regard to product sales volumes for the year ended December 31, 2006, the nitrogen fertilizer operations experienced an increasea decrease of 36%17% in ammonia sales unit volumes (37,949(24,500 tons) and an increasea decrease of 19%0.2% in UAN sales unit volumes (104,982(988 tons) as compared. The decrease in ammonia sales volume was the result of decreased production volumes during the year ended December 31, 2006 relative to 2004. The increases in both ammonia and UAN sales werethe comparable period of 2005 due to improved on-streamthe scheduled turnaround at the nitrogen fertilizer plant during July 2006 and the transfer of hydrogen to our petroleum operations to facilitate sulfur recovery in the ultra low sulfur diesel production unit.
On-stream factors (total number of hours operated divided by total hours in the reporting period) for all units of the nitrogen fertilizer operations (gasifier, ammonia plant and UAN plant) were less in 2006 than in 2005 as comparedprimarily due to 2004. On-stream factors in 2004 were negatively impacted during September 2004 by additional downtime from athe scheduled turnaround which resulted from delay instart-up associated with projects completed during the turnaround July 2006 and outagesdowntime in the ammonia plant due to repair a damaged heat exchanger.crack in the converter. It is typical to experience brief outages in complex manufacturing operations such as the nitrogen fertilizer plant which result in less than 100% on-stream availability for one or more specific units.
Plant gate prices are prices FOB the delivery point less any freight cost we absorbabsorbed to deliver the product. We believe plant gate price is meaningful because we sell products both FOB our plant gate (sold plant) and FOB the customers designated delivery site (sold delivered) and the percentage of sold plant as compared to sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. Plant gate prices in 2005 for ammonia and UAN were greater than 2004 by 22% and 27%, respectively. These prices reflected the strong market conditions in the nitrogen fertilizer business as reflected in relatively high natural gas prices during 2005.
The demand for fertilizer is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers. Individual farmers make planting decisions based largely on the prospective profitability of a harvest, while the specific varieties and amounts of fertilizer they apply depend on factors like their current liquidity, soil conditions, weather patterns and the types of crops planted.
Manufacturing Expenses Excluding Depreciation and Amortization. Nitrogen fertilizer manufacturing expenses excluding depreciation and amortization in 2005 decreased to $54.6 million, or 6%, as compared to $58.4 million in 2004. This decrease was primarily the result of the reduction in turnaround and catalyst expenses.
Depreciation and Amortization Included in Gross Profit. Nitrogen fertilizer depreciation and amortization included in gross profit increased by $7.7 million to $8.7 million in the year ended December 31, 2005 as compared to the year ended December 31, 2004. This increase was primarily the result of thestep-up in property, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”
Operating Income. Nitrogen fertilizer operating income increased $44.6 million, or 169%, to $71.0 million in the year ended December 31, 2005 from $26.4 million in the year ended December 31, 2004. This increase was due to the factors discussed above, and particularly driven by historically high natural gas prices during 2005.
Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.
Net Sales. Nitrogen fertilizer net sales increased $12.0 million, or 12%, to $112.9 million in 2004 from $100.9 million in 2003. This revenue increase was entirely attributable to increased nitrogen fertilizer prices, which more than offset a slight decline in total production volume due to a planned turnaround in August 2004. For 2004, southern plains ammonia and corn belt UAN prices increased 8% and 20%, respectively, as compared to the comparable period in 2003. In addition, due to our direct marketing efforts, our actual plant gate prices, relative to the market indices presented above improved substantially. Plant gate prices for the year ended December 31, 2004 for ammonia and UAN were greater than the comparable period in 2003 by 13% and 27%, respectively. Plant gate prices are prices FOB the delivery point less any freight cost we absorb to deliver the product. We believe the plant gate price is meaningful because we sellsells products both FOB ourthe plant gate (sold plant) and FOB the customer’s designated delivery site (sold delivered) and the percentage of sold plant versus sold delivered can change month to month or year to year. The plant gate price provides a measure that is consistently comparable period to period. The improvement inPlant gate prices for the year ended December 31, 2006 for ammonia were greater than plant gate prices for the comparable period of 2005 by 4%. In contrast to ammonia, UAN prices decreased for the year ended December 31, 2006 as compared to the year ended December 31, 2005 by 6%. The positive price comparisons for ammonia sales, given the dramatic decline in natural gas prices during the comparable periods, were the result of prepay contracts executed during the period of relatively high natural gas prices that resulted from the impact of hurricanes Katrina and Rita on an already tight natural gas market.
Cost of Product Sold Exclusive of Depreciation and Amortization. Cost of product sold exclusive of depreciation and amortization is primarily comprised of pet coke expense and freight and distribution expenses. Cost of product sold excluding depreciation and amortization for the year ended December 31, 2006 was $25.9 million compared to $9.1 million for the 174 days ended June 23, 2005 and $14.5 million for the 233 days ended December 31, 2005. The increase of $2.3 million for the
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relativeyear ended December 31, 2006 as compared to the market index was the result of eliminating the reseller discount offered under the terms of our prior marketing agreement and maximizing shipments to customers that were more freight logical to our facility.
Manufacturing Expenses Excluding Depreciation and Amortization. Nitrogen fertilizer manufacturing expenses excluding depreciation and amortization were unchanged at $58.4 million duringcombined periods for the year ended December 31, 2004 and during2005 was primarily the year ended December 31, 2003.result of increases in freight expense.
Depreciation and Amortization Included in Gross Profit.Amortization. Nitrogen fertilizer depreciation and amortization includedincreased to $17.1 million for the year ended December 31, 2006 as compared to $0.3 million for the 174 days ended June 23, 2005 and $8.4 million for the 233 days ended December 31, 2005. This increase of $8.4 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of thestep-up in gross profit decreased by $0.2 million, or 17%, to $1.0 million in 2004 from $1.2 million in 2003. This decrease was principally due toproperty, plant and equipment for the Subsequent Acquisition. See “— Factors Affecting Comparability.”
Direct Operating Expenses Exclusive of Depreciation and Amortization. Direct operating expenses for the nitrogen fertilizer assets’ useful lives being reset to longer periods inoperations include costs associated with the Initial Acquisition compared to the prior period based on management’s assessment of the conditionactual operations of the nitrogen fertilizer assets acquiredplant, such as repairs and maintenance, energy and utility costs, catalyst and chemical costs, outside services, labor and environmental compliance costs. Nitrogen direct operating expenses exclusive of depreciation and amortization for the year ended December 31, 2006 were $63.7 million as compared to $28.3 million for the 174 days ended June 23, 2005 and $29.2 million for the 233 days ended December 31, 2005. The increase of $6.2 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was primarily the result of increases in labor ($0.7 million), repairs and maintenance ($0.5 million), turnaround expenses ($2.6 million), outside services ($0.6 million), utilities ($2.3 million) and insurance ($0.5 million), partially offset by the impact of thestep-upreductions in value of the acquired nitrogen fertilizer assets in the Initial Acquisition.expenses related to catalyst ($0.6 million) and environmental ($0.8 million).
Operating Income. Nitrogen fertilizer operating income increased $18.6was $36.8 million or 238%, to $26.4 million in 2004 from $7.8 million in 2003. This increase was due to continued strong market conditions infor the domestic nitrogen fertilizer industry described above. For the 304 day periodyear ended December 31, 20042006 as compared to $35.3 million for the 174 days ended June 23, 2005 and $35.7 million for the 233 days ended December 31, 2005. This decrease of $34.2 million for the year ended December 31, 2006 as compared to the combined periods for the year ended December 31, 2005 was the result of reduced sales volumes, lower plant gate prices for UAN and increased direct operating expenses related to labor ($0.7 million), repairs and maintenance ($0.5 million), turnaround expenses ($2.6 million), outside services ($0.6 million), utilities ($2.3 million), insurance ($0.5 million) and depreciation ($8.4 million), partially offset by reductions in expenses related to catalyst ($0.6 million) and environmental ($0.8 million) and higher ammonia prices.
Liquidity and Capital Resources
Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap as well as our convertible notes offering, if consummated, and the proceeds of our proposed senior secured credit facility, if entered into. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses.
As of March 31, 2008 and June 16, 2008, we had cash, cash equivalents and short-term investments of $25.2 million and $71.4 million, respectively, and up to $112.6 million available under our revolving credit facility as of both dates. In the current crude oil price environment, working capital is subject to substantial variability from week-to-week and month-to-month. The payable to swap counterparty included in the consolidated balance sheet at March 31, 2008 was approximately $371.4 million, and the current portion included an increase of $32.6 million from December 31, 2007, resulting in an equal reduction in our working capital for the same period.
On June 30, 2007, our refinery and the nitrogen fertilizer businessplant were severely flooded and forced to conduct emergency shutdowns and evacuate. See “Flood and Crude Oil Discharge.” Our liquidity was charged $4.3 million for pet coke transferred from our refinery. Duringsignificantly negatively impacted as a result of the Original Predecessor period, pet coke was transferred at zero value.
Consolidated Results of Operations
Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005 (Non-GAAP Combined).
Net Sales. Consolidated net sales increased $520.2 million, or 50%, to $1,550.6 millionreduction in the six months ended June 30, 2006 from $1,030.4 million for the six months ended June 30, 2005. This increase was primarilycash provided by operations due to an increase in petroleum net salesour temporary cessation of $507.3 million, as described above,operations and an increase in nitrogen fertilizer net sales of $13.1 million, as described above.
Gross Margin Excluding Manufacturing Expenses. Consolidated gross margin excluding manufacturing expenses increased by $147.0 million, or 72%, to $351.5 million for the six months ended June 30, 2006 from $204.5 million foradditional expenditures associated with the six months ended June 30, 2005. This increase was primarily due to an increase in petroleum gross margin excluding manufacturing expenses of $137.0 million, as described above.
Manufacturing Expenses Excluding Depreciation and Amortization. Consolidated manufacturing expenses excluding depreciation and amortization increased by $7.4 million, or 9%, to $92.1 million for the six months ended June 30, 2006 from $84.7 million for the six months ended June 30, 2005. This increase was due to an increase in petroleum manufacturing expenses of $6.3 million and nitrogen fertilizer manufacturing expenses of $0.4 million.
Depreciation and Amortization Included in Gross Profit. Consolidated depreciation and amortization included in gross profit increased by $22.0 million to $23.9 million for the six months ended June 30, 2006 from $1.9 million for the six months ended June 30, 2005. This increase was due to an increase in petroleum depreciation and amortization of $14.2 million and in nitrogen fertilizer depreciation and amortization of $7.8 million.
Operating Income. Consolidated operating income increased by $116.2 million, or 118%, to $214.9 million for the six months ended June 30, 2006 from $98.7 million for the six months ended June 30, 2005. Petroleum operating income increased $114.6 million and nitrogen fertilizer operating income increased by $2.1 million.
Selling, General and Administrative Expenses. Consolidated selling, general and administrative expenses increased $1.4 million, or 7%, to $20.6 million for the six months ended June 30, 2006 from $19.2 million for the six months ended June 30, 2005. Consolidated selling,flood
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general and administrative expensescrude oil discharge. In order to provide immediate and future liquidity, on August 23, 2007 we deferred payments which were due to J. Aron under the terms of the Cash Flow Swap. The J. Aron deferred amounts of $123.7 million (plus accrued interest of $5.8 million as of June 1, 2008) are due on August 31, 2008. See “— Liquidity and Capital Resources — Payment Deferrals Related to the Cash Flow Swap” for additional information about the six months endedpayment deferral. These deferrals are supported by third-party guarantees. In addition, we estimate that we will owe J. Aron approximately $54 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2005 were negatively impacted2008 based on June 16, 2008 pricing.
Our liquidity was enhanced during the fourth quarter of 2007 by certain expensesthe receipt of the net proceeds from our initial public offering. We intend to use the net proceeds from the convertible notes offering, if consummated, and the proposed senior secured credit facility, if entered into, for general corporate purposes, which may include using a portion of the proceeds to pay amounts owed to J. Aron under the Cash Flow Swap and for other future capital investments. If the convertible notes offering is not consummatedand/or the proposed senior secured credit facility is not entered into, we intend to fund our operations through cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap. We believe these capital resources will be sufficient to satisfy the anticipated cash requirements associated with $3.3our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Debt
Proposed Secured Credit Facility
Concurrently with the closing of this offering, we anticipate that Coffeyville Resources, LLC will enter into a new $25.0 million senior secured term loan (the “proposed senior secured credit facility”). We anticipate that the proposed senior secured credit facility will be secured by the same collateral that secures our existing Credit Facility and will contain covenants substantially similar to the Credit Facility described below. Although we have begun negotiations on the new credit facility, we have not entered into any agreement regarding the proposed senior secured credit facility, and as such, there is no guarantee that we will be enter into a credit facility on the terms described above or at all.
Credit Facility
On December 28, 2006, our subsidiary, Coffeyville Resources, LLC, entered into a credit facility (the “Credit Facility”) which provided financing of up to $1.075 billion. The Credit Facility consisted of $775.0 million of unearned compensation related to the management equity of Immediate Predecessor in relation to the Subsequent Acquisition. Adjusting for this expense, consolidated selling, generaltranche D term loans, a $150.0 million revolving credit facility, and administrative expenses increased $4.6 million for the six months ended June 30, 2006 as compared to the six months ended June 30, 2005. This variance was primarily the result of increases in insurance costs associated with Successor’s $1.25 billion property insurance limit requirement,a funded letter of credit fees duefacility of $150.0 million issued in support of the Cash Flow Swap. On October 26, 2007, we repaid $280.0 million of the tranche D term loans with proceeds from our initial public offering. The Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including the equity of our subsidiaries on a first-lien priority basis.
The tranche D term loans outstanding are subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on April 1, 2007 and increasing to 23.5% of the outstanding principal balance on April 1, 2013 and the next two quarters, with a final payment of the aggregate outstanding balance on December 28, 2013.
The revolving credit facility of $150.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under ourthe revolving credit facility are subject to a $75.0 million sub-limit. The revolving loan commitment expires on December 28, 2012. The borrower has an option to extend this maturity upon written notice to the lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is
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December 28, 2013. As of March 31, 2008, we had available $112.6 million under the revolving credit facility. As of June 16, 2008, we had available $112.6 million under the revolving credit facility.
The $150.0 million funded letter of credit facility utilizedprovides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into a credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time upon written notice to the lenders. The funded letter of credit facility expires on December 28, 2010.
The Credit Facility incorporates the following pricing by facility type:
| | |
| • | Tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). |
|
| • | Revolving loan borrowings bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). |
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| • | Letters of credit issued under the $75.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per annum owing to the issuing lender. |
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| • | Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit. |
In addition to the fees stated above, the Credit Facility requires the borrower to pay 0.50% per annum in commitment fees on the unused portion of the revolving loan facility.
The Credit Facility requires the borrower to prepay outstanding loans, subject to certain exceptions, with:
| | |
| • | 100% of the net asset sale proceeds received from specified asset sales and net insurance/ condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations; |
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| • | 100% of the cash proceeds from the incurrence of specified debt obligations; and |
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| • | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 or 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00. |
Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving letters of credit and
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funded letters of credit. Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.
The Credit Facility contains customary covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The Credit Facility provides that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap or the Partnership’s partnership agreement without the prior written approval of the lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.
The Credit Facility also requires the borrower to maintain certain financial ratios as follows:
| | | | |
| | Minimum
| | |
| | Interest
| | Maximum
|
| | Coverage
| | Leverage
|
Fiscal Quarter Ending | | Ratio | | Ratio |
|
| June 30, 2008 | | 3.25:1.00 | | 3.00:1.00 |
| September 30, 2008 | | 3.25:1.00 | | 2.75:1.00 |
| December 31, 2008 | | 3.25:1.00 | | 2.50:1.00 |
| March 31, 2009 and thereafter | | 3.75:1.00 | | 2.25:1.00 to
December 31, 2009
2.00:1.00 thereafter |
The computation of these ratios is governed by the specific terms of the Credit Facility and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general, under the terms of our Credit Facility, consolidated adjusted EBITDA is calculated by adding consolidated net income, consolidated interest expense, income taxes, depreciation and amortization, other non- cash expenses, any fees and expenses related to permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests and major scheduled turnaround expenses. As of the date of this prospectus, we were in compliance with our covenants under the Credit Facility.
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We present consolidated adjusted EBITDA because it is a material component of material covenants within our current Credit Facility and significantly impacts our liquidity and ability to borrow under our revolving line of credit. However, consolidated adjusted EBITDA is not a defined term under GAAP and should not be considered as an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the Credit Facility as follows:
| | | | | | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | |
| | | Predecessor and
| | | | |
| | | Successor
| | | | |
| | | Combined
| | | | |
| | | (Non-GAAP) | | | Successor | |
| | | Year Ended December 31, | | | | Three Months Ended March 31, | |
Consolidated Financial Results | | 2005 | | | 2006 | | | 2007 | | | | 2007 | | | 2008 | |
| | | (unaudited) | | | (in millions) | | | | | | | (unaudited in millions) | |
| Net income (loss) | | $ | (66.8 | ) | | $ | 191.6 | | | $ | (67.6 | ) | | | $ | (154.4 | ) | | $ | 22.2 | |
| Plus: | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 25.1 | | | | 51.0 | | | | 68.4 | | | | | 14.2 | | | | 19.6 | |
| Interest expense | | | 32.8 | | | | 43.9 | | | | 61.1 | | | | | 11.9 | | | | 11.3 | |
| Income tax expense (benefit) | | | (26.9 | ) | | | 119.8 | | | | (88.5 | ) | | | | (47.3 | ) | | | 6.9 | |
| Loss on extinguishment of debt | | | 8.1 | | | | 23.4 | | | | 1.3 | | | | | — | | | | — | |
| Inventory fair market value adjustment | | | 16.6 | | | | — | | | | — | | | | | — | | | | — | |
| Funded letters of credit expenses and interest rate swap not included in interest expense | | | 2.3 | | | | — | | | | 1.8 | | | | | — | | | | 0.9 | |
| Major scheduled turnaround expense | | | — | | | | 6.6 | | | | 76.4 | | | | | 66.0 | | | | — | |
| Loss on termination of Swap | | | 25.0 | | | | — | | | | — | | | | | — | | | | — | |
| Unrealized (gain) or loss on derivatives | | | 229.8 | | | | (128.5 | ) | | | 113.5 | | | | | 126.9 | | | | 18.9 | |
| Non-cash compensation expense for equity awards | | | 1.8 | | | | 16.9 | | | | 43.5 | | | | | 3.7 | | | | (0.4 | ) |
| (Gain) or loss on disposition of fixed assets | | | — | | | | 1.2 | | | | 1.3 | | | | | — | | | | — | |
| Expenses related to acquisition | | | 3.5 | | | | — | | | | — | | | | | — | | | | — | |
| Minority interest in subsidiaries | | | — | | | | — | | | | (0.2 | ) | | | | (0.7 | ) | | | — | |
| Management fees | | | 2.3 | | | | 2.3 | | | | 11.7 | | | | | 0.5 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | |
| Consolidated adjusted EBITDA | | $ | 253.6 | | | $ | 328.2 | | | $ | 222.7 | | | | $ | 20.8 | | | $ | 79.4 | |
| | | | | | | | | | | | | | | | | | | | | | |
In addition to the financial covenants summarized in the table above, the Credit Facility restricts the capital expenditures of Coffeyville Resources, LLC to $125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and $50.0 million in 2011 and thereafter. The capital expenditures covenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe the limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our Credit Facility.
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The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20.0 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20.0 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20.0 million, events relating to employee benefit plans resulting in liability in excess of $20.0 million, a change in control, the guarantees, collateral documents or the Credit Facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the Credit Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.
Under the terms of our Credit Facility, our initial public offering was deemed a “Qualified IPO” because the offering generated more than $250.0 million of gross proceeds and we used the proceeds of the offering to repay at least $275.0 million of term loans under the Credit Facility. As a result of our Qualified IPO, the interest margin on LIBOR loans may in the future decrease from 3.25% to 2.75% (if we have credit ratings of B2/B) or 2.50% (if we have credit ratings of B1/B+). Interest on base rate loans will similarly be adjusted. In addition, as a result of our Qualified IPO, (1) we will be allowed to borrow an additional $225.0 million under the Credit Facility after June 30, 2008 to finance capital enhancement projects if we are in pro forma compliance with the financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we will be allowed to pay an additional $35.0 million of dividends each year, if our corporate family ratings are at least B2 from Moody’s and B from S&P, (3) we will not be subject to any capital expenditures limitations commencing with fiscal 2009 if our total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter ending December 31, 2008, and (4) at any time after March 31, 2008 we will be allowed to reduce the Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or equal to 1.25:1 and we have a corporate family rating of at least B2 from Moody’s and B from S&P.
The Credit Facility is subject to an intercreditor agreement among the lenders and the Cash Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.
At March 31, 2008 and December 31, 2007, funded long-term debt, including current maturities, totaled $488.0 million and $489.2 million, respectively, of tranche D term loans. Other commitments at March 31, 2008 and December 31, 2007 included a $150.0 million funded letter of credit facility and a $150.0 million revolving credit facility. As of March 31, 2008, the commitment outstanding on the revolving credit facility was $37.4 million, including $5.8 million in letters of credit in support of certain environmental obligations and $31.6 million in letters of credit to secure transportation services for crude oil. As of December 31, 2007, the commitment outstanding on the revolving credit facility was $39.4 million, including $5.8 million in letters of credit in support of certain environmental obligations, $3.0 million in support of surety bonds in place to support state and federal excise tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for crude oil.
August 2007 Credit Facilities
The 2007 flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. We did not generate any material revenue while our facilities were shut down due to the flood, but we incurred and continue to incur significant flood repair and cleanup costs, as well as
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incremental legal, public relations and crisis management costs. We also had significant contractual obligations to purchase gathered crude oil. We also owed J. Aron approximately $123.7 million under the Cash Flow Swap, which we deferred to January 31, 2008 (see “— Payment Deferrals Related to Cash Flow Swap” below). In addition, although we believe that we will recover substantial sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery.
As a result of these factors, in August 2007 our subsidiaries entered into three new credit facilities.
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| • | $25.0 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $25.0 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $75.0 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility. |
All indebtedness outstanding under the $25.0 million secured facility and the $25.0 million unsecured facility was notrepaid in place inOctober 2007 with the prior period, management fees, deferred compensation, office expensesproceeds of our initial public offering, and outside services.all three facilities were terminated at that time.
Interest Expense.Payment Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 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. We reportedare required to use 37.5% of our consolidated interest expenseexcess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts, but as of March 31, 2008 we were not required to prepay any portion of the deferred amount.
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| • | On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%. |
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| • | On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued |
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| | interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million, plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%. |
Nitrogen Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time to time, seek to raise capital through a public or private offering of limited partner interests in the Partnership. Any decision to pursue such a transaction would be made in the discretion of the managing general partner, not us, and any proceeds raised in a primary offering would be for the six months ended June 30, 2006benefit of $22.3 millionthe Partnership, not us (although in some cases, depending on the structure of the transaction, the Partnership might remit proceeds to us). If the managing general partner elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as compared to interest expense of $8.8 million for the six months ended June 30, 2005. This 153% increase for the six months ended June 30, 2006well as compared to the six months ended June 30, 2005 wasCash Flow Swap, in order to remove the directPartnership and its subsidiaries as obligors under such instruments. Any such amendments could result in significant changes to our Credit Facility’s pricing, mandatory repayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of increased borrowings associatedadditional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend our Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our current borrowing facility completed in association with“commercially reasonable efforts” to obtain such amendments if we do not effect the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) andrequested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the actual rateterms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140.0 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and to distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering. If the managing general partner sells interests to third party investors, we expect that the Partnership may at such time seek to enter into its own credit facility.
The Partnership filed a registration statement in February 2008 for an initial public offering of its common units. On June 13, 2008, we announced that the managing general partner of the Partnership has decided to postpone indefinitely the Partnership’s initial public offering due to current market conditions for master limited partnerships. We believe maintaining the fertilizer business within the Company provides greater value for CVR Energy shareholders than would be the case if the Partnership became a publicly-traded partnership at this time. The Partnership subsequently
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requested that the registration statement be withdrawn. The Partnership may elect to move forward with a public or private offering in the future. Any future public or private offering by the Partnership would be made solely at the discretion of the Partnership’s managing general partner, subject to our specified joint management rights, and would be subject to market conditions and negotiation of terms acceptable to the Partnership’s managing general partner. In connection with the Partnership’s initial public or private offering, if any, the Partnership may require us to include a sale of a portion of our borrowings dueinterests in the Partnership. If the Partnership becomes a public company, we may consider a secondary offering of interests which we own (either in connection with a public offering by the Partnership, but subject to increases bothpriority rights in index rates (LIBORfavor of the Partnership, or following completion of the Partnership’s initial public offering, if any) or in a private placement. We cannot assure you that any such transaction will be consummated. Neither the consent of the managing general partner nor the consent of the Partnership is required for any sale of our interests in the Partnership, other than customary blackout periods relating to offerings by the Partnership. Any proceeds raised would be for our benefit. The Partnership has granted us registration rights which will require the Partnership to register our interests with the SEC at our request from time to time (following any public offering by the Partnership), subject to various limitations and prime rate)requirements. We cannot assure you that any such transaction will be consummated.
Capital Spending
We divide our capital spending needs into two categories: non-discretionary, which is either capitalized or expensed, and applicable margins.discretionary, which is capitalized. Non-discretionary capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety regulations. The comparabilitytotal non-discretionary capital spending needs for our refinery business and the nitrogen fertilizer business, including major scheduled turnaround expenses, were approximately $170 million in 2006 and $218 million in 2007 and we estimate that the total non-discretionary capital spending needs of interest expenseour refinery business and the nitrogen fertilizer business will be approximately $279 million in the aggregate over the three-year period beginning 2008. These estimates include, among other items, the capital costs necessary to comply with environmental regulations, including Tier II gasoline standards and on-road diesel regulations. As described above, our credit facility limits the amount we can spend on capital expenditures.
Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately $68 million in the comparable periodsaggregate between 2008 and 2010. These amounts are reflected in the table below under “Environmental and safety capital needs.” See “Business — Environmental Matters — Fuel Regulations — Tier II, Low Sulfur Fuels.”
The following table sets forth our estimate of non-discretionary spending for our refinery business and the nitrogen fertilizer business for the years presented as of March 31, 2008 (other than 2006 and 2007 which reflect actual spending). Capital spending for the nitrogen fertilizer business has been impactedand will be determined by the differingmanaging general partner of the Partnership. The data contained in the table below represents our current plans, but these plans may change as a result of unforeseen
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circumstances and we may revise these estimates from time to time or not spend the amounts in the manner allocated below.
Petroleum Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
| |
| Environmental and safety capital needs | | $ | 144.6 | | | $ | 121.8 | | | $ | 46.0 | | | $ | 53.9 | | | $ | 23.5 | | | $ | 2.6 | | | $ | 2.1 | | | $ | 394.5 | |
| Sustaining capital needs | | | 11.8 | | | | 14.9 | | | | 22.0 | | | | 29.8 | | | | 22.3 | | | | 22.0 | | | | 22.0 | | | | 144.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 156.4 | | | | 136.7 | | | | 68.0 | | | | 83.7 | | | | 45.8 | | | | 24.6 | | | | 24.1 | | | | 539.3 | |
| Major scheduled turnaround expenses | | | 4.0 | | | | 76.4 | | | | — | | | | — | | | | 50.0 | | | | — | | | | — | | | | 130.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 160.4 | | | $ | 213.1 | | | $ | 68.0 | | | $ | 83.7 | | | $ | 95.8 | | | $ | 24.6 | | | $ | 24.1 | | | $ | 669.7 | |
Nitrogen Fertilizer Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | (in millions) | |
| |
| Environmental and safety capital needs | | $ | 0.1 | | | $ | 0.5 | | | $ | 2.2 | | | $ | 4.5 | | | $ | 2.6 | | | | 2.7 | | | | 3.8 | | | $ | 16.4 | |
| Sustaining capital needs | | | 6.6 | | | | 3.9 | | | | 9.7 | | | | 3.1 | | | | 4.5 | | | | 4.8 | | | | 4.3 | | | | 36.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 6.7 | | | | 4.4 | | | | 11.9 | | | | 7.6 | | | | 7.1 | | | | 7.5 | | | | 8.1 | | | | 53.3 | |
| Major scheduled turnaround expenses | | | 2.6 | | | | — | | | | 2.8 | | | | — | | | | 2.6 | | | | — | | | | 2.8 | | | | 10.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 9.3 | | | $ | 4.4 | | | $ | 14.7 | | | $ | 7.6 | | | $ | 9.7 | | | $ | 7.5 | | | $ | 10.9 | | | $ | 64.1 | |
Combined
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
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| Environmental and safety capital needs | | $ | 144.7 | | | $ | 122.3 | | | $ | 48.2 | | | $ | 58.4 | | | $ | 26.1 | | | | 5.3 | | | | 5.9 | | | $ | 410.9 | |
| Sustaining capital needs | | | 18.4 | | | | 18.8 | | | | 31.7 | | | | 32.9 | | | | 26.8 | | | | 26.8 | | | | 26.3 | | | | 181.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 163.1 | | | | 141.1 | | | | 79.9 | | | | 91.3 | | | | 52.9 | | | | 32.1 | | | | 32.2 | | | | 592.6 | |
| Major scheduled turnaround expenses | | | 6.6 | | | | 76.4 | | | | 2.8 | | | | — | | | | 52.6 | | | | — | | | | 2.8 | | | | 141.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 169.7 | | | $ | 217.5 | | | $ | 82.7 | | | $ | 91.3 | | | $ | 105.5 | | | $ | 32.1 | | | $ | 35.0 | | | $ | 733.8 | |
We undertake discretionary capital structuresspending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of Successorexisting capacity, improvement in product yields,and/or a reduction in direct operating expenses. As of December 31, 2007, we had committed approximately $14 million towards discretionary capital spending in 2008. Other than the nitrogen fertilizer plant expansion project referred to below, we anticipate that our discretionary capital spending will average approximately $35 million per year between 2008 and Immediate Predecessor periods.2012.
The Partnership is currently moving forward with an approximately $120 million fertilizer plant expansion, of which approximately $11 million was incurred as of March 31, 2008. We estimate this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010. This project is also expected to improve the cost structure of the nitrogen fertilizer business by eliminating the need for rail shipments of ammonia, thereby avoiding anticipated cost increases in such transport.
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Cash Flows
The following table sets forth our cash flows for the periods indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | |
| | | Predecessor | | | Successor | |
| | | 174 Days
| | | 233 Days
| | | Year
| | | | |
| | | Ended
| | | Ended
| | | Ended
| | | Three Months
| |
| | | June 23, | | | December 31, | | | December 31, | | | Ended March 31, | |
| | | 2005 | | | 2005 | | | 2006 | | | 2007 | | | 2007 | | | 2008 | |
| | | | | | | | | | | | | | | (unaudited) | | | (unaudited) | |
| | | (in millions) | |
| |
| Net cash provided by (used in) | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 12.7 | | | $ | 82.5 | | | $ | 186.6 | | | $ | 145.9 | | | $ | 44.1 | | | $ | 24.2 | |
| Investing activities | | | (12.3 | ) | | | (730.3 | ) | | | (240.2 | ) | | | (268.6 | ) | | | (107.3 | ) | | | (26.2 | ) |
| Financing activities | | | (52.4 | ) | | | 712.5 | | | | 30.8 | | | | 111.3 | | | | 28.9 | | | | (3.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | $ | (52.0 | ) | | $ | 64.7 | | | $ | (22.8 | ) | | $ | (11.4 | ) | | $ | (34.3 | ) | | $ | (5.4 | ) |
In addition, we are currently entitled to all cash distributed by the Partnership. However, the amount of cash flows from the Partnership that we will receive in the future may be limited by a number of factors. The Partnership may enter into its own credit facility or other contracts that limit its ability to make distributions to us. Additionally, in the future the managing general partner of the Partnership will receive a greater allocation of distributions as more cash becomes available for distribution, and consequently we will receive a smaller percentage of quarterly distributions over time. Our rights to distributions will also be adversely affected if the Partnership consummates a public or private equity offering in the future. See “—“Risk Factors Affecting Comparability.— Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “Risk Factors — Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the establishment of cash reserves.”
Interest Income.Cash Flows Provided by Operating Activities Interest income increased $1.2 million, or 240%, from $0.5 million in the six months ended June 30, 2005 to $1.7 million in the six months ended June 30, 2006 due to larger cash balances and higher yields on invested cash.
Gain (loss) on Derivatives.Comparison of the Three Months Ended March 31, 2008 and the Three Months Ended March 31, 2007 For
Net cash flows from operating activities for the sixthree months ended June 30, 2006, we reported $126.5 million in losses on derivatives. This compares to a $159.5 million loss on derivatives during the comparableMarch 31, 2008 was $24.2 million. The positive cash flow from operating activities generated over this period of 2005. This decrease in losses on derivatives was primarily attributable to our Cash Flow Swapdriven by favorable changes in other working capital and other assets and liabilities, partially offset by unfavorable changes in trading working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment for all of our derivative transactions.derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap and our other derivative instruments dodoes not qualify as hedgesa hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. The $159.5 millionTherefore, the net loss on derivatives duringfor the sixthree months ended June 30, 2005March 31, 2008 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2008 (approximately two years and three months) and the NYMEX crack spread that is inclusive of the expensing of a $25.0 million option entered into by Successorbasis for the purposeunderlying swaps had increased, the unrealized losses on the Cash
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Flow Swap significantly decreased our net income over this period. The impact of hedging certain levelsthese unrealized losses on the Cash Flow Swap is apparent in the $20.8 million increase in the payable to swap counterparty. Other sources of refined product margins. At closingcash in other working capital included $16.6 million of deferred revenue related to prepaid fertilizer shipments and a $5.2 increase in accrued income taxes. Trade working capital for the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless whichthree months ended March 31, 2008 resulted in a use of cash of $67.5 million. For the expensing of the associated premium in the sixthree months ended June 30, 2005. See “— QuantitativeMarch 31, 2008, accounts receivable increased $30.7 million, inventory increased by $31.6 and Qualitative Disclosures About Market Risk — Commodity Price Risk.”accounts payable decreased by $5.2 million.
Extinguishment of Debt. On June 24, 2005 and in connection withNet cash flows provided by operating activities for the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC (see “— Factors Affecting Comparability”), we raised $800.0 million in long-term debt commitments under both the First Lien Credit Facility and Second Lien Credit Facility. See “— Liquidity and Capital Resources — Debt.” As a result of the retirement of Immediate Predecessor’s outstanding indebtedness consisting of $150.0 million term loan and revolving credit facilities, we recognized $8.1 million as a loss on extinguishment of debt in 2005. There was no similar expense in 2006.
Other Income (Expense). For the sixthree months ended June 30, 2006, other income (expense) increased $1.0 million to $0.2 millionMarch 31, 2007 was $44.1 million. The positive cash flow from a loss of $0.8 million for the comparableoperating activities during this period of 2005. This change was primarily the result of asbestos related accruals, which resultedchanges in other expenseassets and liabilities offset by unfavorable changes in trade working capital and other working capital. Net income for the period was not indicative of the operating margins for the period. This was the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net loss for the three months ended March 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2007 (approximately three years and three months years) and the NYMEX crack spread that is the basis for the underlying swaps had increased during the six months ending June 30, 2005.
Provision for Income Taxes. Income tax expenseperiod, the unrealized losses on the Cash Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $129.3 million increase in the payable to swap counterparty. Adding to our operating cash flow for the sixthree months ended June 30, 2006March 31, 2007 was $25.7a $68.0 million or 38.1%source of earnings beforecash related to a decrease in trade working capital. For the three months ended March 31, 2007, accounts receivable decreased $44.6 million while inventory increased $23.0 million and accounts payable increased $46.4 million. The change in trade working capital was primarily driven by the impact of the refinery turnaround that began in February 2007. The primary use of cash during the period was $41.3 million for deferred income taxes as compared to a tax benefitprimarily the result of $20.0 million for the six months ended June 30, 2005. The effective tax rate for 2005 was impacted by a realizedunrealized loss on option agreements that expired unexercised. Coffeyville Acquisition LLC was party to these agreements and the loss was incurred at that level which we effectively treated as a permanent non-deductible loss.
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Net Income. For the six months ended June 30, 2006, net income increased $99.6 million to $41.8 million as compared to a net loss of $57.8 million in the six months ended June 30, 2005, primarily due to improved margins as noted above.Cash Flow Swap.
Comparison of the Year Ended December 31, 2005 (Non-GAAP Combined) Compared to2007, the Year Ended December 31, 2004 (Non-GAAP Combined).2006, the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.
Net Sales. Consolidated net sales increased $694 million, or 40%, to $2,435.0 million in the year ended December 31, 2005cash flows from $1,741.0 millionoperating activities for the year ended December 31, 2004. This increase2007 was $145.9 million. The positive cash flow from operating activities generated over this period was primarily due to an increasedriven by favorable changes in petroleumother working capital partially offset by unfavorable changes in trade working capital and other assets and liabilities over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net sales of $634.8 million, as described above, and an increase in nitrogen fertilizer net sales of $60.1 million, as described above.
Gross Margin Excluding Manufacturing Expenses. Consolidated gross margin excluding manufacturing expenses increased by $224.4 million, or 79%, to $507.7 millionloss for the year ended December 31, 20052007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2007 (approximately two years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap significantly decreased our Net Income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $240.9 million increase in the payable to swap counterparty. Other sources of cash from $283.3other working capital included $4.8 million from prepaid expenses and other current assets, $27.0 million from other current liabilities and $20.0 million in insurance proceeds. Reducing our operating cash flow for the year ended December 31, 2004. This increase2007 was primarily$42.9 million use of cash related to changes in trade working capital. For the year ended December 31, 2007, accounts receivable increased $17.0 million and inventory increased by $85.0 million resulting in a net use of cash of $102.0 million. These uses of cash due to changes in trade working
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capital were partially offset by an increase in petroleum gross margin excluding manufacturing expensesaccounts payable, or a source of $163.3cash, of $59.1 million. Other primary uses of cash during the period include a $105.3 million as described above, and an increase in nitrogen fertilizer margin excluding manufacturing expensesour insurance receivable related to the flood and a $57.7 million use of $52.0 million duecash related to increased net sales, as described above.deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
Manufacturing Expenses Excluding Depreciation and Amortization. Consolidated manufacturing expenses excluding depreciation and amortization increased by $27.1 million, or 18%, to $175.2 millionNet cash flows from operating activities for the year ended December 31, 20052006 was $186.6 million. The positive cash flow from $148.1 millionoperating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other assets and liabilities, partially offset by unfavorable changes in trade working capital and other working capital over the period. Net income for the year ended December 31, 2004. This increaseperiod was due to an increase in petroleum manufacturing expensesnot indicative of $21.8 million, offset by a decrease in nitrogen fertilizer manufacturing expenses of $3.8 million.
Depreciation and Amortization Included in Gross Profit. Consolidated depreciation and amortization included in gross profit increased by $22.0 million, or 786%, to $24.8 millionthe operating margins for the year ended December 31, 2005 from $2.8 million for the year ended December 31, 2004.period. This increase was due to an increase in petroleum depreciation and amortization of $14.5 million and in nitrogen fertilizer depreciation and amortization of $7.7 million.
Operating Income. Consolidated operating income increased by $159.6 million, or 144%, to $270.8 million for the year ended December 31, 2005 from $111.2 million for the year ended December 31, 2004. Petroleum operating income increased $114.9 million and nitrogen fertilizer operating income increased by $44.6 million.
Selling, General and Administrative Expenses. Consolidated selling, general and administrative expenses increased $15.7 million, or 74.1%, to $36.9 million for the year ended December 31, 2005 from $21.2 million for the year ended December 31, 2004. This increase was primarilyis the result of increasesthe accounting treatment of our derivatives in insurance costs associated with Successor’s $1.25 billion property insurance limit requirement, letter of credit fees due under our $150.0 million funded letter of credit facility utilized as collateral forgeneral and more specifically, the Cash Flow Swap which was not in place in the prior period, management fees, discretionary bonuses and the write-off of unearned compensation associated with the Subsequent Acquisition.
Interest Expense. Consolidated interest expense for the year ended December 31, 2005 was $32.8 million as compared to interest expense of $10.1 million for the year ended December 31, 2004. This 225% increase for 2005 was the direct result of increased borrowings in 2005 associated with our current borrowing facility completed in association with the Subsequent Acquisition (See “— Liquidity and Capital Resources — Debt”) and an increase in the actual rate of our borrowings due to both increases in index rates (LIBOR and prime rate) and applicable margins. The comparability of 2005 and 2004 interest expense has been impacted by the differing capital structures of Successor, Immediate Predecessor and Original Predecessor. See “— Factors Affecting Comparability.”
Interest Income. Interest income increased $1.3 million, or 650%, from $0.2 million in the year ended December 31, 2004 to $1.5 million in the year ended December 31, 2005, due to larger cash balances and higher yields on invested cash.
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Gain (loss) on Derivatives. For the year ended December 31, 2005, we reported $323.7 million in losses on derivatives. This compared to a $0.5 million gain on derivatives during 2004. This dramatic increase in losses on derivatives was primarily attributable to our Cash Flow Swap and the accounting treatment for all of our derivative transactions.Swap. We have determined that the Cash Flow Swap and our other derivative instruments dodoes not qualify as hedgesa hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the year ended December 31, 20052006 included both the realized losses and the unrealized lossesgains on all derivatives.the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 20052006 (approximately four years)three years and six months) and the NYMEX crack spread that is the basis for the underlying swap contracts that comprisedswaps had declined, the unrealized gains on the Cash Flow Swap significantly increased our net income over this period. The impact of these unrealized gains on the Cash Flow Swap is apparent in the $147.0 million decrease in the payable to swap counterparty. Reducing our operating cash flow for the year ended December 31, 2006 was a $0.3 million use of cash related to an increase in trade working capital. For the year ended December 31, 2006, accounts receivable decreased approximately $1.9 million while inventory increased $7.2 million and accounts payable increased $5.0 million. Other primary uses of cash during the period include a $5.4 million increase in prepaid expenses and other current assets and a $37.0 million reduction in accrued income taxes. Offsetting these uses of cash was an $86.8 million increase in deferred income taxes primarily the result of the unrealized gain on the Cash Flow Swap and a $4.6 million increase in other current liabilities.
Analysis of cash flows from operating activities for the year ended December 31, 2005 was impacted by the Subsequent Acquisition. See “— Factors Affecting Comparability.” For instance, completion of the Subsequent Acquisition by Successor required a mark up of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold. Therefore, the discussion of cash flows from operations has been broken down into the 174 days ended June 23, 2005 and the 233 days ended December 31, 2005.
Net cash flows from operating activities for the 174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by income of $52.4 million, offset by a $54.3 million increase in trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.
Net cash flows provided by operating activities for the 233 days ended December 31, 2005 was $82.5 million. The positive cash flow from operating activities generated over this period was primarily the result of strong operating earnings during the period partially offset by the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins and the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. At the closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless and thus resulted in the expensing of the associated premium. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and “— Results of Operations — Consolidated Results of Operations — Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Consolidated).” We have determined that the Cash Flow Swap does not
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qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net income for the year ended December 31, 2005 included the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap became effective July 1, 2005 and had an original term of approximately five years and the NYMEX crack spread that is the basis for the underlying swaps had improved substantially,since the trade date of the Cash Flow Swap on June 16, 2005, the unrealized losses on the Cash Flow Swap increased significantly as of December 31, 2005.reduced our net income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, resultedis apparent in unrealized losses of $229.8the $256.7 million for 2005. Realized losses on derivative transaction comprisedincrease in the balance of the losses for 2005 or $93.9 million. See “— Quantitativepayable to swap counterparty. Additionally and Qualitative Disclosures About Market Risk — Commodity Price Risk.”
Extinguishment of Debt. On June 24, 2005 and in connection with the acquisition of Immediate Predecessor by Coffeyville Acquisition LLC (see “— Factors Affecting Comparability”), we raised $800.0 million in long-term debt commitments under the First Lien Credit Facility and the Second Lien Credit Facility. Asas a result of the retirementclosing of Immediate Predecessor’s outstanding indebtedness consistingthe Subsequent Acquisition, Successor marked up the value of $150.0 million term loan and revolving credit facilities, we recognized $8.1 million as a losspurchased inventory to fair market value at the closing of the transaction on extinguishment of debt inJune 24, 2005. This compareshad the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold. The total impact of this for the 233 days ended December 31, 2005 was $14.3 million. Trade working capital provided $8.0 million in cash during the 233 days ended December 31, 2005 as an increase in accounts receivable was more than offset by decreases in inventory and an increase in accounts payable. Offsetting the sources of cash from operating activities highlighted above was a $98.4 million use of cash related to deferred income taxes and a loss on extinguishment$4.7 million use of debtcash related to other long-term assets.
Cash Flows Used In Investing Activities
Comparison of $7.2the Three Months Ended March 31, 2008 and the Three Months Ended March 31, 2007
Net cash used in investing activities for the three months ended March 31, 2008 was $26.2 million compared to $107.4 million for the three months ended March 31, 2007. The decrease in investing activities for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007 was the result of decreased capital expenditures associated with various capital projects that commenced in the first quarter of 2007 in conjunction with the refinery turnaround.
Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006
Net cash used in investing activities for the year ended December 31, 2007 was $268.6 million compared to $240.2 million for the year ended December 31, 2004. On May 10, 2004, we used proceeds from a $150.0 million term loan to pay off our then existing debt which was originally incurred on March 3, 2004. In connection with the extinguishment of debt, we recognized $7.2 million as a loss on extinguishment of debt2006. The increase in the 304 day period ended December 31, 2004.
Other Income (Expense). Forinvesting activities for the year ended December 31, 2005, other income (expense) decreased $1.4 million2007 as compared to an expense of $1.3 million from income of $0.1 million in 2004. This decreasethe year ended December 31, 2006 was primarily the result of asbestos related accrualsincreased capital expenditures associated with various capital projects in 2005.our petroleum business.
ProvisionNet cash used in investing activities was $12.3 million for Income Taxes. Our income tax benefit inthe 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was $(26.9) million, or 28.7% of loss before income tax, as compared to $33.8approximately $57.4 million in 2004. The effective tax rate for 2005 was impacted by a realized loss on option agreements that expired unexercised. Coffeyville Acquisition LLC was the party to these agreements and the loss was incurred at that level which we effectively treated as a permanent non-deductible loss, therefore generating a lower effective tax rate on the net loss for the year.
Net Income. For the year ended December 31, 2005, net income decreased $127.7 million to a loss of $66.8 million as compared to net income of $60.9 million in 2004, primarily due to losses on derivatives offset by improved margins in the year ending December 31, 2005 as compared to 2004, as described above.capital expenditures.
Year Ended December 31, 2004 (Non-GAAP Combined)2006 Compared to Yearthe 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2003.2005.
Net cash used in investing activities for the year ended December 31, 2006 was $240.2 million compared to $12.3 million for the 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the year ended December 31, 2006 was the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.
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Cash Flows (Used in) Provided by Financing Activities
Comparison of the Three Months Ended March 31, 2008 and the Three Months Ended March 31, 2007
Net Sales.cash used for financing activities for the three months ended March 31, 2008 was $3.4 million as compared to net cash provided by financing activities of $29.0 million for the three months ended March 31, 2007. During the three months ended March 31, 2008, we paid $1.2 million of scheduled principal payments and deferred $2.1 million of initial public offering costs related to CVR Partners, LP. For the three months ended March 31, 2007, the primary source of cash was the result of borrowings drawn on our revolving credit facility.
Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006 Consolidated net sales increased $478.8 million, or 38%, to $1,741 million in
Net cash provided by financing activities for the year ended December 31, 2004 from $1,262.22007 was $111.3 million as compared to net cash provided by financing activities of $30.8 million for the year ended December 31, 2003.2006. The increase was primarily due to an increase in petroleum net salesprimary sources of $471.1 million, as described above, and an increase in nitrogen fertilizer net sales of $12.0 million, as described above.
Gross Margin Excluding Manufacturing Expenses. Consolidated gross margin excluding manufacturing expenses increased by $77.6 million, or 38%, to $283.3 millioncash for the year ended December 31, 2004 from $205.72007 were obtained through $399.6 million of proceeds associated with our initial public offering. The primary uses of cash for the year ended December 31, 2003. This increase2007 was primarily due$335.8 million of long-term debt retirement and $2.5 million in payments of financing costs. The primary sources of cash for the year ended December 31, 2006 were obtained through a refinancing of the Successor’s first and second lien credit facilities into a new long term debt credit facility of $1.075 billion, of which $775.0 million was outstanding as of December 31, 2006. The $775.0 million term loan under the credit facility was used to an increaserepay approximately $527.7 million in petroleum gross margin excluding manufacturing expensesfirst and second lien debt outstanding, fund $5.5 million in prepayment penalties associated with the second lien credit facility and fund a $250.0 million cash distribution to Coffeyville Acquisition LLC. Other sources of $67.4cash included $20.0 million as described above.of additional equity contributions into Coffeyville Acquisition LLC, which was subsequently contributed to our operating subsidiaries, and $30.0 million of additional delayed draw term loans issued under the first lien credit facility. During this period, we also paid $1.7 million of scheduled principal payments on the first lien term loans.
For the combined period ended December 31, 2005, net cash provided by financing activities was $660.0 million. The primary sources of cash for the combined periods ended December 31, 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $227.7 million of equity. Additional equity of $10.0 million was contributed into Coffeyville Acquisition LLC subsequent to the aforementioned acquisition, which was subsequently contributed to our operating subsidiaries, in order to fund a portion of two discretionary capital expenditures at our refining operations. Additional sources of funds during the year ended December 31, 2005 were obtained through the borrowing of $0.2 million in revolving loan proceeds, net of $69.6 million of repayments. Offsetting these sources of cash from financing activities during the year ended December 31, 2005 were $24.6 million in deferred financing costs associated with the first and second lien debt commitments raised by Successor in connection with the Subsequent Acquisition and a $52.2 million cash distribution to Immediate Predecessor prior to the Subsequent Acquisition. See “— Liquidity and Capital Resources — Debt.”
Working Capital
Working capital at March 31, 2008, was $21.5 million, consisting of $622.5 million in current assets and $601.0 million in current liabilities. Working capital at December 31, 2007 was $10.7 million, consisting of $570.2 million in current assets and $559.5 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of $112.6 million at March 31, 2008. In the current crude oil price environment, working capital is subject to substantial variability fromweek-to- week and month-to-month.
Letters of Credit
Our revolving credit facility provides for the issuance of letters of credit. At March 31, 2008, there were $37.4 million of irrevocable letters of credit outstanding, including $5.8 million in support of certain environmental obligators and $31.6 million to secure transportation services for crude oil.
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Manufacturing Expenses Excluding DepreciationCapital and Amortization.Commercial Commitments Consolidated manufacturing expenses excluding depreciation
In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of March 31, 2008 relating to long-term debt, operating leases, unconditional purchase obligations and amortization increased by $9.6 million, or 7%, to $148.1 millionother specified capital and commercial commitments for the year ended Decemberfive-year period following March 31, 20042008 and thereafter.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | | | | Nine Months
| | | | | | | | | | | | | | | | |
| | | | | | Ending
| | | | | | | | | | | | | | | | |
| | | Total | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Thereafter | |
| | | (in millions) | |
| |
Contractual Obligations | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt(1) | | $ | 488.0 | | | $ | 3.7 | | | $ | 4.8 | | | $ | 4.8 | | | $ | 4.7 | | | $ | 4.7 | | | $ | 465.3 | |
| Operating leases(2) | | | 8.9 | | | | 2.8 | | | | 3.3 | | | | 1.7 | | | | 0.9 | | | | 0.2 | | | | — | |
| Unconditional purchase obligations(3) | | | 582.3 | | | | 20.8 | | | | 28.2 | | | | 55.8 | | | | 53.9 | | | | 51.3 | | | | 372.3 | |
| Environmental liabilities(4) | | | 8.8 | | | | 2.6 | | | | 0.7 | | | | 1.6 | | | | 0.3 | | | | 0.3 | | | | 3.3 | |
| Funded letter of credit fees(5) | | | 10.1 | | | | 3.4 | | | | 4.5 | | | | 2.2 | | | | — | | | | — | | | | — | |
| Interest payments(6) | | | 142.0 | | | | 20.2 | | | | 26.6 | | | | 26.3 | | | | 26.1 | | | | 25.9 | | | | 16.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,240.1 | | | $ | 53.5 | | | $ | 68.1 | | | $ | 92.4 | | | $ | 85.9 | | | $ | 82.4 | | | $ | 857.8 | |
Other Commercial Commitments | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Standby letters of credit(7) | | $ | 37.4 | | | $ | 37.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
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| (1) | | Long-term debt amortization is based on the contractual terms of our Credit Facility. We may be required to amend our Credit Facility in connection with an offering by the Partnership. As of March 31, 2008, $488.0 million was outstanding under our credit facility. See “— Liquidity and Capital Resources — Debt.” |
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| (2) | | The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods. |
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| (3) | | The amount includes (1) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation and (2) commitments under an electric supply agreement with the city of Coffeyville. |
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| (4) | | Environmental liabilities represents (1) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (2) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters”. |
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| (5) | | This amount represents the total of all fees related to the funded letter of credit issued under our Credit Facility. The funded letter of credit is utilized as credit support for the Cash Flow Swap. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk”. |
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| (6) | | Interest payments are based on interest rates in effect at April 1, 2008 and assume contractual amortization payments. |
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| (7) | | Standby letters of credit include $5.8 million of letters of credit issued in connection with environmental liabilities and $31.6 million in letters of credit to secure transportation services for crude oil. |
In addition to the amounts described in the above table, we owe J. Aron approximately $123.7 million plus accrued interest ($5.8 million as of June 1, 2008) which will be due August 31, 2008 and approximately $54.0 million which will be due on July 8, 2008 for crude oil we settled or will settle with respect to the quarter ending June 30, 2008 based on June 16, 2008 pricing. Also, if the Partnership does not consummate an initial private or public offering by October 24, 2009, the managing general partner of the Partnership can require us to purchase the managing general partner interest at fair market value until the earlier of October 24, 2012 and the closing of the Partnership’s initial offering.
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Our ability to make payments on and to refinance our indebtedness, to repay the amounts owed to J. Aron, to purchase the Partnership’s managing general partner interest if the Partnership’s managing general partner exercises its put right, to fund planned capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to refining spreads, fertilizer margins, receipt of distributions from $138.5 million for the year ended December 31, 2003. The increase was primarily duePartnership and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our credit facility (or other credit facilities we may enter into in the future) in an increaseamount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in petroleum manufacturing expensesrecent periods have been extremely volatile and have experienced significant increases in the cost of $9.7 million.financing. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
DepreciationOff-Balance Sheet Arrangements
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and Amortization Included in Gross Profit. Consolidated depreciation and amortization included in gross profit decreased by $0.5 million, or 15%, to $2.8 million forregulations of the year ended December 31, 2004 from $3.3 million for the year ended December 31, 2003. This decrease was due to a decrease in petroleum depreciation and amortization of $0.3 million and a decrease in nitrogen fertilizer depreciation and amortization of $0.2 million.SEC.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Operating Income.Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price)”. The standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At March 31, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14 to our consolidated financial statements, “Fair Value Measurements”, included elsewhere in this prospectus.
In February 2008, the FASB issued FASB Staff Position157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will not have a material impact on the Company’s financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. Under this standard, an entity is required to provide additional information that will assist investors and other users of financial information to more easily understand the effect of the Company’s choice to use fair value on its earnings. Further, the entity is required to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 107,Disclosures about Fair Value of Financial Instruments. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of SFAS 159 did not impact the Company’s consolidated financial statements as of the quarter ended March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and
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requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of the acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR Energy will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141(R) will be limited to any future business combinations for which the acquisition date is on or after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,Non-controlling Interests in Consolidated operating income increased by $81.8 million, or 278%, to $111.2 millionFinancial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the year ended December 31, 2004 from $29.4 millionnon-controlling interest in a subsidiary and for the year ended December 31, 2003. Petroleum operating income increased $63.3 milliondeconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and nitrogen fertilizer operating income increased by $18.6 million.disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,Selling, GeneralDisclosures about Derivative Instruments and Administrative Expenses, Reorganization ExpensesHedging Activities — an amendment of FASB Statement No. 133. This statement will change the disclosure requirements for derivative instruments and Interest Expense. Consolidated selling, generalhedging activities. Entities are required to provide enhanced disclosures about how and administrative expenseswhy an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, net earnings, and cash flows. The Company will be required to adopt this statement as of January 1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Company’s consolidated financial statements.
The FASB recently issued final FASB Staff Position (“FSP”)No. APB 14-1Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement”. The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,Accounting for Derivative Instruments and Hedging Activities. Under the FSP, cash settled convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the period from March 2, 2004 throughliability and equity components in a manner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in subsequent periods. The FSP is effective for financial statements issued for fiscal years beginning after December 31, 2004 were $16.6 million. These expenses represented15, 2008, and interim periods within those fiscal years and will require issuers of convertible debt that can be settled in cash to record the cost associatedadditional expense incurred. The Company is currently evaluating the FSP in conjunction with corporate governance, legal expenses, treasury, accounting, marketing, human resources and maintaining corporate offices in New York and Kansas City. During the predecessor periods, Farmland allocated corporate overhead based on internal needs, which may not have been representative of the actual cost to operate the businesses. In addition, during the year ended December 31, 2003, Farmland incurred a number of charges related to its bankruptcy. As a result of the charges and issues related to allocations, a comparison of selling, general and administrative expenses for the year ended December 31, 2004 to the year ended December 31, 2003 is not meaningful.convertible debt offering.
Extinguishment of Debt. On May 10, 2004, we used proceeds from a $150.0 million dollar term loan to pay off our then existing debt which was originally incurred on March 3, 2004. In connection with the extinguishment of debt, we recognized $7.2 million as a loss on extinguishment of debt in the 304 day period ended December 31, 2004.
Provision for Income Taxes. Original Predecessor was not a separate legal entity, and its operating results were included with the operating results of Farmland and its subsidiaries in filing consolidated federal and state income tax returns. Farmland did not allocate income taxes to its divisions. As a result, Original Predecessor periods do not reflect any provision for income taxes.
Net Income. Net income increased $33.0 million in 2004 to $60.9 million from $27.9 million for the comparable period in 2003. This increase was due to both the change in ownership and improved results in both the petroleum business and the nitrogen fertilizer business as discussed in greater detail for each business above.
Critical Accounting PoliciesLiquidity and Capital Resources
Our primary sources of liquidity currently consist of cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap as well as our convertible notes offering, if consummated, and the proceeds of our proposed senior secured credit facility, if entered into. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and selling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses.
As of March 31, 2008 and June 16, 2008, we had cash, cash equivalents and short-term investments of $25.2 million and $71.4 million, respectively, and up to $112.6 million available under our revolving credit facility as of both dates. In the current crude oil price environment, working capital is subject to substantial variability from week-to-week and month-to-month. The payable to swap counterparty included in the consolidated balance sheet at March 31, 2008 was approximately $371.4 million, and the current portion included an increase of $32.6 million from December 31, 2007, resulting in an equal reduction in our working capital for the same period.
On June 30, 2007, our refinery and the nitrogen fertilizer plant were severely flooded and forced to conduct emergency shutdowns and evacuate. See “Flood and Crude Oil Discharge.” Our liquidity was significantly negatively impacted as a result of the reduction in cash provided by operations due to our temporary cessation of operations and the additional expenditures associated with the flood
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and crude oil discharge. In order to provide immediate and future liquidity, on August 23, 2007 we deferred payments which were due to J. Aron under the terms of the Cash Flow Swap. The J. Aron deferred amounts of $123.7 million (plus accrued interest of $5.8 million as of June 1, 2008) are due on August 31, 2008. See “— Liquidity and Capital Resources — Payment Deferrals Related to the Cash Flow Swap” for additional information about the payment deferral. These deferrals are supported by third-party guarantees. In addition, we estimate that we will owe J. Aron approximately $54 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2008 based on June 16, 2008 pricing.
Our liquidity was enhanced during the fourth quarter of 2007 by the receipt of the net proceeds from our initial public offering. We intend to use the net proceeds from the convertible notes offering, if consummated, and the proposed senior secured credit facility, if entered into, for general corporate purposes, which may include using a portion of the proceeds to pay amounts owed to J. Aron under the Cash Flow Swap and for other future capital investments. If the convertible notes offering is not consummatedand/or the proposed senior secured credit facility is not entered into, we intend to fund our operations through cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap. We believe these capital resources will be sufficient to satisfy the anticipated cash requirements associated with our existing operations for at least the next twelve months. However, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of various factors. Additionally, our ability to generate sufficient cash from our operating activities depends on our future performance, which is subject to general economic, political, financial, competitive and other factors beyond our control.
Debt
Proposed Secured Credit Facility
Concurrently with the closing of this offering, we anticipate that Coffeyville Resources, LLC will enter into a new $25.0 million senior secured term loan (the “proposed senior secured credit facility”). We anticipate that the proposed senior secured credit facility will be secured by the same collateral that secures our existing Credit Facility and will contain covenants substantially similar to the Credit Facility described below. Although we have begun negotiations on the new credit facility, we have not entered into any agreement regarding the proposed senior secured credit facility, and as such, there is no guarantee that we will be enter into a credit facility on the terms described above or at all.
Credit Facility
On December 28, 2006, our subsidiary, Coffeyville Resources, LLC, entered into a credit facility (the “Credit Facility”) which provided financing of up to $1.075 billion. The Credit Facility consisted of $775.0 million of tranche D term loans, a $150.0 million revolving credit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. On October 26, 2007, we repaid $280.0 million of the tranche D term loans with proceeds from our initial public offering. The Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including the equity of our subsidiaries on a first-lien priority basis.
The tranche D term loans outstanding are subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on April 1, 2007 and increasing to 23.5% of the outstanding principal balance on April 1, 2013 and the next two quarters, with a final payment of the aggregate outstanding balance on December 28, 2013.
The revolving credit facility of $150.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving credit facility are subject to a $75.0 million sub-limit. The revolving loan commitment expires on December 28, 2012. The borrower has an option to extend this maturity upon written notice to the lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is
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December 28, 2013. As of March 31, 2008, we had available $112.6 million under the revolving credit facility. As of June 16, 2008, we had available $112.6 million under the revolving credit facility.
The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into a credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time upon written notice to the lenders. The funded letter of credit facility expires on December 28, 2010.
The Credit Facility incorporates the following pricing by facility type:
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| • | Tranche D term loans bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). |
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| • | Revolving loan borrowings bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). |
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| • | Letters of credit issued under the $75.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per annum owing to the issuing lender. |
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| • | Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit. |
In addition to the fees stated above, the Credit Facility requires the borrower to pay 0.50% per annum in commitment fees on the unused portion of the revolving loan facility.
The Credit Facility requires the borrower to prepay outstanding loans, subject to certain exceptions, with:
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| • | 100% of the net asset sale proceeds received from specified asset sales and net insurance/ condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations; |
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| • | 100% of the cash proceeds from the incurrence of specified debt obligations; and |
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| • | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 or 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00. |
Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving letters of credit and
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funded letters of credit. Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.
The Credit Facility contains customary covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The Credit Facility provides that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap or the Partnership’s partnership agreement without the prior written approval of the lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.
The Credit Facility also requires the borrower to maintain certain financial ratios as follows:
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| | Minimum
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| | Interest
| | Maximum
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| | Coverage
| | Leverage
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Fiscal Quarter Ending | | Ratio | | Ratio |
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| June 30, 2008 | | 3.25:1.00 | | 3.00:1.00 |
| September 30, 2008 | | 3.25:1.00 | | 2.75:1.00 |
| December 31, 2008 | | 3.25:1.00 | | 2.50:1.00 |
| March 31, 2009 and thereafter | | 3.75:1.00 | | 2.25:1.00 to
December 31, 2009
2.00:1.00 thereafter |
The computation of these ratios is governed by the specific terms of the Credit Facility and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general, under the terms of our Credit Facility, consolidated adjusted EBITDA is calculated by adding consolidated net income, consolidated interest expense, income taxes, depreciation and amortization, other non- cash expenses, any fees and expenses related to permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests and major scheduled turnaround expenses. As of the date of this prospectus, we were in compliance with our covenants under the Credit Facility.
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We present consolidated adjusted EBITDA because it is a material component of material covenants within our current Credit Facility and significantly impacts our liquidity and ability to borrow under our revolving line of credit. However, consolidated adjusted EBITDA is not a defined term under GAAP and should not be considered as an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the Credit Facility as follows:
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| | | Immediate
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| | | Predecessor and
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| | | Successor
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| | | Combined
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| | | (Non-GAAP) | | | Successor | |
| | | Year Ended December 31, | | | | Three Months Ended March 31, | |
Consolidated Financial Results | | 2005 | | | 2006 | | | 2007 | | | | 2007 | | | 2008 | |
| | | (unaudited) | | | (in millions) | | | | | | | (unaudited in millions) | |
| Net income (loss) | | $ | (66.8 | ) | | $ | 191.6 | | | $ | (67.6 | ) | | | $ | (154.4 | ) | | $ | 22.2 | |
| Plus: | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 25.1 | | | | 51.0 | | | | 68.4 | | | | | 14.2 | | | | 19.6 | |
| Interest expense | | | 32.8 | | | | 43.9 | | | | 61.1 | | | | | 11.9 | | | | 11.3 | |
| Income tax expense (benefit) | | | (26.9 | ) | | | 119.8 | | | | (88.5 | ) | | | | (47.3 | ) | | | 6.9 | |
| Loss on extinguishment of debt | | | 8.1 | | | | 23.4 | | | | 1.3 | | | | | — | | | | — | |
| Inventory fair market value adjustment | | | 16.6 | | | | — | | | | — | | | | | — | | | | — | |
| Funded letters of credit expenses and interest rate swap not included in interest expense | | | 2.3 | | | | — | | | | 1.8 | | | | | — | | | | 0.9 | |
| Major scheduled turnaround expense | | | — | | | | 6.6 | | | | 76.4 | | | | | 66.0 | | | | — | |
| Loss on termination of Swap | | | 25.0 | | | | — | | | | — | | | | | — | | | | — | |
| Unrealized (gain) or loss on derivatives | | | 229.8 | | | | (128.5 | ) | | | 113.5 | | | | | 126.9 | | | | 18.9 | |
| Non-cash compensation expense for equity awards | | | 1.8 | | | | 16.9 | | | | 43.5 | | | | | 3.7 | | | | (0.4 | ) |
| (Gain) or loss on disposition of fixed assets | | | — | | | | 1.2 | | | | 1.3 | | | | | — | | | | — | |
| Expenses related to acquisition | | | 3.5 | | | | — | | | | — | | | | | — | | | | — | |
| Minority interest in subsidiaries | | | — | | | | — | | | | (0.2 | ) | | | | (0.7 | ) | | | — | |
| Management fees | | | 2.3 | | | | 2.3 | | | | 11.7 | | | | | 0.5 | | | | — | |
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| Consolidated adjusted EBITDA | | $ | 253.6 | | | $ | 328.2 | | | $ | 222.7 | | | | $ | 20.8 | | | $ | 79.4 | |
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In addition to the financial covenants summarized in the table above, the Credit Facility restricts the capital expenditures of Coffeyville Resources, LLC to $125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and $50.0 million in 2011 and thereafter. The capital expenditures covenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The capital expenditures limitation will not apply for any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe the limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our Credit Facility.
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The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20.0 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20.0 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20.0 million, events relating to employee benefit plans resulting in liability in excess of $20.0 million, a change in control, the guarantees, collateral documents or the Credit Facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the Credit Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.
Under the terms of our Credit Facility, our initial public offering was deemed a “Qualified IPO” because the offering generated more than $250.0 million of gross proceeds and we used the proceeds of the offering to repay at least $275.0 million of term loans under the Credit Facility. As a result of our Qualified IPO, the interest margin on LIBOR loans may in the future decrease from 3.25% to 2.75% (if we have credit ratings of B2/B) or 2.50% (if we have credit ratings of B1/B+). Interest on base rate loans will similarly be adjusted. In addition, as a result of our Qualified IPO, (1) we will be allowed to borrow an additional $225.0 million under the Credit Facility after June 30, 2008 to finance capital enhancement projects if we are in pro forma compliance with the financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we will be allowed to pay an additional $35.0 million of dividends each year, if our corporate family ratings are at least B2 from Moody’s and B from S&P, (3) we will not be subject to any capital expenditures limitations commencing with fiscal 2009 if our total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter ending December 31, 2008, and (4) at any time after March 31, 2008 we will be allowed to reduce the Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or equal to 1.25:1 and we have a corporate family rating of at least B2 from Moody’s and B from S&P.
The Credit Facility is subject to an intercreditor agreement among the lenders and the Cash Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.
At March 31, 2008 and December 31, 2007, funded long-term debt, including current maturities, totaled $488.0 million and $489.2 million, respectively, of tranche D term loans. Other commitments at March 31, 2008 and December 31, 2007 included a $150.0 million funded letter of credit facility and a $150.0 million revolving credit facility. As of March 31, 2008, the commitment outstanding on the revolving credit facility was $37.4 million, including $5.8 million in letters of credit in support of certain environmental obligations and $31.6 million in letters of credit to secure transportation services for crude oil. As of December 31, 2007, the commitment outstanding on the revolving credit facility was $39.4 million, including $5.8 million in letters of credit in support of certain environmental obligations, $3.0 million in support of surety bonds in place to support state and federal excise tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for crude oil.
August 2007 Credit Facilities
The 2007 flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. We did not generate any material revenue while our facilities were shut down due to the flood, but we incurred and continue to incur significant flood repair and cleanup costs, as well as
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incremental legal, public relations and crisis management costs. We also had significant contractual obligations to purchase gathered crude oil. We also owed J. Aron approximately $123.7 million under the Cash Flow Swap, which we deferred to January 31, 2008 (see “— Payment Deferrals Related to Cash Flow Swap” below). In addition, although we believe that we will recover substantial sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery.
As a result of these factors, in August 2007 our subsidiaries entered into three new credit facilities.
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| • | $25.0 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $25.0 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $75.0 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility. |
All indebtedness outstanding under the $25.0 million secured facility and the $25.0 million unsecured facility was repaid in October 2007 with the proceeds of our initial public offering, and all three facilities were terminated at that time.
Payment Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 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. We are required to use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts, but as of March 31, 2008 we were not required to prepay any portion of the deferred amount.
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| • | On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%. |
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| • | On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued |
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| | interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million, plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%. |
Nitrogen Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time to time, seek to raise capital through a public or private offering of limited partner interests in the Partnership. Any decision to pursue such a transaction would be made in the discretion of the managing general partner, not us, and any proceeds raised in a primary offering would be for the benefit of the Partnership, not us (although in some cases, depending on the structure of the transaction, the Partnership might remit proceeds to us). If the managing general partner elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Any such amendments could result in significant changes to our Credit Facility’s pricing, mandatory repayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend our Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140.0 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and to distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering. If the managing general partner sells interests to third party investors, we expect that the Partnership may at such time seek to enter into its own credit facility.
The Partnership filed a registration statement in February 2008 for an initial public offering of its common units. On June 13, 2008, we announced that the managing general partner of the Partnership has decided to postpone indefinitely the Partnership’s initial public offering due to current market conditions for master limited partnerships. We believe maintaining the fertilizer business within the Company provides greater value for CVR Energy shareholders than would be the case if the Partnership became a publicly-traded partnership at this time. The Partnership subsequently
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requested that the registration statement be withdrawn. The Partnership may elect to move forward with a public or private offering in the future. Any future public or private offering by the Partnership would be made solely at the discretion of the Partnership’s managing general partner, subject to our specified joint management rights, and would be subject to market conditions and negotiation of terms acceptable to the Partnership’s managing general partner. In connection with the Partnership’s initial public or private offering, if any, the Partnership may require us to include a sale of a portion of our interests in the Partnership. If the Partnership becomes a public company, we may consider a secondary offering of interests which we own (either in connection with a public offering by the Partnership, but subject to priority rights in favor of the Partnership, or following completion of the Partnership’s initial public offering, if any) or in a private placement. We cannot assure you that any such transaction will be consummated. Neither the consent of the managing general partner nor the consent of the Partnership is required for any sale of our interests in the Partnership, other than customary blackout periods relating to offerings by the Partnership. Any proceeds raised would be for our benefit. The Partnership has granted us registration rights which will require the Partnership to register our interests with the SEC at our request from time to time (following any public offering by the Partnership), subject to various limitations and requirements. We cannot assure you that any such transaction will be consummated.
Capital Spending
We preparedivide our consolidated financial statementscapital spending needs into two categories: non-discretionary, which is either capitalized or expensed, and discretionary, which is capitalized. Non-discretionary capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety regulations. The total non-discretionary capital spending needs for our refinery business and the nitrogen fertilizer business, including major scheduled turnaround expenses, were approximately $170 million in accordance2006 and $218 million in 2007 and we estimate that the total non-discretionary capital spending needs of our refinery business and the nitrogen fertilizer business will be approximately $279 million in the aggregate over the three-year period beginning 2008. These estimates include, among other items, the capital costs necessary to comply with GAAP. In orderenvironmental regulations, including Tier II gasoline standards and on-road diesel regulations. As described above, our credit facility limits the amount we can spend on capital expenditures.
Compliance with the Tier II gasoline and on-road diesel standards required us to applyspend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately $68 million in the aggregate between 2008 and 2010. These amounts are reflected in the table below under “Environmental and safety capital needs.” See “Business — Environmental Matters — Fuel Regulations — Tier II, Low Sulfur Fuels.”
The following table sets forth our estimate of non-discretionary spending for our refinery business and the nitrogen fertilizer business for the years presented as of March 31, 2008 (other than 2006 and 2007 which reflect actual spending). Capital spending for the nitrogen fertilizer business has been and will be determined by the managing general partner of the Partnership. The data contained in the table below represents our current plans, but these principles, management must make judgments, assumptionsplans may change as a result of unforeseen
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circumstances and we may revise these estimates from time to time or not spend the amounts in the manner allocated below.
Petroleum Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
| |
| Environmental and safety capital needs | | $ | 144.6 | | | $ | 121.8 | | | $ | 46.0 | | | $ | 53.9 | | | $ | 23.5 | | | $ | 2.6 | | | $ | 2.1 | | | $ | 394.5 | |
| Sustaining capital needs | | | 11.8 | | | | 14.9 | | | | 22.0 | | | | 29.8 | | | | 22.3 | | | | 22.0 | | | | 22.0 | | | | 144.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 156.4 | | | | 136.7 | | | | 68.0 | | | | 83.7 | | | | 45.8 | | | | 24.6 | | | | 24.1 | | | | 539.3 | |
| Major scheduled turnaround expenses | | | 4.0 | | | | 76.4 | | | | — | | | | — | | | | 50.0 | | | | — | | | | — | | | | 130.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 160.4 | | | $ | 213.1 | | | $ | 68.0 | | | $ | 83.7 | | | $ | 95.8 | | | $ | 24.6 | | | $ | 24.1 | | | $ | 669.7 | |
Nitrogen Fertilizer Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | (in millions) | |
| |
| Environmental and safety capital needs | | $ | 0.1 | | | $ | 0.5 | | | $ | 2.2 | | | $ | 4.5 | | | $ | 2.6 | | | | 2.7 | | | | 3.8 | | | $ | 16.4 | |
| Sustaining capital needs | | | 6.6 | | | | 3.9 | | | | 9.7 | | | | 3.1 | | | | 4.5 | | | | 4.8 | | | | 4.3 | | | | 36.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 6.7 | | | | 4.4 | | | | 11.9 | | | | 7.6 | | | | 7.1 | | | | 7.5 | | | | 8.1 | | | | 53.3 | |
| Major scheduled turnaround expenses | | | 2.6 | | | | — | | | | 2.8 | | | | — | | | | 2.6 | | | | — | | | | 2.8 | | | | 10.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 9.3 | | | $ | 4.4 | | | $ | 14.7 | | | $ | 7.6 | | | $ | 9.7 | | | $ | 7.5 | | | $ | 10.9 | | | $ | 64.1 | |
Combined
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
| |
| Environmental and safety capital needs | | $ | 144.7 | | | $ | 122.3 | | | $ | 48.2 | | | $ | 58.4 | | | $ | 26.1 | | | | 5.3 | | | | 5.9 | | | $ | 410.9 | |
| Sustaining capital needs | | | 18.4 | | | | 18.8 | | | | 31.7 | | | | 32.9 | | | | 26.8 | | | | 26.8 | | | | 26.3 | | | | 181.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 163.1 | | | | 141.1 | | | | 79.9 | | | | 91.3 | | | | 52.9 | | | | 32.1 | | | | 32.2 | | | | 592.6 | |
| Major scheduled turnaround expenses | | | 6.6 | | | | 76.4 | | | | 2.8 | | | | — | | | | 52.6 | | | | — | | | | 2.8 | | | | 141.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 169.7 | | | $ | 217.5 | | | $ | 82.7 | | | $ | 91.3 | | | $ | 105.5 | | | $ | 32.1 | | | $ | 35.0 | | | $ | 733.8 | |
We undertake discretionary capital spending based on the best available information atexpected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields,and/or a reduction in direct operating expenses. As of December 31, 2007, we had committed approximately $14 million towards discretionary capital spending in 2008. Other than the time. Actual results may differ based onnitrogen fertilizer plant expansion project referred to below, we anticipate that our discretionary capital spending will average approximately $35 million per year between 2008 and 2012.
The Partnership is currently moving forward with an approximately $120 million fertilizer plant expansion, of which approximately $11 million was incurred as of March 31, 2008. We estimate this expansion will increase the accuracynitrogen fertilizer plant’s capacity to upgrade ammonia into premium priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010. This project is also expected to improve the cost structure of the information utilized and subsequent events. Our accounting policies are describednitrogen fertilizer business by eliminating the need for rail shipments of ammonia, thereby avoiding anticipated cost increases in the Notes to our audited Financial Statements included elsewhere in this prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.such transport.
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Cash Flows
The following table sets forth our cash flows for the periods indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | |
| | | Predecessor | | | Successor | |
| | | 174 Days
| | | 233 Days
| | | Year
| | | | |
| | | Ended
| | | Ended
| | | Ended
| | | Three Months
| |
| | | June 23, | | | December 31, | | | December 31, | | | Ended March 31, | |
| | | 2005 | | | 2005 | | | 2006 | | | 2007 | | | 2007 | | | 2008 | |
| | | | | | | | | | | | | | | (unaudited) | | | (unaudited) | |
| | | (in millions) | |
| |
| Net cash provided by (used in) | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 12.7 | | | $ | 82.5 | | | $ | 186.6 | | | $ | 145.9 | | | $ | 44.1 | | | $ | 24.2 | |
| Investing activities | | | (12.3 | ) | | | (730.3 | ) | | | (240.2 | ) | | | (268.6 | ) | | | (107.3 | ) | | | (26.2 | ) |
| Financing activities | | | (52.4 | ) | | | 712.5 | | | | 30.8 | | | | 111.3 | | | | 28.9 | | | | (3.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | $ | (52.0 | ) | | $ | 64.7 | | | $ | (22.8 | ) | | $ | (11.4 | ) | | $ | (34.3 | ) | | $ | (5.4 | ) |
In addition, we are currently entitled to all cash distributed by the Partnership. However, the amount of cash flows from the Partnership that we will receive in the future may be limited by a number of factors. The Partnership may enter into its own credit facility or other contracts that limit its ability to make distributions to us. Additionally, in the future the managing general partner of the Partnership will receive a greater allocation of distributions as more cash becomes available for distribution, and consequently we will receive a smaller percentage of quarterly distributions over time. Our rights to distributions will also be adversely affected if the Partnership consummates a public or private equity offering in the future. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “Risk Factors — Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the establishment of cash reserves.”
Impairment of Long-Lived AssetsCash Flows Provided by Operating Activities
During 2001, Farmland accountedComparison of the Three Months Ended March 31, 2008 and the Three Months Ended March 31, 2007
Net cash flows from operating activities for long-livedthe three months ended March 31, 2008 was $24.2 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital and other assets and liabilities, partially offset by unfavorable changes in accordance withtrading working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 121,133,Accounting for ImpairmentDerivative Instruments and Hedging Activities. Therefore, the net loss for the three months ended March 31, 2008 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of Long-Lived AssetsMarch 31, 2008 (approximately two years and three months) and the NYMEX crack spread that is the basis for Long-Lived Assetsthe underlying swaps had increased, the unrealized losses on the Cash
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Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $20.8 million increase in the payable to be Disposed of.swap counterparty. Other sources of cash in other working capital included $16.6 million of deferred revenue related to prepaid fertilizer shipments and a $5.2 increase in accrued income taxes. Trade working capital for the three months ended March 31, 2008 resulted in a use of cash of $67.5 million. For the three months ended March 31, 2008, accounts receivable increased $30.7 million, inventory increased by $31.6 and accounts payable decreased by $5.2 million.
Net cash flows provided by operating activities for the three months ended March 31, 2007 was $44.1 million. The positive cash flow from operating activities during this period was primarily the result of changes in other assets and liabilities offset by unfavorable changes in trade working capital and other working capital. Net income for the period was not indicative of the operating margins for the period. This was the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 121 was superseded by SFAS No. 144,133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the Impairment or Disposalnet loss for the three months ended March 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of Long-Lived Assets, whichMarch 31, 2007 (approximately three years and three months years) and the NYMEX crack spread that is the basis for the underlying swaps had increased during the period, the unrealized losses on the Cash Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $129.3 million increase in the payable to swap counterparty. Adding to our operating cash flow for the three months ended March 31, 2007 was adopteda $68.0 million source of cash related to a decrease in trade working capital. For the three months ended March 31, 2007, accounts receivable decreased $44.6 million while inventory increased $23.0 million and accounts payable increased $46.4 million. The change in trade working capital was primarily driven by Farmland effective January 1, 2002.the impact of the refinery turnaround that began in February 2007. The primary use of cash during the period was $41.3 million for deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
In accordance with both SFAS No. 144 and SFAS No. 121, Farmland reviewed its long-lived assets for impairment whenever events or changes in circumstances indicated that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparisonComparison of the carrying amount of an asset to estimated undiscounted future netYear Ended December 31, 2007, the Year Ended December 31, 2006, the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.
Net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeded its estimated future undiscounted net cash flows, an impairment charge was recognized by the amount by which the carrying amount of the assets exceeded the fair value of the assets. Assets to be disposed of are reported at the lower of the carrying value or fair value less cost to sell, and are no longer depreciated.
In its Plan of Reorganization, Farmland stated, among other things, its intent to dispose of its petroleum and nitrogen fertilizer assets. Despite this stated intent, these assets were not classified as heldfrom operating activities for sale under SFAS 144 until October 7, 2003 because, ultimately, any disposition must be approved by the bankruptcy court and the bankruptcy court did not approve such disposition until that date. Since Farmland determined that it was more likely than not that its assets would be disposed of, those assets were tested for impairment in 2002 pursuant to SFAS 144, using projected undiscounted net cash flows. Based on Farmland’s best assumptions regarding the use and eventual disposition of those assets, primarily from indications of value received from potential bidders in the bankruptcy sales process, the assets were determined to exceed the fair value expected to be received on disposition by approximately $375.1 million. Accordingly, an impairment charge was recognized for that amount in 2002. The ultimate proceeds from disposition of these assets were decided in a bidding and auction process conducted in the bankruptcy proceedings. In 2003, as a result of receiving a bid from Coffeyville Resources, LLC, Farmland revised its estimate of the amount to be generated from the disposition of these assets and an additional impairment charge of $9.6 million was taken in the year ended December 31, 2003.
As2007 was $145.9 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital partially offset by unfavorable changes in trade working capital and other assets and liabilities over the period. For purposes of June 30, 2006, net property, plantthis cash flow discussion, we define trade working capital as accounts receivable, inventory and equipment totaled $834.6 million. Toaccounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the extent events or circumstances change indicatingperiod was not indicative of the carrying amountsoperating margins for the period. This is the result of the accounting treatment of our assets may not be recoverable, we could experience asset impairmentsderivatives in general and more specifically, the future.
Derivative Instruments and Fair Value of Financial Instruments
Cash Flow Swap. We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long term-debt. Although management considers these derivatives economic hedges,have determined that the Cash Flow Swap and our other derivative instruments dodoes not qualify as hedgesa hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net loss for the year ended December 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2007 (approximately two years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap significantly decreased our Net Income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $240.9 million increase in the payable to swap counterparty. Other sources of cash from other working capital included $4.8 million from prepaid expenses and other current assets, $27.0 million from other current liabilities and $20.0 million in insurance proceeds. Reducing our operating cash flow for the year ended December 31, 2007 was $42.9 million use of cash related to changes in trade working capital. For the year ended December 31, 2007, accounts receivable increased $17.0 million and inventory increased by $85.0 million resulting in a net use of cash of $102.0 million. These uses of cash due to changes in trade working
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capital were partially offset by an increase in accounts payable, or a source of cash, of $59.1 million. Other primary uses of cash during the period include a $105.3 million increase in our insurance receivable related to the flood and a $57.7 million use of cash related to deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
Net cash flows from operating activities for the year ended December 31, 2006 was $186.6 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other assets and liabilities, partially offset by unfavorable changes in trade working capital and other working capital over the period. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities,. Therefore, the net income for the year ended December 31, 2006 included both the realized losses and accordingly are recorded at fair valuethe unrealized gains on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2006 (approximately three years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had declined, the unrealized gains on the Cash Flow Swap significantly increased our net income over this period. The impact of these unrealized gains on the Cash Flow Swap is apparent in the balance sheet. Changes$147.0 million decrease in the fair valuepayable to swap counterparty. Reducing our operating cash flow for the year ended December 31, 2006 was a $0.3 million use of these derivative instruments are recorded into earnings as a componentcash related to an increase in trade working capital. For the year ended December 31, 2006, accounts receivable decreased approximately $1.9 million while inventory increased $7.2 million and accounts payable increased $5.0 million. Other primary uses of other income (expense) incash during the period include a $5.4 million increase in prepaid expenses and other current assets and a $37.0 million reduction in accrued income taxes. Offsetting these uses of change. The estimated fair valuescash was an $86.8 million increase in deferred income taxes primarily the result of forwardthe unrealized gain on the Cash Flow Swap and swap contracts are based on quoted market prices and assumptionsa $4.6 million increase in other current liabilities.
Analysis of cash flows from operating activities for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. Our petroleum business recorded net losses from derivative instruments of $323.7 million and $126.4 million in other income (expense) for the fiscal year ended December 31, 2005 was impacted by the Subsequent Acquisition. See “— Factors Affecting Comparability.” For instance, completion of the Subsequent Acquisition by Successor required a mark up of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold. Therefore, the discussion of cash flows from operations has been broken down into the 174 days ended June 23, 2005 and the six months233 days ended June 30, 2006.December 31, 2005.
As of June 30, 2006, a $1.00 change in quoted pricesNet cash flows from operating activities for the crack spreads utilized174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by income of $52.4 million, offset by a $54.3 million increase in trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.
Net cash flows provided by operating activities for the 233 days ended December 31, 2005 was $82.5 million. The positive cash flow from operating activities generated over this period was primarily the result of strong operating earnings during the period partially offset by the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins and the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. At the closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless and thus resulted in the expensing of the associated premium. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and “— Results of Operations — Consolidated Results of Operations — Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Consolidated).” We have determined that the Cash Flow Swap woulddoes not
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qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net income for the year ended December 31, 2005 included the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap became effective July 1, 2005 and had an original term of approximately five years and the NYMEX crack spread that is the basis for the underlying swaps had improved since the trade date of the Cash Flow Swap on June 16, 2005, the unrealized losses on the Cash Flow Swap significantly reduced our net income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $256.7 million increase in the payable to swap counterparty. Additionally and as a result of the closing of the Subsequent Acquisition, Successor marked up the value of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold. The total impact of this for the 233 days ended December 31, 2005 was $14.3 million. Trade working capital provided $8.0 million in cash during the 233 days ended December 31, 2005 as an increase in accounts receivable was more than offset by decreases in inventory and an increase in accounts payable. Offsetting the sources of cash from operating activities highlighted above was a $77.2$98.4 million changeuse of cash related to deferred income taxes and a $4.7 million use of cash related to other long-term assets.
Cash Flows Used In Investing Activities
Comparison of the Three Months Ended March 31, 2008 and the Three Months Ended March 31, 2007
Net cash used in investing activities for the three months ended March 31, 2008 was $26.2 million compared to $107.4 million for the three months ended March 31, 2007. The decrease in investing activities for the three months ended March 31, 2008 as compared to the fair valuethree months ended March 31, 2007 was the result of derivative commodity positiondecreased capital expenditures associated with various capital projects that commenced in the first quarter of 2007 in conjunction with the refinery turnaround.
Comparison of the Year Ended December 31, 2007 and the same changeYear Ended December 31, 2006
Net cash used in investing activities for the year ended December 31, 2007 was $268.6 million compared to net income.$240.2 million for the year ended December 31, 2006. The increase in investing activities for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was the result of increased capital expenditures associated with various capital projects in our petroleum business.
Net cash used in investing activities was $12.3 million for the 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.
Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.
Net cash used in investing activities for the year ended December 31, 2006 was $240.2 million compared to $12.3 million for the 174 days ended June 23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the year ended December 31, 2006 was the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures. Investing activities for the combined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.
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Environmental ExpendituresCash Flows (Used in) Provided by Financing Activities
Liabilities related to future remediationComparison of contaminated properties are recognized when the related costs are considered probableThree Months Ended March 31, 2008 and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted as new facts or changes in law or technology occur. Environmental expenditures are capitalized when such costs provide future economic benefits. Changes in laws, regulations or assumptions used in estimating these costs could have a material impact to our financial statements. The amount recorded for environmental obligations at June 30, 2006 totaled $7.4 million, including $1.3 million included in current liabilities.
Share-Based Compensationthe Three Months Ended March 31, 2007
We accountNet cash used for share-based compensation in accordance with Statementfinancing activities for the three months ended March 31, 2008 was $3.4 million as compared to net cash provided by financing activities of Financial Accounting Standards (SFAS) No. 123(R),Share-Based Payments. SFAS 123(R) requires that compensation$29.0 million for the three months ended March 31, 2007. During the three months ended March 31, 2008, we paid $1.2 million of scheduled principal payments and deferred $2.1 million of initial public offering costs relating to share-based payment transactions be recognized in a company’s financial statements. SFAS 123(R) applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based on the fair value of those equity instruments.
In accordance with SFAS 123(R), we apply a fair-value-based measurement method in accounting for share-based override units and phantom points. See “Management — Employment Agreements, Separation and Consulting Agreement and Other Arrangements.” This measurement method, which uses binomial modeling, is based upon significant assumptions related to (1) volatility, (2) projected undiscounted futureCVR Partners, LP. For the three months ended March 31, 2007, the primary source of cash flows, (3) discount rate and (4) marketability and minority discounts.
Override units are equity classified awards measured usingwas the grant date fair value with compensation expense recognized over the respective vesting period. Phantom points are liability classified awards marked to market basedresult of borrowings drawn on their fair value at the end of each reporting period with compensation expense recognized over the respective vesting period.
There is considerable judgment in the determination of the significant assumptions used in determining the fair value for our share based compensation. Changes in these assumptions could result in material changes in the amounts recognized as compensation expense in our consolidated financial statements. For example, if we increased volatility or projected undiscounted future cash flows, or decreased the discount rate or marketability and minority discounts, the measurement date fair value of the override units and the phantom points could materially increase, which could materially increase the amount of compensation expense recognized in our consolidated financial statements.revolving credit facility.
Purchase Price AccountingComparison of the Year Ended December 31, 2007 and Allocationthe Year Ended December 31, 2006
Net cash provided by financing activities for the year ended December 31, 2007 was $111.3 million as compared to net cash provided by financing activities of $30.8 million for the year ended December 31, 2006. The Initialprimary sources of cash for the year ended December 31, 2007 were obtained through $399.6 million of proceeds associated with our initial public offering. The primary uses of cash for the year ended December 31, 2007 was $335.8 million of long-term debt retirement and $2.5 million in payments of financing costs. The primary sources of cash for the year ended December 31, 2006 were obtained through a refinancing of the Successor’s first and second lien credit facilities into a new long term debt credit facility of $1.075 billion, of which $775.0 million was outstanding as of December 31, 2006. The $775.0 million term loan under the credit facility was used to repay approximately $527.7 million in first and second lien debt outstanding, fund $5.5 million in prepayment penalties associated with the second lien credit facility and fund a $250.0 million cash distribution to Coffeyville Acquisition LLC. Other sources of cash included $20.0 million of additional equity contributions into Coffeyville Acquisition LLC, which was subsequently contributed to our operating subsidiaries, and $30.0 million of additional delayed draw term loans issued under the first lien credit facility. During this period, we also paid $1.7 million of scheduled principal payments on the first lien term loans.
For the combined period ended December 31, 2005, net cash provided by financing activities was $660.0 million. The primary sources of cash for the combined periods ended December 31, 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $227.7 million of equity. Additional equity of $10.0 million was contributed into Coffeyville Acquisition LLC subsequent to the aforementioned acquisition, which was subsequently contributed to our operating subsidiaries, in order to fund a portion of two discretionary capital expenditures at our refining operations. Additional sources of funds during the year ended December 31, 2005 were obtained through the borrowing of $0.2 million in revolving loan proceeds, net of $69.6 million of repayments. Offsetting these sources of cash from financing activities during the year ended December 31, 2005 were $24.6 million in deferred financing costs associated with the first and second lien debt commitments raised by Successor in connection with the Subsequent Acquisition described in note 1and a $52.2 million cash distribution to our audited consolidated financial statements included elsewhere in this prospectus have been accounted for using the purchase method of accounting as of March 3, 2004 and June 24, 2005, respectively. The allocations of the purchase pricesImmediate Predecessor prior to the netSubsequent Acquisition. See “— Liquidity and Capital Resources — Debt.”
Working Capital
Working capital at March 31, 2008, was $21.5 million, consisting of $622.5 million in current assets acquired have been performedand $601.0 million in accordance with SFAS No. 141,Business Combinations.current liabilities. Working capital at December 31, 2007 was $10.7 million, consisting of $570.2 million in current assets and $559.5 million in current liabilities. In connection withaddition, we had available borrowing capacity under our revolving credit facility of $112.6 million at March 31, 2008. In the allocationscurrent crude oil price environment, working capital is subject to substantial variability fromweek-to- week and month-to-month.
Letters of Credit
Our revolving credit facility provides for the purchase prices, management used estimatesissuance of letters of credit. At March 31, 2008, there were $37.4 million of irrevocable letters of credit outstanding, including $5.8 million in support of certain environmental obligators and assumptions$31.6 million to determine the fair value of the assets acquired and liabilities assumed. Changes in these assumptions and estimates such as discount rates and future cash flows used in the appraisal process could have a material impact on how the purchase prices were allocated at the dates of acquisition.secure transportation services for crude oil.
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Income TaxesCapital and Commercial Commitments
Income tax expenseIn addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of March 31, 2008 relating to long-term debt, operating leases, unconditional purchase obligations and other specified capital and commercial commitments for the five-year period following March 31, 2008 and thereafter.
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Payments Due by Period | |
| | | | | | Nine Months
| | | | | | | | | | | | | | | | |
| | | | | | Ending
| | | | | | | | | | | | | | | | |
| | | Total | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Thereafter | |
| | | (in millions) | |
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Contractual Obligations | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt(1) | | $ | 488.0 | | | $ | 3.7 | | | $ | 4.8 | | | $ | 4.8 | | | $ | 4.7 | | | $ | 4.7 | | | $ | 465.3 | |
| Operating leases(2) | | | 8.9 | | | | 2.8 | | | | 3.3 | | | | 1.7 | | | | 0.9 | | | | 0.2 | | | | — | |
| Unconditional purchase obligations(3) | | | 582.3 | | | | 20.8 | | | | 28.2 | | | | 55.8 | | | | 53.9 | | | | 51.3 | | | | 372.3 | |
| Environmental liabilities(4) | | | 8.8 | | | | 2.6 | | | | 0.7 | | | | 1.6 | | | | 0.3 | | | | 0.3 | | | | 3.3 | |
| Funded letter of credit fees(5) | | | 10.1 | | | | 3.4 | | | | 4.5 | | | | 2.2 | | | | — | | | | — | | | | — | |
| Interest payments(6) | | | 142.0 | | | | 20.2 | | | | 26.6 | | | | 26.3 | | | | 26.1 | | | | 25.9 | | | | 16.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,240.1 | | | $ | 53.5 | | | $ | 68.1 | | | $ | 92.4 | | | $ | 85.9 | | | $ | 82.4 | | | $ | 857.8 | |
Other Commercial Commitments | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Standby letters of credit(7) | | $ | 37.4 | | | $ | 37.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
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| (1) | | Long-term debt amortization is based on the contractual terms of our Credit Facility. We may be required to amend our Credit Facility in connection with an offering by the Partnership. As of March 31, 2008, $488.0 million was outstanding under our credit facility. See “— Liquidity and Capital Resources — Debt.” |
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| (2) | | The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods. |
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| (3) | | The amount includes (1) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation and (2) commitments under an electric supply agreement with the city of Coffeyville. |
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| (4) | | Environmental liabilities represents (1) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (2) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters”. |
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| (5) | | This amount represents the total of all fees related to the funded letter of credit issued under our Credit Facility. The funded letter of credit is utilized as credit support for the Cash Flow Swap. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk”. |
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| (6) | | Interest payments are based on interest rates in effect at April 1, 2008 and assume contractual amortization payments. |
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| (7) | | Standby letters of credit include $5.8 million of letters of credit issued in connection with environmental liabilities and $31.6 million in letters of credit to secure transportation services for crude oil. |
In addition to the amounts described in the above table, we owe J. Aron approximately $123.7 million plus accrued interest ($5.8 million as of June 1, 2008) which will be due August 31, 2008 and approximately $54.0 million which will be due on July 8, 2008 for crude oil we settled or will settle with respect to the quarter ending June 30, 2008 based on June 16, 2008 pricing. Also, if the projectedPartnership does not consummate an initial private or public offering by October 24, 2009, the managing general partner of the Partnership can require us to purchase the managing general partner interest at fair market value until the earlier of October 24, 2012 and the closing of the Partnership’s initial offering.
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Our ability to make payments on and to refinance our indebtedness, to repay the amounts owed to J. Aron, to purchase the Partnership’s managing general partner interest if the Partnership’s managing general partner exercises its put right, to fund planned capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to refining spreads, fertilizer margins, receipt of distributions from the Partnership and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile and have experienced significant increases in the cost of financing. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
Off-Balance Sheet Arrangements
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.
Recently Issued Accounting Standards
In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157,Fair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price)”. The standard’s provisions for financial assets and financial liabilities, which became effective tax rate based upon future tax return filings. The amounts anticipatedJanuary 1, 2008, had no material impact on the Company’s financial position or results of operations. At March 31, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14 to be reported in those filings may change between the time theour consolidated financial statements, “Fair Value Measurements”, included elsewhere in this prospectus.
In February 2008, the FASB issued FASB Staff Position157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are prepared and the time the tax returns are filed. Further, because tax filings are subject to review by taxing authorities, there is also the risk that a positionrecognized or disclosed at fair value in an entity’s financial statements on a tax return mayrecurring basis (at least annually). The Company will be challenged by a taxing authority. Ifrequired to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the taxing authority is successful in asserting a position different than that taken by us, differences in a tax expense or between current and deferred tax items may arise in future periods. Anyadoption of these differences which couldSFAS 157 deferral provisions will not have a material impact on ourthe Company’s financial position or earnings.
In February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. Under this standard, an entity is required to provide additional information that will assist investors and other users of financial information to more easily understand the effect of the Company’s choice to use fair value on its earnings. Further, the entity is required to display the fair value of those assets and liabilities for which the Company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 107,Disclosures about Fair Value of Financial Instruments. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of SFAS 159 did not impact the Company’s consolidated financial statements would be reflectedas of the quarter ended March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the financial statements when management considers them probablebusiness combination, establishes the acquisition date as the date that the acquirer achieves control and
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requires the acquirer to recognize the assets acquired, liabilities assumed and any non-controlling interest at their fair values as of occurringthe acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR Energy will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141(R) will be limited to any future business combinations for which the amount reasonably estimatable.acquisition date is on or after January 1, 2009.
Valuation allowances reduce deferred tax assetsIn December 2007, the FASB issued SFAS No. 160,Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement will change the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an amountentity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, net earnings, and cash flows. The Company will be required to adopt this statement as of January 1, 2009. The adoption of SFAS 161 is not expected to have a material impact on the Company’s consolidated financial statements.
The FASB recently issued final FASB Staff Position (“FSP”)No. APB 14-1Accounting for Convertible Debt Instruments That May Be Settled in Cash upon Conversion (Including Partial Cash Settlement”. The FSP changes the accounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS 133,Accounting for Derivative Instruments and Hedging Activities. Under the FSP, cash settled convertible securities will be separated into their debt and equity components. The FSP specifies that issuers of such instruments should separately account for the liability and equity components in a manner that will more likely than not be realized. Management’s estimates ofreflect the realization of deferred tax assetsentity’s nonconvertible debt borrowing rate when interest cost is based on the information available at the time therecognized in subsequent periods. The FSP is effective for financial statements are preparedissued for fiscal years beginning after December 15, 2008, and may include estimatesinterim periods within those fiscal years and will require issuers of future income and other assumptionsconvertible debt that are inherently uncertain. No valuation allowancecan be settled in cash to record the additional expense incurred. The Company is currently recorded, as we expect to realize our deferred tax assets.evaluating the FSP in conjunction with its convertible debt offering.
Liquidity and Capital Resources
Our principalprimary sources of liquidity arecurrently consist of cash generated from our operating activities, existing cash balances, our existing revolving credit facility and cash equivalents, cash from operationsthird party guarantees of obligations under the Cash Flow Swap as well as our convertible notes offering, if consummated, and borrowings under Coffeyville Resources, LLC’sthe proceeds of our proposed senior secured credit facilities.
Cash Balancefacility, if entered into. Our ability to generate sufficient cash flows from our operating activities will continue to be primarily dependent on producing or purchasing, and Other Liquidityselling, sufficient quantities of refined products at margins sufficient to cover fixed and variable expenses.
As of March 31, 2008 and June 30, 2006,16, 2008, we had cash, cash equivalents and short-term investments of $127.9 million. We believe our June 30, 2006 cash levels, together with the availability of borrowings$25.2 million and $71.4 million, respectively, and up to $112.6 million available under our revolving loan facilitiescredit facility as of both dates. In the current crude oil price environment, working capital is subject to substantial variability from week-to-week and month-to-month. The payable to swap counterparty included in the consolidated balance sheet at March 31, 2008 was approximately $371.4 million, and the current portion included an increase of $32.6 million from December 31, 2007, resulting in an equal reduction in our working capital for the same period.
On June 30, 2007, our refinery and the nitrogen fertilizer plant were severely flooded and forced to conduct emergency shutdowns and evacuate. See “Flood and Crude Oil Discharge.” Our liquidity was significantly negatively impacted as a result of the reduction in cash provided by operations due to our temporary cessation of operations and the additional expenditures associated with the flood
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and crude oil discharge. In order to provide immediate and future liquidity, on August 23, 2007 we deferred payments which were due to J. Aron under the terms of the Cash Flow Swap. The J. Aron deferred amounts of $123.7 million (plus accrued interest of $5.8 million as of June 1, 2008) are due on August 31, 2008. See “— Liquidity and Capital Resources — Payment Deferrals Related to the Cash Flow Swap” for additional information about the payment deferral. These deferrals are supported by third-party guarantees. In addition, we estimate that we will owe J. Aron approximately $54 million on July 8, 2008 for crude oil we settled with respect to the quarter ending June 30, 2008 based on June 16, 2008 pricing.
Our liquidity was enhanced during the fourth quarter of 2007 by the receipt of the net proceeds from our initial public offering. We intend to use the net proceeds from the convertible notes offering, if consummated, and the proposed senior secured credit facility, if entered into, for general corporate purposes, which may include using a portion of the proceeds to pay amounts owed to J. Aron under the Cash Flow Swap and for other future capital investments. If the convertible notes offering is not consummatedand/or the proposed senior secured credit facility is not entered into, we receive from this offering, will be adequateintend to fund our operations through cash generated from our operating activities, existing cash balances, our existing revolving credit facility and third party guarantees of obligations under the Cash Flow Swap. We believe these capital resources will be sufficient to satisfy the anticipated cash requirements based onassociated with our current level ofexisting operations for at least the next twelve months. AsHowever, our future capital expenditures and other cash requirements could be higher than we currently expect as a result of June 30, 2006, we had available upvarious factors. Additionally, our ability to $55.2 million undergenerate sufficient cash from our revolving loan facilities,operating activities depends on our future performance, which are discussed in more detail below.is subject to general economic, political, financial, competitive and other factors beyond our control.
Debt
DebtProposed Secured Credit Facility
Concurrently with the closing of this offering, we anticipate that Coffeyville Resources, LLC will enter into a new $25.0 million senior secured term loan (the “proposed senior secured credit facility”). We anticipate that the proposed senior secured credit facility will be secured by the same collateral that secures our existing Credit Facility and will contain covenants substantially similar to the Credit Facility described below. Although we have begun negotiations on the new credit facility, we have not entered into any agreement regarding the proposed senior secured credit facility, and as such, there is no guarantee that we will be enter into a credit facility on the terms described above or at all.
Credit Facility
On June 24, 2005 and in conjunction with the Subsequent Acquisition, we completedDecember 28, 2006, our subsidiary, Coffeyville Resources, LLC, entered into a recapitalizationcredit facility (the “Credit Facility”) which provided financing of Successor with a new First Lien Credit Facility and a new Second Lien Credit Facility.up to $1.075 billion. The First Lien Credit Facility was for an aggregate commitment not to exceed $525.0 million and the Second Lien Credit Facility consisted of a $275.0 million term loan. The First Lien Credit Facility consisted of $225.0$775.0 million of tranche BD term loans; $50.0 million of delayed draw term loans;loans, a $100.0$150.0 million revolving loan facility;credit facility, and a $150.0 million funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. The primary borrower underOn October 26, 2007, we repaid $280.0 million of the First Lientranche D term loans with proceeds from our initial public offering. The Credit Facility is our subsidiary, Coffeyville Resources, LLC. The First Lien Credit Facility matures on June 23, 2012, is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including the equity of our subsidiaries on a first lienfirst-lien priority basis.
The tranche BD term loan, initially $225 million, isloans outstanding are subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on OctoberApril 1, 20052007 and increasing to 23.5% of the outstanding principal balance on OctoberApril 1, 2011,2013 and the next two quarters, with a final payment of the aggregate outstanding balance on June 23, 2012.
The delayed draw term loans of $50.0 million are available for drawing through December 2006. We obtained the delayed draw term loan commitment to fund a portion of the capital requirements for two specific petroleum business capital projects: the continuous catalytic reformer and the fluidized catalytic cracking unit. As of June 24, 2005, the estimated cost to complete these projects was approximately $140.0 million with the difference between the delayed draw term commitment and the estimated project costs being funded by incremental equity contributions to Successor or other cash
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from operations under certain conditions. The delayed draw term loan is subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on the last date of the first quarter following the delayed draw term loan termination date or the date on which the delayed draw term loans have been fully funded through June 24, 2011. Thereafter, the delayed draw term loans are amortized in equal quarterly installments until June 24, 2012. As of June 30, 2006, we have used $10.0 million of the delayed draw term loan.28, 2013.
The revolving loancredit facility of $100.0$150.0 million provides for direct cash borrowings for general corporate purposes and on a short-term basis. Letters of credit issued under the revolving loancredit facility are subject to a $50.0$75.0 million sub-limit. The revolving loan commitment maturesexpires on June 24, 2011.December 28, 2012. The borrower has an option to extend this maturity upon written notice to the lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is June 24, 2012.
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December 28, 2013. As of March 31, 2008, we had available $112.6 million under the revolving credit facility. As of June 30, 2006,16, 2008, we had available $55.2$112.6 million under the revolving credit facility.
The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into a credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, the borrower has the ability to reduce the funded letter of credit at any time upon written notice to the lenders.
In addition to the First Lien Credit Facility, our subsidiary Coffeyville Resources, LLC also entered into the Second Lien Credit Facility on June 24, 2005 for $275.0 million. The Second Lien Credit Facility is guaranteed by all of our subsidiaries and is secured by substantially all of their assets including equity of our subsidiaries on a second lien priority basis. The Second Lien Credit Facility is not subject to scheduled principal amortization; however, the principal outstanding is due and payable upon final maturity on June 24, 2013.
The net proceeds from the tranche B term loan of $225.0 million, second lien term loans of $275.0 million, $12.6 million of revolving loan facilities and a $227.7 million equity contribution from Coffeyville Acquisition LLC were utilized to fund the following upon the closing of the Subsequent Acquisition:
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| • | $685.8 million for cash proceeds to Immediate Predecessor ($1,038.9 million of assets acquired less $353.1 million of liabilities assumed), including $12.6 million of legal, accounting, advisory, transaction and other expenses associated with the Subsequent Acquisition; |
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| • | $49.6 million of other fees and expenses related to the Subsequent Acquisition; and |
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| • | $4.9 million of cash to fund our operating accounts. |
The First Lien Credit Facility was subsequently amended and restated on June 29, 2006 under substantially the same terms as the June 24, 2005 agreement. The tranche B term loans were refinanced into tranche C term loans. The primary reason for the amendment and restatement was to reduce the applicable margin spreads for borrowings on the first lien term loans and the funded letter of credit facility.facility expires on December 28, 2010.
The amended and restated First Lien Credit Facility incorporatedincorporates the following pricing by facility type:
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| | • | Tranche C term loans and delayed drawD term loans bear interest at either LIBOR(a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s election, the prime rateoption, (b) LIBOR plus 1.25%3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.00%2.75% or the prime rate plus 1%2.50%, respectively, upon achievement of certain rating conditions). |
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| | • | Revolving loan facility borrowings bear interest at either LIBOR(a) the greater of the prime rate and the federal funds effective rate plus 2.50%0.5%, plus in either case 2.25%, or, at the borrower’s election, the prime rateoption, (b) LIBOR plus 1.50%3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.25%2.75% or the prime rate plus 1.25%, respectively, and then to LIBOR plus 2.00% or the prime rate plus 1%2.50%, respectively, upon certain prepayments of the term loans and substantial completionachievement of certain capital expenditure projects)rating conditions). |
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| | • | Letters of credit issued under the $50.0$75.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per annum owing to the issuing lender. |
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| | • | Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit. |
In addition to the fees stated above, the amended and restated First Lien Credit Facility requires the borrower to pay 0.50% per annum in commitment fees on the unused portion of the revolving loan facility and 1.00% in commitment fees on the unused portion of the delayed draw term loan commitment.facility.
The Second Lien Credit Facility borrowings bear interest at LIBOR plus 6.75%requires the borrower to prepay outstanding loans, subject to certain exceptions, with:
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| • | 100% of the net asset sale proceeds received from specified asset sales and net insurance/ condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations; |
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| • | 100% of the cash proceeds from the incurrence of specified debt obligations; and |
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| • | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 or 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00. |
Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving letters of credit and
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funded letters of credit. Voluntary prepayments of loans under the Credit Facility are permitted, in whole or in part, at the borrower’s option, the prime rate plus 5.75%.without premium or penalty.
The First Lien Credit Facility iscontains customary covenants. These agreements, among other things, restrict, subject to mandatory prepaymentsand/certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or commitment reductions associated advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with asset sales, insurance or condemnation proceeds or debt issuances. In addition,affiliates and stockholders, change the First Lienbusiness conducted by the credit parties, and enter into hedging agreements. The Credit Facility also requires prepaymentprovides that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of loans subject to excess cash flow provisions underActual Production (the borrower’s estimated future production of refined products based on the agreement.
Underactual production for the First Lien Credit Facility, in certain circumstances, the borrower is required to prepay allthree prior months) or partfor a term of the First Lien Credit Facility.longer than six years from December 28, 2006. In addition, the borrower may at its option, electnot enter into material amendments related to prepay allany material rights under the Cash Flow Swap or partthe Partnership’s partnership agreement without the prior written approval of the First Lien Credit Facility, subject to LIBOR breakage costs. This offering will not trigger a mandatory prepayment of the First Lien Credit Facility. Any voluntary prepayment or refinancing of the Second Lien Credit Facility is subject to a prepayment premium until June 24, 2008.
Both the First Lien Credit Facility and the Second Lien Facility contain customary covenants and events of default, including an event of default upon the occurrence of a change of control. Accordingly, these agreements impose significant operating and financial restrictions on our operations. These restrictions, among other things, limit incurrence of additional indebtedness, maintenance of certain commodity agreements, capital expenditures, creation of liens, payment of dividends, significant investments and sales of assets.lenders. These limitations are subject to critical exceptions and exclusions and are not designed to protect investors in our common stock.
In particular, the agreements requireThe Credit Facility also requires the borrower to maintain certain financial ratios as follows:
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June 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
September 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
December 31, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
March 31, 2007 | | | 2.25:1.00 | | | | 4.75:1.00 | | | | 5.00:1.00 | |
June 30, 2007 | | | 2.50:1.00 | | | | 4.50:1.00 | | | | 4.75:1.00 | |
September 30, 2007 | | | 2.75:1.00 | | | | 4.25:1.00 | | | | 4.75:1.00 | |
December 31, 2007 | | | 3.00:1.00 | | | | 3.50:1.00 | | | | 4.00:1.00 | |
March 31, 2008 | | | 3.25:1.00 | | | | 3.50:3.00:1.00 | | | | 4.00:1.00 | |
June 30, 2008 | | | 3.25:1.00 | | | | 3.25:1.00 | | | | 3.75:1.00 | |
| September 30, 2008 | | | 3.25:1.00 | | | | 3.00:2.75:1.00 | | | | 3.50:1.00 | |
| December 31, 2008 | | | 3.25:1.00 | | | | 2.75:2.50:1.00 | | | | 3.25:1.00 | |
| March 31, 2009 and thereafter | | | 3.50:3.75:1.00 | | | | 2.50:2.25:1.00 | | | | 3.00: to
December 31, 2009
2.00:1.00 | thereafter |
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The computation of these ratios is governed by the specific terms of the credit agreementsCredit Facility and may not be comparable to other similarly titled measures computed for other purposes or by other companies. The minimum interest coverage ratio is the ratio of consolidated adjusted EBITDA to consolidated cash interest expense over a four quarter period. The maximum leverage ratio is the ratio of consolidated total debt to consolidated adjusted EBITDA over a four quarter period. The computation of these ratios requires a calculation of consolidated adjusted EBITDA. In general, under the terms of our Credit Facility, consolidated adjusted EBITDA is calculated by adding consolidated net income, consolidated interest expense, income taxes, depreciation and amortization, other non- cash expenses, any fees and expenses related to permitted acquisitions, any non-recurring expenses incurred in connection with the issuance of debt or equity, management fees, any unusual or non-recurring charges up to 7.5% of consolidated adjusted EBITDA, any net after-tax loss from disposed or discontinued operations, any incremental property taxes related to abatement non-renewal, any losses attributable to minority equity interests and major scheduled turnaround expenses. As of the date of this prospectus, we were in compliance with our covenants under the Credit Facility.
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We present consolidated adjusted EBITDA because it is a material component of material covenants within our current Credit Facility and significantly impacts our liquidity and ability to borrow under our revolving line of credit. However, consolidated adjusted EBITDA is not a defined term under GAAP and should not be considered as an alternative to operating income or net income as a measure of operating results or as an alternative to cash flows as a measure of liquidity. Consolidated adjusted EBITDA is calculated under the Credit Facility as follows:
| | | | | | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | |
| | | Predecessor and
| | | | |
| | | Successor
| | | | |
| | | Combined
| | | | |
| | | (Non-GAAP) | | | Successor | |
| | | Year Ended December 31, | | | | Three Months Ended March 31, | |
Consolidated Financial Results | | 2005 | | | 2006 | | | 2007 | | | | 2007 | | | 2008 | |
| | | (unaudited) | | | (in millions) | | | | | | | (unaudited in millions) | |
| Net income (loss) | | $ | (66.8 | ) | | $ | 191.6 | | | $ | (67.6 | ) | | | $ | (154.4 | ) | | $ | 22.2 | |
| Plus: | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 25.1 | | | | 51.0 | | | | 68.4 | | | | | 14.2 | | | | 19.6 | |
| Interest expense | | | 32.8 | | | | 43.9 | | | | 61.1 | | | | | 11.9 | | | | 11.3 | |
| Income tax expense (benefit) | | | (26.9 | ) | | | 119.8 | | | | (88.5 | ) | | | | (47.3 | ) | | | 6.9 | |
| Loss on extinguishment of debt | | | 8.1 | | | | 23.4 | | | | 1.3 | | | | | — | | | | — | |
| Inventory fair market value adjustment | | | 16.6 | | | | — | | | | — | | | | | — | | | | — | |
| Funded letters of credit expenses and interest rate swap not included in interest expense | | | 2.3 | | | | — | | | | 1.8 | | | | | — | | | | 0.9 | |
| Major scheduled turnaround expense | | | — | | | | 6.6 | | | | 76.4 | | | | | 66.0 | | | | — | |
| Loss on termination of Swap | | | 25.0 | | | | — | | | | — | | | | | — | | | | — | |
| Unrealized (gain) or loss on derivatives | | | 229.8 | | | | (128.5 | ) | | | 113.5 | | | | | 126.9 | | | | 18.9 | |
| Non-cash compensation expense for equity awards | | | 1.8 | | | | 16.9 | | | | 43.5 | | | | | 3.7 | | | | (0.4 | ) |
| (Gain) or loss on disposition of fixed assets | | | — | | | | 1.2 | | | | 1.3 | | | | | — | | | | — | |
| Expenses related to acquisition | | | 3.5 | | | | — | | | | — | | | | | — | | | | — | |
| Minority interest in subsidiaries | | | — | | | | — | | | | (0.2 | ) | | | | (0.7 | ) | | | — | |
| Management fees | | | 2.3 | | | | 2.3 | | | | 11.7 | | | | | 0.5 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | |
| Consolidated adjusted EBITDA | | $ | 253.6 | | | $ | 328.2 | | | $ | 222.7 | | | | $ | 20.8 | | | $ | 79.4 | |
| | | | | | | | | | | | | | | | | | | | | | |
In addition to the financial covenants summarized in the table above, the First Lien Credit Facility restricts the borrower’s capital expenditures of Coffeyville Resources, LLC to $230.0 million in 2006, $70.0 million in 2007 and $40.0$125.0 million in 2008, $125.0 million in 2009, $80.0 million in 2010, and each year$50.0 million in 2011 and thereafter. The capital expenditures are measured based on actual capital expenditures excluding the continuous catalytic reformer and fluidized catalytic crack unit projects and includecovenant includes a mechanism for carrying over the excess of any previous year’s capital expenditure limit. The continuous catalytic reformercapital expenditures limitation will not apply for any fiscal year commencing with fiscal 2009 if the borrower obtains a total leverage ratio of less than or equal to 1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe the limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our current capital expenditure needs. However, if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned, we would need to obtain consent from the lenders under our Credit Facility.
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The Credit Facility also contains customary events of default. The events of default include the failure to pay interest and fluidized catalytic cracking unitprincipal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20.0 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20.0 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20.0 million, events relating to employee benefit plans resulting in liability in excess of $20.0 million, a change in control, the guarantees, collateral documents or the Credit Facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the Credit Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.
Under the terms of our Credit Facility, our initial public offering was deemed a “Qualified IPO” because the offering generated more than $250.0 million of gross proceeds and we used the proceeds of the offering to repay at least $275.0 million of term loans under the Credit Facility. As a result of our Qualified IPO, the interest margin on LIBOR loans may in the future decrease from 3.25% to 2.75% (if we have credit ratings of B2/B) or 2.50% (if we have credit ratings of B1/B+). Interest on base rate loans will similarly be adjusted. In addition, as a result of our Qualified IPO, (1) we will be allowed to borrow an additional $225.0 million under the Credit Facility after June 30, 2008 to finance capital enhancement projects if we are in pro forma compliance with the financial covenants in the Credit Facility and the rating agencies confirm our ratings, (2) we will be allowed to pay an additional $35.0 million of dividends each year, if our corporate family ratings are at least B2 from Moody’s and B from S&P, (3) we will not be subject to their own specificany capital expenditure limitationexpenditures limitations commencing with fiscal 2009 if our total leverage ratio is less than or equal to 1.25:1 for any quarter commencing with the quarter ending December 31, 2008, and (4) at any time after March 31, 2008 we will be allowed to reduce the Cash Flow Swap to not less than 35,000 barrels a day for fiscal 2008 and terminate the Cash Flow Swap for any year commencing with fiscal 2009, so long as our total leverage ratio is less than or equal to 1.25:1 and we have a corporate family rating of $165.0 million.at least B2 from Moody’s and B from S&P.
The credit agreements areCredit Facility is subject to an intercreditor agreement betweenamong the lenders of both credit agreements and the Cash Flow Swap provider, which deal with, among other things, priority of liens, payments and proceeds of sale of collateral.
At June 30, 2006,March 31, 2008 and December 31, 2007, funded long-term debt, including current maturities, totaled $223.3$488.0 million and $489.2 million, respectively, of tranche C term loans, $10.0 million of delayed draw term loans and $275.0 million of second lienD term loans. Other commitments at March 31, 2008 and December 31, 2007 included a $150.0 million funded letter of credit facility and a $100.0$150.0 million revolving credit facility. As of June 30, 2006,March 31, 2008, the commitmentscommitment outstanding on the revolving loan facilities were $3.2credit facility was $37.4 million, including $5.8 million in letters of credit issued in support of certain environmental obligations $3.2and $31.6 million in letters of credit to secure transportation services for a crude oil pipeline and a $38.5oil. As of December 31, 2007, the commitment outstanding on the revolving credit facility was $39.4 million, letterincluding $5.8 million in letters of credit issued in support of the purchasecertain environmental obligations, $3.0 million in support of surety bonds in place to support state and federal excise tax for refined fuels, and $30.6 million in letters of credit to secure transportation services for crude oil.
August 2007 Credit Facilities
The 2007 flood and crude oil discharge had a significant negative effect on our liquidity in July/August 2007. We did not generate any material revenue while our facilities were shut down due to the flood, but we incurred and continue to incur significant flood repair and cleanup costs, as well as
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incremental legal, public relations and crisis management costs. We also had significant contractual obligations to purchase gathered crude oil. We also owed J. Aron approximately $123.7 million under the Cash Flow Swap, which we deferred to January 31, 2008 (see “— Payment Deferrals Related to Cash Flow Swap” below). In addition, although we believe that we will recover substantial sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery.
As a result of these factors, in August 2007 our subsidiaries entered into three new credit facilities.
| | |
| • | $25.0 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
|
| • | $25.0 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
|
| • | $75.0 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility. |
All indebtedness outstanding under the $25.0 million secured facility and the $25.0 million unsecured facility was repaid in October 2007 with the proceeds of our initial public offering, and all three facilities were terminated at that time.
Payment Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 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. We are required to measureuse 37.5% of our complianceconsolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts, but as of March 31, 2008 we were not required to prepay any portion of the deferred amount.
| | |
| • | On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%. |
|
| • | On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payment and (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
|
| • | On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued |
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| | |
| | interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one-half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
| | |
| • | On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million, plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%. |
Nitrogen Fertilizer Limited Partnership
The managing general partner of the Partnership may, from time to time, seek to raise capital through a public or private offering of limited partner interests in the Partnership. Any decision to pursue such a transaction would be made in the discretion of the managing general partner, not us, and any proceeds raised in a primary offering would be for the benefit of the Partnership, not us (although in some cases, depending on the structure of the transaction, the Partnership might remit proceeds to us). If the managing general partner elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Any such amendments could result in significant changes to our Credit Facility’s pricing, mandatory repayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice.
However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend our Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140.0 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and to distribute that cash to us prior to, or concurrently with, the financial ratios and other required metrics underclosing of its initial public or private offering. If the first and second lienmanaging general partner sells interests to third party investors, we expect that the Partnership may at such time seek to enter into its own credit agreements onfacility.
The Partnership filed a quarterly basis andregistration statement in February 2008 for an initial public offering of its common units. On June 13, 2008, we were in complianceannounced that the managing general partner of the Partnership has decided to postpone indefinitely the Partnership’s initial public offering due to current market conditions for master limited partnerships. We believe maintaining the fertilizer business within the Company provides greater value for CVR Energy shareholders than would be the case if the Partnership became a publicly-traded partnership at this time. The Partnership subsequently
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requested that the registration statement be withdrawn. The Partnership may elect to move forward with those ratios as of June 30, 2006. As of June 30, 2006, our minimum interest coverage ratio was 6.93:1 and our maximum leverage ratio was 1.39:1, in each case as such ratios are defined and calculateda public or private offering in the firstfuture. Any future public or private offering by the Partnership would be made solely at the discretion of the Partnership’s managing general partner, subject to our specified joint management rights, and second lien credit agreements.would be subject to market conditions and negotiation of terms acceptable to the Partnership’s managing general partner. In connection with the Partnership’s initial public or private offering, if any, the Partnership may require us to include a sale of a portion of our interests in the Partnership. If the Partnership becomes a public company, we may consider a secondary offering of interests which we own (either in connection with a public offering by the Partnership, but subject to priority rights in favor of the Partnership, or following completion of the Partnership’s initial public offering, if any) or in a private placement. We cannot assure you that any such transaction will be consummated. Neither the consent of the managing general partner nor the consent of the Partnership is required for any sale of our interests in the Partnership, other than customary blackout periods relating to offerings by the Partnership. Any proceeds raised would be for our benefit. The Partnership has granted us registration rights which will require the Partnership to register our interests with the SEC at our request from time to time (following any public offering by the Partnership), subject to various limitations and requirements. We cannot assure you that any such transaction will be consummated.
Capital Spending
We divide our capital spending needs into two categories,categories: non-discretionary, which is either capitalized or expensed, and discretionary, which is capitalized. Non-discretionary capital spending, such as for planned turnarounds and other maintenance, is required to maintain safe and reliable operations or to comply with environmental, health and safety regulations. We estimate that ourThe total non-discretionary capital spending needs for our refinery business and the nitrogen fertilizer business, including major scheduled turnaround expenses, will bewere approximately $153$170 million in 2006 approximately $85and $218 million in 2007 and we estimate that the total non-discretionary capital spending needs of our refinery business and the nitrogen fertilizer business will be approximately $142$279 million in the aggregate over the three-year period beginning 2008. These estimates include, among other items, the capital costs necessary to comply with environmental regulations, including Tier II gasoline standards and on-road diesel regulations. As described above, our credit facilities limitfacility limits the amount we can spend on capital expenditures.
We estimate that complianceCompliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately $97$68 million during 2006 (most of which has already been spent), approximately $11 million during 2007 and approximately $12 millionin the aggregate between 2008 and 2010. These amounts are reflected in the table below under “Environmental and safety capital needs.” See “Business — Environmental Matters — Fuel Regulations — Tier II, Low Sulfur Fuels.”
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The following table sets forth our estimate of our non-discretionary spending for our refinery business and the nitrogen fertilizer business for the years presented as of June 30, 2006:March 31, 2008 (other than 2006 and 2007 which reflect actual spending). Capital spending for the nitrogen fertilizer business has been and will be determined by the managing general partner of the Partnership. The data contained in the table below represents our current plans, but these plans may change as a result of unforeseen
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circumstances and we may revise these estimates from time to time or not spend the amounts in the manner allocated below.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | Cumulative
| |
| | | | | | | | | | | | | | | | | | Through
| |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2010 | |
| | | (in millions) | |
| |
| Environmental capital needs | | $ | 115.5 | | | $ | 27.8 | | | $ | 18.5 | | | $ | 15.4 | | | $ | 8.5 | | | $ | 185.7 | |
| Sustaining capital needs | | | 32.0 | | | | 26.5 | | | | 21.9 | | | | 21.4 | | | | 17.6 | | | | 119.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Subtotal | | $ | 147.5 | | | $ | 54.3 | | | $ | 40.4 | | | $ | 36.8 | | | $ | 26.1 | | | $ | 305.1 | |
| Turnaround expenses | | | 5.6 | | | | 30.8 | | | | 3.0 | | | | 3.0 | | | | 33.0 | | | | 75.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 153.1 | | | $ | 85.1 | | | $ | 43.4 | | | $ | 39.8 | | | $ | 59.1 | | | $ | 380.5 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Petroleum Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
| |
| Environmental and safety capital needs | | $ | 144.6 | | | $ | 121.8 | | | $ | 46.0 | | | $ | 53.9 | | | $ | 23.5 | | | $ | 2.6 | | | $ | 2.1 | | | $ | 394.5 | |
| Sustaining capital needs | | | 11.8 | | | | 14.9 | | | | 22.0 | | | | 29.8 | | | | 22.3 | | | | 22.0 | | | | 22.0 | | | | 144.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 156.4 | | | | 136.7 | | | | 68.0 | | | | 83.7 | | | | 45.8 | | | | 24.6 | | | | 24.1 | | | | 539.3 | |
| Major scheduled turnaround expenses | | | 4.0 | | | | 76.4 | | | | — | | | | — | | | | 50.0 | | | | — | | | | — | | | | 130.4 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 160.4 | | | $ | 213.1 | | | $ | 68.0 | | | $ | 83.7 | | | $ | 95.8 | | | $ | 24.6 | | | $ | 24.1 | | | $ | 669.7 | |
Nitrogen Fertilizer Business
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | (in millions) | |
| |
| Environmental and safety capital needs | | $ | 0.1 | | | $ | 0.5 | | | $ | 2.2 | | | $ | 4.5 | | | $ | 2.6 | | | | 2.7 | | | | 3.8 | | | $ | 16.4 | |
| Sustaining capital needs | | | 6.6 | | | | 3.9 | | | | 9.7 | | | | 3.1 | | | | 4.5 | | | | 4.8 | | | | 4.3 | | | | 36.9 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 6.7 | | | | 4.4 | | | | 11.9 | | | | 7.6 | | | | 7.1 | | | | 7.5 | | | | 8.1 | | | | 53.3 | |
| Major scheduled turnaround expenses | | | 2.6 | | | | — | | | | 2.8 | | | | — | | | | 2.6 | | | | — | | | | 2.8 | | | | 10.8 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 9.3 | | | $ | 4.4 | | | $ | 14.7 | | | $ | 7.6 | | | $ | 9.7 | | | $ | 7.5 | | | $ | 10.9 | | | $ | 64.1 | |
Combined
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2006 | | | 2007 | | | 2008 | | | 2009 | | | 2010 | | | 2011 | | | 2012 | | | Cumulative | |
| | | | | | | | | | | | (in millions) | | | | | | | | | | |
| |
| Environmental and safety capital needs | | $ | 144.7 | | | $ | 122.3 | | | $ | 48.2 | | | $ | 58.4 | | | $ | 26.1 | | | | 5.3 | | | | 5.9 | | | $ | 410.9 | |
| Sustaining capital needs | | | 18.4 | | | | 18.8 | | | | 31.7 | | | | 32.9 | | | | 26.8 | | | | 26.8 | | | | 26.3 | | | | 181.7 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 163.1 | | | | 141.1 | | | | 79.9 | | | | 91.3 | | | | 52.9 | | | | 32.1 | | | | 32.2 | | | | 592.6 | |
| Major scheduled turnaround expenses | | | 6.6 | | | | 76.4 | | | | 2.8 | | | | — | | | | 52.6 | | | | — | | | | 2.8 | | | | 141.2 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total estimated non-discretionary spending | | $ | 169.7 | | | $ | 217.5 | | | $ | 82.7 | | | $ | 91.3 | | | $ | 105.5 | | | $ | 32.1 | | | $ | 35.0 | | | $ | 733.8 | |
We undertake discretionary capital spending based on the expected return on incremental capital employed. Discretionary capital projects generally involve an expansion of existing capacity, improvement in product yields,and/or a reduction in manufacturingdirect operating expenses. As of June 30, 2006,December 31, 2007, we had committed approximately $150$14 million towards discretionary capital spending in 2006.2008. Other than the nitrogen fertilizer plant expansion project referred to below, we anticipate that our discretionary capital spending will average approximately $35 million per year between 2008 and 2012.
The Partnership is currently moving forward with an approximately $120 million fertilizer plant expansion, of which approximately $11 million was incurred as of March 31, 2008. We estimate this expansion will increase the nitrogen fertilizer plant’s capacity to upgrade ammonia into premium priced UAN by approximately 50%. Management currently expects to complete this expansion in July 2010. This project is also expected to improve the cost structure of the nitrogen fertilizer business by eliminating the need for rail shipments of ammonia, thereby avoiding anticipated cost increases in such transport.
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Cash Flows
ComparabilityThe following table sets forth our cash flows for the periods indicated below:
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | |
| | | Predecessor | | | Successor | |
| | | 174 Days
| | | 233 Days
| | | Year
| | | | |
| | | Ended
| | | Ended
| | | Ended
| | | Three Months
| |
| | | June 23, | | | December 31, | | | December 31, | | | Ended March 31, | |
| | | 2005 | | | 2005 | | | 2006 | | | 2007 | | | 2007 | | | 2008 | |
| | | | | | | | | | | | | | | (unaudited) | | | (unaudited) | |
| | | (in millions) | |
| |
| Net cash provided by (used in) | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating activities | | $ | 12.7 | | | $ | 82.5 | | | $ | 186.6 | | | $ | 145.9 | | | $ | 44.1 | | | $ | 24.2 | |
| Investing activities | | | (12.3 | ) | | | (730.3 | ) | | | (240.2 | ) | | | (268.6 | ) | | | (107.3 | ) | | | (26.2 | ) |
| Financing activities | | | (52.4 | ) | | | 712.5 | | | | 30.8 | | | | 111.3 | | | | 28.9 | | | | (3.4 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | $ | (52.0 | ) | | $ | 64.7 | | | $ | (22.8 | ) | | $ | (11.4 | ) | | $ | (34.3 | ) | | $ | (5.4 | ) |
In addition, we are currently entitled to all cash distributed by the Partnership. However, the amount of cash flows from operating activitiesthe Partnership that we will receive in the future may be limited by a number of factors. The Partnership may enter into its own credit facility or other contracts that limit its ability to make distributions to us. Additionally, in the future the managing general partner of the Partnership will receive a greater allocation of distributions as more cash becomes available for distribution, and consequently we will receive a smaller percentage of quarterly distributions over time. Our rights to distributions will also be adversely affected if the six months ended June 30, 2006Partnership consummates a public or private equity offering in the future. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and 2005“Risk Factors — Risks Related to the Nitrogen Fertilizer Business — The nitrogen fertilizer business may not have sufficient cash to enable it to make quarterly distributions to us following the payment of expenses and fees and the years ended December 31, 2005, 2004 and 2003 has been impacted by the Initial Acquisition and the Subsequent Acquisition. See “Factors Affecting Comparability.” Therefore, we have presented our discussionestablishment of cash flows from operations by comparing (1) the six months ending June 30, 2006 with the 174 days ended June 23, 2005 and the 49 days ended June 30, 2005, (2) the 233 days ended December 31, 2005, the 174 days ended June 23, 2005, the 304 days ended December 31, 2004 and the 62 days ended March 2, 2004 and (3) the year ended December 31, 2003, the 62 days ended March 2, 2004, and the 304 days ended December 31, 2004.
We believe that the most meaningful way to comment on cash flows from investing and financing activities is to compare the sum of the combined cash flows for the six months ended June 30, 2006 and 2005 and the twelve months ended December 31, 2005 and 2004.reserves.”
Cash Flows Provided by Operating Activities
Comparison of Sixthe Three Months Ended June 30,March 31, 2008 and the Three Months Ended March 31, 2007
Net cash flows from operating activities for the three months ended March 31, 2008 was $24.2 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital and other assets and liabilities, partially offset by unfavorable changes in trading working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net loss for the three months ended March 31, 2008 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2008 (approximately two years and three months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash
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Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $20.8 million increase in the payable to swap counterparty. Other sources of cash in other working capital included $16.6 million of deferred revenue related to prepaid fertilizer shipments and a $5.2 increase in accrued income taxes. Trade working capital for the three months ended March 31, 2008 resulted in a use of cash of $67.5 million. For the three months ended March 31, 2008, accounts receivable increased $30.7 million, inventory increased by $31.6 and accounts payable decreased by $5.2 million.
Net cash flows provided by operating activities for the three months ended March 31, 2007 was $44.1 million. The positive cash flow from operating activities during this period was primarily the result of changes in other assets and liabilities offset by unfavorable changes in trade working capital and other working capital. Net income for the period was not indicative of the operating margins for the period. This was the result of the accounting treatment of our derivatives in general and, more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net loss for the three months ended March 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of March 31, 2007 (approximately three years and three months years) and the NYMEX crack spread that is the basis for the underlying swaps had increased during the period, the unrealized losses on the Cash Flow Swap significantly decreased our net income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $129.3 million increase in the payable to swap counterparty. Adding to our operating cash flow for the three months ended March 31, 2007 was a $68.0 million source of cash related to a decrease in trade working capital. For the three months ended March 31, 2007, accounts receivable decreased $44.6 million while inventory increased $23.0 million and accounts payable increased $46.4 million. The change in trade working capital was primarily driven by the impact of the refinery turnaround that began in February 2007. The primary use of cash during the period was $41.3 million for deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
Comparison of the Year Ended December 31, 2007, the Year Ended December 31, 2006, the 174 Days Ended June 23, 2005 and the 49233 Days Ended June 30,December 31, 2005.
ComparabilityNet cash flows from operating activities for the year ended December 31, 2007 was $145.9 million. The positive cash flow from operating activities generated over this period was primarily driven by favorable changes in other working capital partially offset by unfavorable changes in trade working capital and other assets and liabilities over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, inventory and accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net loss for the year ended December 31, 2007 included both the realized losses and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2007 (approximately two years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had increased, the unrealized losses on the Cash Flow Swap significantly decreased our Net Income over this period. The impact of these unrealized losses on the Cash Flow Swap is apparent in the $240.9 million increase in the payable to swap counterparty. Other sources of cash from other working capital included $4.8 million from prepaid expenses and other current assets, $27.0 million from other current liabilities and $20.0 million in insurance proceeds. Reducing our operating cash flow for the year ended December 31, 2007 was $42.9 million use of cash related to changes in trade working capital. For the year ended December 31, 2007, accounts receivable increased $17.0 million and inventory increased by $85.0 million resulting in a net use of cash of $102.0 million. These uses of cash due to changes in trade working
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capital were partially offset by an increase in accounts payable, or a source of cash, of $59.1 million. Other primary uses of cash during the period include a $105.3 million increase in our insurance receivable related to the flood and a $57.7 million use of cash related to deferred income taxes primarily the result of the unrealized loss on the Cash Flow Swap.
Net cash flows from operating activities for the year ended December 31, 2006 was $186.6 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other assets and liabilities, partially offset by unfavorable changes in trade working capital and other working capital over the period. Net income for the period was not indicative of the operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the year ended December 31, 2006 included both the realized losses and the unrealized gains on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2006 (approximately three years and six months) and the NYMEX crack spread that is the basis for the underlying swaps had declined, the unrealized gains on the Cash Flow Swap significantly increased our net income over this period. The impact of these unrealized gains on the Cash Flow Swap is apparent in the $147.0 million decrease in the payable to swap counterparty. Reducing our operating cash flow for the year ended December 31, 2006 was a $0.3 million use of cash related to an increase in trade working capital. For the year ended December 31, 2006, accounts receivable decreased approximately $1.9 million while inventory increased $7.2 million and accounts payable increased $5.0 million. Other primary uses of cash during the period include a $5.4 million increase in prepaid expenses and other current assets and a $37.0 million reduction in accrued income taxes. Offsetting these uses of cash was an $86.8 million increase in deferred income taxes primarily the result of the unrealized gain on the Cash Flow Swap and a $4.6 million increase in other current liabilities.
Analysis of cash flows from operating activities for the six monthsyear ended June 30, 2006 and the six months ended June 30,December 31, 2005 has beenwas impacted by the Initial Acquisition and the Subsequent Acquisition. See “— Factors Affecting Comparability.” For instance, completion of the Subsequent Acquisition by Successor required a mark up of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of goodsproduct sold. Therefore, the discussion of cash flows from operations has been broken down into three separate periods: the 174 days ended June 23, 2005 and the 49233 days ended June 30, 2005 and the six months ending June 30, 2006.December 31, 2005.
Net cash flows from operating activities for the six months ended June 30, 2006 was $120.3 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other working capital over the period. Net income for the period was not indicative of the strong operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. See “— Consolidated Results of Operations — Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005 (Non-GAAP Combined).” We have
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determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the six months ended June 30, 2006 included both the realized and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of June 30, 2006 (approximately four years) and the NYMEX crack spread that is the basis for the underlying swaps had improved substantially, the unrealized losses on the Cash Flow Swap significantly reduced our Net Income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $112.2 million unrealized loss related to the increase in the payable to swap counterparty. Reducing our operating earnings for the six months ended June 30, 2006 was a $20.6 million use of cash related to an increase in trade working capital. For the six months ending June 30, 2006, accounts receivable decreased approximately $8.0 million while inventory increased $25.4 million. The primary reason for the increase in inventory relates to the increased overall volumes in inventory and also overall price increases in the related crude oil and refined product inventory. In addition to the $112.2 million unrealized loss related to the increase in the payable to swap counterparty, accrued income taxes increased $6.4 million during the period. This unrealized loss was partially offset by a reduction in deferred revenue of $10.5 million for the six months ending June 30, 2006 as a result of deliveries of fertilizer products that were completed.
Net cash flows from operating activities for the 174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by strong income of $52.4 million, offset by a $54.3 million increase in trade working capital. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, plus inventory, less accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.
Net cash flows used in operating activities for the 49 days ended June 30, 2005 was a use of $22.4 million. The negative cash flow from operating activities during this period was primarily the result of the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins and the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. At the closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless and thus resulted in the expensing of the associated premium. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and “— Consolidated Results of Operations — Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005 (Non-GAAP Combined).” We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the six months ended June 30, 2005 included the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap became effective July 1, 2005 and had an original term of approximately five years and the NYMEX crack spread that is the basis for the underlying swaps had improved since the trade date of the Cash Flow Swap on June 16, 2005, the unrealized losses on the Cash Flow Swap significantly reduced our net income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $127.2 million unrealized loss in the period related to the increase in the payable to swap counterparty. Additionally and as a result of the closing of the Subsequent Acquisition, Successor marked up the value of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash flow for Successor as it capitalized that portion of the purchase price of the assets into cost of goods sold. The total impact of this for the 49 days ended June 30, 2005 was $14.3 million. Offsetting the uses of cash from operating activities highlighted above were sources of cash of $15.9 million from favorable changes in net working capital.
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Comparison of the 233 Days Ended December 31, 2005, the 174 Days Ended June 23, 2005, the 304 Days Ended December 31, 2004 and the 62 Days Ended March 2, 2004.
Comparability of cash flows from operating activities for the year ended December 31, 2005 to the year ended December 31, 2004 has been impacted by the Initial Acquisition and the Subsequent Acquisition. See “— Factors Affecting Comparability.” Immediate Predecessor did not assume the accounts receivable or the accounts payable of Farmland. As a result, Farmland collected and made payments on these accounts after March 3, 2004 and these transactions are not included on our consolidated statements of cash flows. In addition, Coffeyville Acquisition LLC’s acquisition of the subsidiaries of Coffeyville Group Holdings, LLC required a mark up of purchased inventory to fair market value at the closing of the Initial Acquisition on June 24, 2005. This had the effect of reducing overall cash flow for Coffeyville Acquisition LLC as it capitalized that portion of the purchase price of the assets into cost of goods sold. Therefore, the discussion of cash flows from operations has been broken down into four separate periods: the 233 days ended December 31, 2005, the 174 days ended June 23, 2005, the 304 days ended December 31, 2004 and the 62 days ended March 2, 2004.
Net cash flows for operating activities for the 233 days ended December 31, 2005 was $82.5 million. The positive cash flow from operating activities generated over this period was primarily driven by our strong operating environment and favorable changes in other working capital over the period. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, plus inventory, less accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. The net income for the period was not indicative of the excellent operating margins for the period. This is the result of the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. See “— Consolidated Results of Operations — Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).” We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities. Therefore, the net income for the 233 days ended December 31, 2005 included both the realized and the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap had a significant term remaining as of December 31, 2005 (approximately four and one-half years) and the NYMEX crack spread that is the basis for the underlying swaps had improved substantially, the unrealized losses on the Cash Flow Swap significantly reduced our Net Income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $256.7 million unrealized loss in the period related to the increase in the payable to swap counterparty. Contributing to the sources of cash for operating activities during the period was a decrease of trade working capital of $8.0 million and an increase in both deferred revenue and other current liabilities of $10.0 million and $10.5 million, respectively. Primary uses of cash during the period were related to increases in prepaid expenses of $6.5 million due to increases in insurance and other prepaids and an increase in deferred income taxes associated with purchase price accounting for the transaction of $98.4 million.
Net cash flows for operating activities for the 174 days ended June 23, 2005 was $12.7 million. The positive cash flow generated over this period was primarily driven by income of $52.4 million, offset by a $54.3 million increase in trade working capital. During this period, accounts receivable and inventory increased $11.3 million and $59.0 million, respectively. These uses of cash were primarily the result of our expansion into the rack marketing business, which offered increased accounts receivable credit terms relative to bulk refined product sales, an increase in product sales prices and an increase in overall inventory levels.
Net cash flow fromflows provided by operating activities for the 304233 days ended December 31, 20042005 was $89.8$82.5 million. The primary driver for the positive cash flow from operations over this period was cash earnings and favorable changes in trade working capital. During this period, we experienced favorable market conditions in our petroleum and nitrogen fertilizer businesses. Changes in trade working capital produced cash flow of approximately $27.6 million during this period. For the 304 days ended December 31, 2004, we experienced a $20.1 million decrease in inventory due to an effort to reduce
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inventory carrying levels and a $31.1 million increase in accounts payable due to the extension of credit terms by several crude oil vendors and a large electricity vendor. These positive cash flows from operations were partially offset by an increase in accounts receivable of $23.6 million as Immediate Predecessor assumed ownership of the business from Farmland. In addition, changes in other working capital generated approximately $8.7 million in cash during the period. This was primarily the result of increases in other current liabilities by $13.0 million as a result of accruals for personnel, taxes other than income taxes, leases, freight and professional services, offset by reductions in certain prepaid expenses.
Net cash from operating activities for the 62 days ended March 2, 2004 was $53.2 million. The positive cash flow generated over this period was primarily driventhe result of strong operating earnings during the period partially offset by the expensing of a $25.0 million option entered into by Successor for the purpose of hedging certain levels of refined product margins and the accounting treatment of our derivatives in general and more specifically, the Cash Flow Swap. At the closing of the Subsequent Acquisition, we determined that this option was not economical and we allowed the option to expire worthless and thus resulted in the expensing of the associated premium. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk” and “— Results of Operations — Consolidated Results of Operations — Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005 (Consolidated).” We have determined that the Cash Flow Swap does not
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qualify as a hedge for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.Therefore, the net income for the year ended December 31, 2005 included the unrealized losses on the Cash Flow Swap. Since the Cash Flow Swap became effective July 1, 2005 and had an original term of approximately five years and the NYMEX crack spread that is the basis for the underlying swaps had improved since the trade date of the Cash Flow Swap on June 16, 2005, the unrealized losses on the Cash Flow Swap significantly reduced our net income over this period. The impact of these unrealized losses on all derivatives, including the Cash Flow Swap, is apparent in the $256.7 million increase in the payable to swap counterparty. Additionally and as a result of the closing of the Subsequent Acquisition, Successor marked up the value of purchased inventory to fair market value at the closing of the transaction on June 24, 2005. This had the effect of reducing overall cash earnings and favorable changes in otherflow for Successor as it capitalized that portion of the purchase price of the assets into cost of product sold. The total impact of this for the 233 days ended December 31, 2005 was $14.3 million. Trade working capital of $34.4 million. With respect to other working capital, $25.7provided $8.0 million in cash resulted from reductions in prepaid expenses and other current assets due toduring the reduction in prepaid crude oil required by Farmland due to the Initial Acquisition by Coffeyville Group Holdings, LLC and $8.3 million of deferred revenue resulting primarily from prepaid fertilizer contract activity of our nitrogen fertilizer operations. The $6.5 million of cash flows generated from trade working capital was mainly the result of a $19.6 million decrease233 days ended December 31, 2005 as an increase in accounts receivable duewas more than offset by decreases in inventory and an increase in accounts payable. Offsetting the sources of cash from operating activities highlighted above was a $98.4 million use of cash related to the collectiondeferred income taxes and a $4.7 million use of a large petroleum account, which had been past due.cash related to other long-term assets.
Cash Flows Used In Investing Activities
Comparison of the Year Ended December 31, 2003, the 62 DaysThree Months Ended March 2, 200431, 2008 and the 304 Days Ended December 31, 2004.
Comparability of cash flows from operating activities for the year ended December 31, 2004 to 2003 has been impacted by the closing of the Initial Acquisition on March 3, 2004. We did not assume the accounts receivable or the accounts payable of Farmland. As a result, Farmland collected and made payments on these accounts after March 3, 2004 and these transactions are not included on our consolidated statements of cash flows. Therefore, this discussion of the cash flow from operations has been separated into three periods: the year ended December 31, 2003, the 62 days ended March 2, 2004 and the 304 days ended December 31, 2004.
Net cash flow from operating activities for the 304 days ended December 31, 2004 was $89.8 million. The primary driver for the positive cash flow from operations over this period was cash earnings and favorable changes in trade working capital. For purposes of this cash flow discussion, we define trade working capital as accounts receivable, plus inventory, less accounts payable. Other working capital is defined as all other current assets and liabilities except trade working capital. During this period, we experienced favorable market conditions in our petroleum and nitrogen fertilizer businesses. Changes in trade working capital produced cash flow of approximately $27.6 million during this period. For the 304 days ended December 31, 2004, we experienced a $20.1 million decrease in inventory due to an effort to reduce inventory carrying levels and a $31.1 million increase in accounts payable due to the extension of credit terms by several crude oil vendors and a large electricity vendor. These positive cash flows from operations were partially offset by an increase in accounts receivable of $23.6 million as Immediate Predecessor assumed ownership of the business from Farmland. In addition, changes in other working capital generated approximately $8.7 million in cash during the period. This was primarily the result of increases in other current liabilities by $13.0 million as a result of accruals for personnel, taxes other than income taxes, leases, freight and professional services, offset by reductions in certain prepaid expenses.
Net cash flow from operating activities for the 62 days ended March 2, 2004 was $53.2 million. The positive cash flow generated over this period was primarily driven by cash earnings and favorable changes in other working capital of $34.4 million. With respect to other working capital, $25.7 million in cash resulted from reductions in prepaid expenses and other current assets due to the reduction in prepaid crude oil required by Farmland due to the Initial Acquisition by Coffeyville Group Holdings, LLC and $8.3 million of deferred revenue resulting primarily from prepaid fertilizer contract activity of our nitrogen fertilizer operations. The $6.5 million of cash flows generated from trade working capital
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was mainly the result of a $19.6 million decrease in accounts receivable due to the collection of a large petroleum account, which had been past due.
Net cash flow from operating activities for the year ended December 31, 2003 was $20.3 million. The positive cash flow from operations over this period was directly attributable to cash earnings offset by unfavorable changes in trade and other working capital. The positive cash earnings were the result of an improvement in the environment for both our petroleum and nitrogen fertilizer businesses versus the prior period. The $6.6 million cash outflow resulting from changes in trade working capital was primarily attributable to a $25.3 million increase in accounts receivable due to the delinquency of a large petroleum customer. This increase in accounts receivable was partially offset by a reduction in inventory by $10.4 million and an $8.3 million increase in accounts payable. The increase in other working capital of $21.8 million was primarily driven by a $23.8 million increase in prepaid expenses and other current assets directly attributable to the necessity for Farmland to prepay its crude oil supply during its bankruptcy.
Investing Activities
SixThree Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005 (Non-GAAP Combined).March 31, 2007
Net cash used in investing activities for the sixthree months ended June 30, 2006March 31, 2008 was $86.2$26.2 million compared to $697.7$107.4 million for the sixthree months ended March 31, 2007. The decrease in investing activities for the three months ended March 31, 2008 as compared to the three months ended March 31, 2007 was the result of decreased capital expenditures associated with various capital projects that commenced in the first quarter of 2007 in conjunction with the refinery turnaround.
Comparison of the Year Ended December 31, 2007 and the Year Ended December 31, 2006
Net cash used in investing activities for the year ended December 31, 2007 was $268.6 million compared to $240.2 million for the year ended December 31, 2006. The increase in investing activities for the year ended December 31, 2007 as compared to the year ended December 31, 2006 was the result of increased capital expenditures associated with various capital projects in our petroleum business.
Net cash used in investing activities was $12.3 million for the 174 days ended June 30,23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the six monthscombined period ended December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the year ended December 31, 2005 was approximately $57.4 million in capital expenditures.
Year Ended December 31, 2006 Compared to the 174 Days Ended June 23, 2005 and the 233 Days Ended December 31, 2005.
Net cash used in investing activities for the year ended December 31, 2006 was $240.2 million compared to $12.3 million for the 174 days ended June 30,23, 2005 and $730.3 million for the 233 days ended December 31, 2005. Investing activities for the year ended December 31, 2006 was the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures. Investing activities for the six monthscombined period ended June 30,December 31, 2005 included $685.1 million related to the Subsequent Acquisition. The other primary use of cash for investing activities for the six monthsyear ended June 30,December 31, 2005 was approximately $12.6$57.4 million in capital expenditures.
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Cash Flows (Used in) Provided by Financing Activities
YearComparison of the Three Months Ended DecemberMarch 31, 2005 (Non-GAAP Combined) Compared to Year2008 and the Three Months Ended DecemberMarch 31, 2004 (Non-GAAP Combined).2007
Net cash used in investingfor financing activities for the yearthree months ended DecemberMarch 31, 20052008 was $742.6$3.4 million as compared to $130.8net cash provided by financing activities of $29.0 million in 2004. Both periods included acquisition costs associated with successive owners of the assets. Investing activities for the yearthree months ended DecemberMarch 31, 2005 included2007. During the $685.1three months ended March 31, 2008, we paid $1.2 million of scheduled principal payments and deferred $2.1 million of initial public offering costs related to CVR Partners, LP. For the Subsequent Acquisition. Investing activities forthree months ended March 31, 2007, the year ended December 31, 2004 included the $116.6 million acquisition of our assets by Immediate Predecessor from Original Predecessor on March 3, 2004. The other primary usesource of cash for investing activities was $57.4 million for capital expenditures in 2005 as compared to $14.2 million for 2004. This increase in capital expenditures was primarily the result of a capital spending increase associated with Tier II fuel compliance and other capital expenditures.borrowings drawn on our revolving credit facility.
Comparison of the Year Ended December 31, 2004 (Non-GAAP Combined) Compared to2007 and the Year Ended December 31, 2003.
Net cash used in investing activities for 2004 was $130.8 million compared to $0.8 million in 2003. This difference is directly attributable to an increase in capital expenditures and the acquisition of the Farmland assets during the comparable periods. Throughout its bankruptcy, Farmland maintained capital expenditures for its petroleum and nitrogen assets at a minimum.
Financing Activities
Six Months Ended June 30, 2006 Compared to Six Months Ended June 30, 2005 (Non-GAAP Combined).
Net cash provided by financing activities infor the six monthsyear ended June 30, 2006December 31, 2007 was $29.0$111.3 million as compared to $665.2net cash provided by financing activities of $30.8 million for the six monthsyear ended June 30, 2005.December 31, 2006. The primary
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sources of cash for the six monthsyear ended June 30,December 31, 2007 were obtained through $399.6 million of proceeds associated with our initial public offering. The primary uses of cash for the year ended December 31, 2007 was $335.8 million of long-term debt retirement and $2.5 million in payments of financing costs. The primary sources of cash for the year ended December 31, 2006 were obtained through a refinancing of the Successor’s first and second lien credit facilities into a new long term debt credit facility of $1.075 billion, of which $775.0 million was outstanding as of December 31, 2006. The $775.0 million term loan under the credit facility was used to repay approximately $527.7 million in first and second lien debt outstanding, fund $5.5 million in prepayment penalties associated with the second lien credit facility and fund a $250.0 million cash distribution to Coffeyville Acquisition LLC. Other sources of cash included $20.0 million of additional equity contributions into Coffeyville Acquisition LLC, which was subsequently contributed to our operating subsidiaries, and $10.0$30.0 million of additional delayed draw term loans. These sources of cash were specifically generated to fund a portion of two discretionary capital expenditures at our refining operations.loans issued under the first lien credit facility. During this period, we also paid $1.1$1.7 million of scheduled principal payments on the first lien term loans.
For the combined period ended December 31, 2005, net cash provided by financing activities was $660.0 million. The primary sources of cash for the six months ended June 30, 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $225.6 million of equity. Additional sources of funds during the six months ending June 30, 2005 were obtained through the borrowing of $15.8 million in revolving loan proceeds, net of $10.0 million of repayments. Offsetting these sources of cash from financing activities during the six months ending June 30, 2005 were $23.6 million in deferred financing costs associated with the first and second lien debt commitments raised by Successor in connection with the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) and a $52.2 million cash distribution to Immediate Predecessor prior to the Subsequent Acquisition.
Year Ended December 31, 2005 (Non-GAAP Combined) Compared to Year Ended December 31, 2004 (Non-GAAP Combined).
Net cash provided by financing activities in the yearcombined periods ended December 31, 2005 was $660.0 million as compared to $40.4 million in 2004. The primary sources of cash for 2005 related to the funding of Successor’s acquisition of the assets on June 24, 2005 in the form of $500.0 million in long-term debt and $227.7 million of equity. Additional equity of $10.0 million was contributed into Coffeyville Acquisition LLC subsequent to the aforementioned acquisition, which was subsequently contributed to our operating subsidiaries, in order to fund a portion of two discretionary capital expenditures at our refining operations. Additional sources of funds during the year ended December 31, 2005 were obtained through the borrowing of $0.2 million in revolving loan proceeds, net of $69.6 million of repayments. Offsetting these sources of cash from financing activities during the year ended December 31, 2005 were $24.7$24.6 million in deferred financing costs associated with the first and second lien debt commitments raised by Coffeyville Acquisition LLCSuccessor in connection with the Subsequent Acquisition (see “— Liquidity and Capital Resources — Debt”) and a $52.2 million cash distribution to the owners of Coffeyville Group Holdings, LLCImmediate Predecessor prior to the Subsequent Acquisition.
The uses of cash for financing activities in the year ended December 31, 2004 related primarily to the prepayment of the $23.0 million term loan, a $100.0 million cash distribution to the holders of the preferred See “— Liquidity and common units issued by Coffeyville Group Holdings, LLC, $1.2 million repayment of a capital lease obligation, $16.3 million in financing costs and $53.2 million in net divisional equity distribution to Farmland. We used cash from operations, a $63.3 million equity contribution related to the Initial Acquisition and a new term loan for $150.0 million completed on May 10, 2004 to finance the aforementioned cash outflows in 2004.Capital Resources — Debt.”
Year Ended December 31, 2004 (Non-GAAP Combined) Compared to Year Ended December 31, 2003.Working Capital
Net cash provided by financing activities in 2004Working capital at March 31, 2008, was $40.4 million. The uses$21.5 million, consisting of cash for financing activities over this period related primarily to the prepayment of the $23.0 million term loan, a $100.0 million cash distribution to the holders of the preferred and common units issued by Coffeyville Group Holdings, LLC, $1.2 million repayment of a capital lease obligation, $16.3$622.5 million in financing costscurrent assets and $53.2$601.0 million in net divisional equity distribution to Farmland. We used cash from operations, a $63.3current liabilities. Working capital at December 31, 2007 was $10.7 million, equity contribution related to the Initial Acquisition and a new term loan for $150.0 million completed on May 10, 2004 to finance the aforementioned cash outflows in 2004. In 2003, we used $19.5consisting of $570.2 million in cashcurrent assets and $559.5 million in current liabilities. In addition, we had available borrowing capacity under our revolving credit facility of $112.6 million at March 31, 2008. In the current crude oil price environment, working capital is subject to fund a net divisional equity distribution.substantial variability fromweek-to- week and month-to-month.
PriorLetters of Credit
Our revolving credit facility provides for the issuance of letters of credit. At March 31, 2008, there were $37.4 million of irrevocable letters of credit outstanding, including $5.8 million in support of certain environmental obligators and $31.6 million to the Initial Acquisition, our petroleum and nitrogen fertilizer businesses were organized as divisions within Farmland. As such, these divisions did not have a discreet legal structure from Farmland and the cash flows from these operations were collected and disbursed under Farmland’s centralized approach to cash management and the financing of its operations. The net divisionalsecure transportation services for crude oil.
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equity distribution characterized on the accompanying financial statements represents the net cash generated by these divisions and funded to Farmland to finance its overall operations.
Capital and Commercial Commitments
In addition to long-term debt, we are required to make payments relating to various types of obligations. The following table summarizes our minimum payments as of June 30, 2006March 31, 2008 relating to long-term debt, operating leases, unconditional purchase obligations and other specified capital and commercial commitments for the six months ending December 31, 2006, the four-yearfive-year period following DecemberMarch 31, 20062008 and thereafter.
Our ability to make payments on and to refinance our indebtedness, to fund planned capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to refining spreads, fertilizer margins and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Based on our current level of operations, we believe our cash flow from operations, available cash and available borrowings under our revolving loan facility and the proceeds we receive from this offering will be adequate to meet our future liquidity needs for at least the next twelve months.
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| | | Payments Due by Period | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| | | | | December 31,
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| | | Total | | 2006 | | 2007 | | 2008 | | 2009 | | 2010 | | Thereafter | | | Total | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | Thereafter | |
| | | (in millions) | | | (in millions) | |
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Contractual Obligations | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Long-term debt(1) | | $ | 508.3 | | | $ | 1.1 | | | $ | 2.3 | | | $ | 2.3 | | | $ | 2.3 | | | $ | 2.2 | | | $ | 498.1 | | | $ | 488.0 | | | $ | 3.7 | | | $ | 4.8 | | | $ | 4.8 | | | $ | 4.7 | | | $ | 4.7 | | | $ | 465.3 | |
| Operating leases(2) | | | 14.6 | | | | 1.7 | | | | 3.8 | | | | 3.7 | | | | 2.9 | | | | 1.6 | | | | 0.9 | | | | 8.9 | | | | 2.8 | | | | 3.3 | | | | 1.7 | | | | 0.9 | | | | 0.2 | | | | — | |
| Unconditional purchase obligations(3) | | | 247.1 | | | | 12.5 | | | | 24.0 | | | | 19.7 | | | | 19.6 | | | | 17.3 | | | | 154.0 | | | | 582.3 | | | | 20.8 | | | | 28.2 | | | | 55.8 | | | | 53.9 | | | | 51.3 | | | | 372.3 | |
| Other long-term liabilities included in the balance sheet(4) | | | 0.3 | | | | 0.3 | | | | — | | | | — | | | | — | | | | — | | | | — | | |
| Environmental liabilities(5) | | | 10.3 | | | | 0.6 | | | | 1.7 | | | | 0.9 | | | | 0.5 | | | | 0.3 | | | | 6.3 | | |
| Funded letter of credit fees(6) | | | 16.6 | | | | 2.1 | | | | 4.1 | | | | 4.2 | | | | 4.1 | | | | 2.1 | | | | — | | |
| Interest payments(7) | | | 338.1 | | | | 26.3 | | | | 52.0 | | | | 51.9 | | | | 51.6 | | | | 51.4 | | | | 104.9 | | |
| Environmental liabilities(4) | | | | 8.8 | | | | 2.6 | | | | 0.7 | | | | 1.6 | | | | 0.3 | | | | 0.3 | | | | 3.3 | |
| Funded letter of credit fees(5) | | | | 10.1 | | | | 3.4 | | | | 4.5 | | | | 2.2 | | | | — | | | | — | | | | — | |
| Interest payments(6) | | | | 142.0 | | | | 20.2 | | | | 26.6 | | | | 26.3 | | | | 26.1 | | | | 25.9 | | | | 16.9 | |
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| Total | | $ | 1,135.3 | | | $ | 44.6 | | | $ | 87.9 | | | $ | 82.7 | | | $ | 81.0 | | | $ | 74.9 | | | $ | 764.2 | | | $ | 1,240.1 | | | $ | 53.5 | | | $ | 68.1 | | | $ | 92.4 | | | $ | 85.9 | | | $ | 82.4 | | | $ | 857.8 | |
Other Commercial Commitments | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Standby letters of credit(8) | | $ | 44.8 | | | $ | 41.6 | | | $ | 3.2 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | |
| Standby letters of credit(7) | | | $ | 37.4 | | | $ | 37.4 | | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
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| (1) | | Long-term debt amortization is based on the contractual terms of our existingCredit Facility. We may be required to amend our Credit Facility in connection with an offering by the Partnership. As of March 31, 2008, $488.0 million was outstanding under our credit facilities.facility. See “Description of Our Indebtedness“— Liquidity and the Cash Flow Swap.Capital Resources — Debt.” |
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| (2) | | We leaseThe nitrogen fertilizer business leases various facilities and equipment, primarily railcars, for our nitrogen fertilizer business under non-cancelable operating leases for various periods. |
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| (3) | | The amount includes (1) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation and (2) commitments under an electric supply agreement with the Citycity of Coffeyville. |
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| (4) | | The amount includes contractual payments due to Farmland related to rejection damages for the electricity contract with the City of Coffeyville. |
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(5) | | Environmental liabilities represents (1) our estimated payments required by federaland/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas.Kansas and (2) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters.”Matters”. |
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(6)(5) | | This amount represents the total of all fees related to the funded letter of credit issued under our First Lien Credit Facility. The funded letter of credit is utilized as credit support for the Cash Flow Swap. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk.”Risk”. |
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(7)(6) | | Interest payments are based on interest rates in effect at June 30, 2006April 1, 2008 and assume contractual amortization payments. |
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(8)(7) | | Standby letters of credit include our obligations under $3.2$5.8 million of letters of credit issued in connection with environmental liabilities $3.2and $31.6 million in letters of credit to secure transportation expenses related to the Transportation Services Agreement with CCPS Transportation, LLC and a $38.5 million letter of credit issued to support certainservices for crude oil purchases. This letter of credit was subsequently cancelled on July 5, 2006.oil. |
In addition to the amounts described in the above table, we owe J. Aron approximately $123.7 million plus accrued interest ($5.8 million as of June 1, 2008) which will be due August 31, 2008 and approximately $54.0 million which will be due on July 8, 2008 for crude oil we settled or will settle with respect to the quarter ending June 30, 2008 based on June 16, 2008 pricing. Also, if the Partnership does not consummate an initial private or public offering by October 24, 2009, the managing general partner of the Partnership can require us to purchase the managing general partner interest at fair market value until the earlier of October 24, 2012 and the closing of the Partnership’s initial offering.
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Our ability to make payments on and to refinance our indebtedness, to repay the amounts owed to J. Aron, to purchase the Partnership’s managing general partner interest if the Partnership’s managing general partner exercises its put right, to fund planned capital expenditures and to satisfy our other capital and commercial commitments will depend on our ability to generate cash flow in the future. This, to a certain extent, is subject to refining spreads, fertilizer margins, receipt of distributions from the Partnership and general economic financial, competitive, legislative, regulatory and other factors that are beyond our control. Our business may not generate sufficient cash flow from operations, and future borrowings may not be available to us under our revolving credit facility (or other credit facilities we may enter into in the future) in an amount sufficient to enable us to pay our indebtedness or to fund our other liquidity needs. We may seek to sell additional assets to fund our liquidity needs but may not be able to do so. We may also need to refinance all or a portion of our indebtedness on or before maturity. Our ability to refinance our indebtedness is also subject to the availability of the credit markets, which in recent periods have been extremely volatile and have experienced significant increases in the cost of financing. We may not be able to refinance any of our indebtedness on commercially reasonable terms or at all.
Off-Balance Sheet Arrangements
We do not have any “off-balance sheet arrangements” as such term is defined within the rules and regulations of the SEC.
Recently Issued Accounting Standards
In December 2004,September 2006, the Financial Accounting Standards Board or FASB,(“FASB”) issued FASBSFAS No. 123 (revised 2004),157,Share-Based PaymentFair Value Measurements, which addresses the accountingestablishes a framework for transactions in which an entity exchanges its equity instruments for goods or services, with a primary focus on transactions in which an entity obtains employee services in share-based payment transactions. This Statement requires us to measure the cost of employee services received in exchange for an award of equity based on the grant-datemeasuring fair value ofin GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the award (with limited exceptions)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)”. Incremental compensation costs arising from subsequent modifications of awards after the grant date must be recognized. Successor elected early adoption of SFAS 123(R)The standard’s provisions for the 233 day period ended December 31, 2005. The effect of the adoption of this standard is described in the footnotes to the Audited Financial Statements.
In December 2004, the FASB issued FASB No. 151,Inventory Costs,financial assets and financial liabilities, which clarifies the accounting for abnormal amounts of idle facility expense, freight, handling costs, and spoilage. Under FASB 151, such items will be recognized as current-period charges. In addition, Statement No. 151 requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities. We adopted SFAS 151became effective January 1, 2006. There was not a significant2008, had no material impact on ourthe Company’s financial position or results of operation.operations. At March 31, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14 to our consolidated financial statements, “Fair Value Measurements”, included elsewhere in this prospectus.
In March 2005,February 2008, the FASB issued FASB InterpretationStaff Position157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in an entity’s financial statements on a recurring basis (at least annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of January 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will not have a material impact on the Company’s financial position or earnings.
In February 2007, the FASB issued SFAS No. 47,159,AccountingThe Fair Value Option for Conditional Asset Retirement ObligationsFinancial Assets and Financial Liabilities, which requires companies. Under this standard, an entity is required to recognize a liability forprovide 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 a legal obligationthose assets and liabilities for which the Company has chosen to perform asset-retirement activities that are conditionaluse fair value on a future event when the amount can be reasonably estimated. FINface of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 47 also clarifies when an entity would have sufficient information to reasonably estimate107,Disclosures about Fair Value of Financial Instruments. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of an asset retirement obligation under SFAS 143. We adopted FIN 47,159 did not impact the Company’s consolidated financial statements as required, forof the year endingquarter ended March 31, 2008.
In December 31, 2005. A net asset retirement obligation2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of $636,000 was includedone or more businesses in other liabilities on the consolidated balance sheet.business combination, establishes the acquisition date as the date that the acquirer achieves control and
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The Emerging Issues Task Force, or EITF, reached a consensus on Issue No.04-13,Accounting for Purchasesrequires the acquirer to recognize the assets acquired, liabilities assumed and Sales of Inventory with the Same Counterparty, and the FASB ratified it on September 28, 2005. This Issue addresses accounting matters that arise when one company both sells inventory to and buys inventory from another company in the same line of business, specifically, when it is appropriate to measure purchases and sales of inventoryany non-controlling interest at their fair value and record them in cost of sales and revenues, and when they should be recordedvalues as an exchange measured at the book value of the item sold.acquisition date. This Issuestatement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR Energy will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141(R) will be limited to any future business combinations for which the acquisition date is to be applied to new arrangements entered into in reporting periods beginningon or after March 15, 2006. There was not a significant impact on our financial position or results of operations as a result of adoption.January 1, 2009.
In June 2006,December 2007, the FASB issued InterpretationSFAS No. 48,160,Accounting for UncertaintyNon-controlling Interests in Income TaxesConsolidated Financial Statements — an interpretationamendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial statements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 109.133 FIN 48 clarifies. This statement will change the accountingdisclosure requirements for uncertainty in income taxes recognized inderivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an enterprise’sentity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial statements in accordance with FASB Statement No. 109,Accounting for Income Taxes, by prescribing a recognition thresholdposition, net earnings, and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. If a tax position is more likely than not to be sustained upon examination, then an enterprise wouldcash flows. The Company will be required to recognize in its financial statements the largest amountadopt this statement as of benefit that is greater than 50% likelyJanuary 1, 2009. The adoption of being realized upon ultimate settlement. FIN No. 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosures and transition. The application of FIN No. 48 is effective for fiscal years beginning after December 15, 2006 andSFAS 161 is not expected to have a material impact on ourthe Company’s consolidated financial position or results of operations.statements.
InThe FASB recently issued final FASB Staff Position (“FSP”)No. APB 14-1Accounting for Convertible Debt Instruments That May 2005,Be Settled in Cash upon Conversion (Including Partial Cash Settlement”. The FSP changes the FASB issuedaccounting treatment for convertible debt instruments that by their stated terms may be settled in cash upon conversion, including partial cash settlements, unless the embedded conversion option is required to be separately accounted for as a derivative under SFAS No. 154,133,Accounting Changesfor Derivative Instruments and Error CorrectionsHedging Activities, which replaces APB Opinion No. 20,Accounting Changes. Under the FSP, cash settled convertible securities will be separated into their debt and SFAS No. 3,Reporting Accounting Changes in Interim Financial Statements. SFAS 154 retained accounting guidance related to changes in estimates, changesequity components. The FSP specifies that issuers of such instruments should separately account for the liability and equity components in a reporting entity and error corrections. However, changesmanner that will reflect the entity’s nonconvertible debt borrowing rate when interest cost is recognized in accounting principles must be accounted for retrospectively by modifying the financial statements of prior periods unless it is impracticable to do so. SFAS 154subsequent periods. The FSP is effective for accounting changes made infinancial statements issued for fiscal years beginning after December 15, 2005.2008, and interim periods within those fiscal years and will require issuers of convertible debt that can be settled in cash to record the additional expense incurred. The adoptionCompany is currently evaluating the FSP in conjunction with its convertible debt offering.
Critical Accounting Policies
We prepare our consolidated financial statements in accordance with GAAP. In order to apply these principles, management must make judgments, assumptions and estimates based on the best available information at the time. Actual results may differ based on the accuracy of the information utilized and subsequent events. Our accounting policies are described in the notes to our audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. Our critical accounting policies, which are described below, could materially affect the amounts recorded in our financial statements.
Receivables from Insurance
As of March 31, 2008, we have incurred total gross costs of approximately of $154.5 million as a result of the 2007 flood and crude oil discharge. During this period, we have maintained insurance
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policies that were issued by a variety of insurers and which covered various risks, such as property damage, interruption of our business, environmental cleanup costs, and potential liability to third parties for bodily injury or property damage. Accordingly, as of March 31, 2008, we have recognized receivables of approximately $107.2 million related to these gross costs incurred that we believe are probable of recovery from the insurance carriers under the terms of the respective policies. As of March 31, 2008, we have collected approximately $21.5 million of these receivables.
We are in the process of submitting our claims to, responding to information requests from, and negotiating with the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. Our property insurers have raised a question as to whether our facilities are principally located in “Zone A,” which is subject to a $10 million insurance limit for flood or “Zone B”’ which is subject to a $300 million insurance limit for flood. We have reached agreement with 32.5% of our property insurers that our facilities are principally located in Zone B. Our remaining property insurers have not, at this time, agreed to this position. In addition, our primary environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup,” which is subject to a $10 million sub-limit, rather than “property damage,” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While we will vigorously contest the primary carrier’s position, we believe that if that position were upheld, our umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. Although each insurer has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses, we are vigorously pursuing our insurance recovery claims. We expect that ultimate recovery will be subject to negotiation and, if negotiation is unsuccessful, litigation.
There is inherent uncertainty regarding the ultimate amount or timing of the recovery of the insurance receivable because of the difficulty in projecting the final resolution of our claims. The difference between what we ultimately receive under our insurance policies compared to the receivable we have recorded could be material to our consolidated financial statements.
Long-Lived Assets
We calculate depreciation and amortization on a straight-line basis over the estimated useful lives of the various classes of depreciable assets. When assets are placed in service, we make estimates of what we believe are their reasonable useful lives. CVR accounts for impairment of long-lived assets in accordance with SFAS 154 didNo. 144,Accounting for the Impairment or Disposal of Long-Lived Assets. In accordance with SFAS 144, CVR reviews long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell. No impairment charges were recognized for any of the periods presented.
Derivative Instruments and Fair Value of Financial Instruments
We use futures contracts, options, and forward contracts primarily to reduce exposure to changes in crude oil prices, finished goods product prices and interest rates to provide economic hedges of inventory positions and anticipated interest payments on long-term debt. Although management considers these derivatives economic hedges, the Cash Flow Swap and our other derivative instruments do not qualify as hedges for hedge accounting purposes under SFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, and accordingly are recorded at fair value in the balance sheet. Changes in the fair value of these derivative instruments are recorded into earnings as a component of other income (expense) in the period of change. The estimated fair values of forward and swap contracts are based on quoted market prices and assumptions for the estimated forward yield curves of related commodities in periods when quoted market prices are unavailable. The Company recorded net
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gains (losses) from derivative instruments of ($323.7) million, $94.5 million, $(282.0) million and $(47.9) million in gain (loss) on derivatives for the fiscal years ended December 31, 2005, 2006 and 2007 and the three months ended March 31, 2008, respectively.
As of March 31, 2008, a $1.00 change in quoted prices for the crack spreads utilized in the Cash Flow Swap would result in a $32.6 million change to the fair value of derivative commodity position and the same change to net income.
Environmental Expenditures
Liabilities related to future remediation of contaminated properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilities are monitored and adjusted as new facts or changes in law or technology occur. Environmental expenditures are capitalized when such costs provide future economic benefits. Changes in laws, regulations or assumptions used in estimating these costs could have a material impact to our financial statements. The amount recorded for environmental obligations (exclusive of estimated obligations associated with the crude oil discharge) at March 31, 2008 totaled $7.7 million, including $2.8 million included in current liabilities. Additionally, at March 31, 2008, $1.0 million was included in current liabilities for estimated future remediation obligations arising from the crude oil discharge. This amount also included estimated obligations to settle third party property damage claims resulting from the crude oil discharge.
Income Taxes
Income tax expense is estimated based on the projected effective tax rate based upon future tax return filings. The amounts anticipated to be reported in those filings may change between the time the financial statements are prepared and the time the tax returns are filed. Further, because tax filings are subject to review by taxing authorities, there is also the risk that a position on a tax return may be challenged by a taxing authority. If the taxing authority is successful in asserting a position different than that taken by us, differences in a tax expense or between current and deferred tax items may arise in future periods. Any of these differences which could have a material impact on our financial position or resultsstatements would be reflected in the financial statements when management considers them probable of operations.occurring and the amount reasonably capable of being estimated.
Valuation allowances reduce deferred tax assets to an amount that will more likely than not be realized. Management’s estimates of the realization of deferred tax assets is based on the information available at the time the financial statements are prepared and may include estimates of future income and other assumptions that are inherently uncertain. No valuation allowance is currently recorded, as we expect to realize our deferred tax assets.
Off-Balance Sheet ArrangementsConsolidation of Variable Interest Entities
In accordance with FIN No. 46R management has reviewed the terms associated with our interests in the Partnership based upon the partnership agreement. Management has determined that the Partnership is treated as a variable interest entity and as such has evaluated the criteria under FIN 46R to determine that we are the primary beneficiary of the Partnership. FIN 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. FIN 46R defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and where there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. As the primary beneficiary, we absorb the majority of the expected lossesand/or receive a majority of the expected residual returns of the VIE’s activities.
We do not have any “off-balance sheet arrangements”will need to reassess our investment in the Partnership from time to time to determine whether we are the primary beneficiary. If in the future we conclude that we are no longer the primary beneficiary, we will be required to deconsolidate the activities of the Partnership on a going forward basis. The interest would then be recorded using the equity method and the Partnership gross
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revenues, expenses, net income, assets and liabilities as such term is defined within the rules and regulations of the SEC.would not be included in our consolidated financial statements.
Quantitative and Qualitative Disclosures About Market Risk
The risk inherent in our market risk sensitive instruments and positions is the potential loss from adverse changes in commodity prices and interest rates. None of our market risk sensitive instruments are held for trading.
Commodity Price Risk
We,Our petroleum business, as a manufacturer of refined petroleum products, and the nitrogen fertilizer business, as a manufacturer of nitrogen fertilizer products, all of which are “naturally long” processing capacity.commodities, has exposure to market pricing for products sold in the future. In order to realize value from thisour processing capacity, a positive spread between the cost of raw materials and the value of finished products must be achieved (i.e., gross margin or crack spread). The physical commodities that comprise our raw materials and finished goods are typically bought and sold at a spot or index price that can be highly variable.
We use a crude oil purchasing intermediary which allows us to take title and price of our crude oil at the refinery, as opposed to the crude origination point, reducing our risk associated with volatile commodity prices by shortening the commodity conversion cycle time. The commodity conversion cycle time refers to the time elapsed between raw material acquisition and the sale of finished goods.
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In addition, we seek to reduce the variability of commodity price exposure by engaging in hedging strategies and transactions that will serve to protect gross margins as forecasted in the annual operating plan. Accordingly, we use financial derivatives to economically hedge future cash flows (i.e., gross margin or crack spreads) and product inventories. With regard to our hedging activities, we may enter into, or have entered into, derivative instruments which serve to:
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| | • | lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows; and |
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| | • | hedge the value of inventories in excess of minimum required inventories.inventories; and |
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| • | hedge the value of inventories held with respect to our rack marketing business. |
Further, we intend to engage only in risk mitigating activities directly related to our business.
Basis Risk. The effectiveness of our derivative strategies is dependent upon the correlation of the price index utilized for the hedging activity and the cash or spot price of the physical commodity for which price risk is being mitigated. Basis risk is a term we use to define that relationship. Basis risk can exist due to several factors including time or location differences between the derivative instrument and the underlying physical commodity. Our selection of the appropriate index to utilize in a hedging strategy is a prime consideration in our basis risk exposure.
Examples of our basis risk exposure are as follows:
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| | • | Time Basis — In entering into over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlingunderlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periodperiods then weighted average physical prices will be weighted differently than the swap price as the result of timing. |
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| | • | Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area. |
Price and Basis Risk Management Activities. OurThe most prevalent risk management activitysignificant derivative position we have is to sell forward the crack spread when opportunities exist to lock in a margin sufficient to meet our cash obligations or our operating plan. Selling forward derivative contractsCash Flow Swap. The Cash Flow Swap, for which the underlying commodity is the crack spread, enablesenabled us to lock in a margin on the spread between the price of crude oil and price of refined products. The commodity derivative contracts areproducts at the execution date of the agreement. We may look for opportunities to reduce the
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effective position of the Cash Flow Swap by buying either exchange-traded contracts in the form of futures contracts orover-the-counter contracts in the form of commodity price swaps. In addition, we may sell forward crack spreads when opportunities exist to lock in a margin.
In the event our inventories exceed our target base level of inventories, we may enter into commodity derivative contracts to manage our price exposure to our inventory positions that are in excess of our base level. Excess inventories are typically the result of plant operations such as a turnaround or other plant maintenance. The commodity derivative contracts are either exchange-traded contracts in the form of futures contracts orover-the-counter contracts in the form of commodity price swaps.
To reduce the basis risk between the price of products for Group 3 and that of the NYMEX associated with selling forward derivative contracts for NYMEX crack spreads, we may enter into basis swap positions to lock the price difference. If the difference between the price of products on the NYMEX and Group 3 (or some other price benchmark as we may deem appropriate) is different than the value contracted in the swap, then we will receive from or owe to the counterparty the difference on each unit of product contracted in the swap, thereby completing the locking of our margin. An example of our use of a basis swap is in the winter heating oil season. The risk associated with not hedging the basis when using NYMEX forward contracts to fix future margins is if the crack spread increases based on prices traded on NYMEX while Group 3 pricing remains flat or decreases then we
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would be in a position to lose money on the derivative position while not earning an offsetting additional margin on the physical position based on the Group 3 pricing.
At June 30, 2006, we had the following open commodity derivative contracts whose unrealized gains and losses are included in other (income) expense in the consolidated statements of operations:
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| • | Successor’s Petroleum Segment holds commodity derivative contracts in the form of three swap agreements for the period from July 1, 2005 to June 30, 2010 with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of Immediate Predecessor and required under the terms of our long-term debt agreements. These agreements were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The notional quantities on the date of execution were 100,911,000 barrels of crude oil; 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil. In June 2006, a subsequent swap was entered into with J. Aron to effectively reduce our unleaded notional quantity and increase our heating oil notional quantity by 229,671,750 over the period July 1, 2007 to June 30, 2010. The swap agreements were executed at the prevailing market rate at the time of execution and management believed the swap agreements would provide an economic hedge on future transactions. At June 30, 2006 the net notional open amounts under these swap agreements were 77,186,000 barrels of crude oil, 1,620,906 gallons of heating oil and 1,620,906 gallons of unleaded gasoline. The purpose of these contracts is to economically hedge 38,593,000 barrels of heating oil crack spreads, the price spread between crude oil and heating oil and 38,593,000 barrels of unleaded gas crack spreads, the price spread between crude oil and unleaded gasoline. These open contracts had total unrealized net loss at June 30, 2006 of approximately $334.3 million. |
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| • | Successor’s Petroleum Segment holds another commodity derivative contract for the period from July 1, 2006 to September 30, 2006 with J. Aron. The notional quantity was 230,000 barrels of unleaded gasoline. The swap agreement was executed to economically hedge location basis between the NYMEX Unleaded price and the Platts U.S. Gulf Coast Unleaded price. This open contract had an unrealized gain of $0.2 million at June 30, 2006. |
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| • | Successor’s Petroleum Segment also holds various NYMEX positions through ABN Amro. At June 30, 2006, we were short 300 crude contract, 45 heating oil contracts and 135 unleaded contracts reflecting an unrealized loss of $1.3 million on that date. |
As of June 30, 2006,March 31, 2008, a $1.00 change in quoted futures price for the crack spreads described in the first bullet point would result in a $77.2$36.2 million change to the fair value of the derivative commodity position and the same change in net income.
Interest Rate Risk
As of June 30, 2006,March 31, 2008, all of our $508.3$488.0 million of outstanding term debt was at floating rates. An increase of 1.0% in the LIBOR rate would result in an increase in our interest expense of approximately $5.2$4.9 million per year.
In an effort to mitigate the interest rate risk highlighted above and as required under the currentour then-existing first and second lien credit agreements, we entered into several interest rate swap agreements in 2005. These swap agreements were entered into with counterparties that we believe to be creditworthy. Under the swap agreements, we pay fixed rates and receive floating rates based on the
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three-month LIBOR rates, with payments calculated on the notional amounts set forforth in the table below. The swap isinterest rate swaps are settled quarterly and marked to market at each reporting date.
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| | | Effective
| | | MaturityTermination
| | | Fixed
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Notional Amount | | Date | | | Date | | | Rate | |
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$375.0 million | | | 6/30/06 | | | | 3/30/07 | | | | 4.038% | |
$325.0 million | | | 3/30/07 | | | | 6/29/07 | | | | 4.038% | |
$325.0 million | | | 6/29/07 | | | | 3/31/08 | | | | 4.195% | |
| $250.0 million | | | 3/31/08March 31, 2008 | | | | 3/31/09March 30, 2009 | | | | 4.195%4.195 | % |
| $180.0 million | | | 3/31/09March 31, 2009 | | | | 3/31/10March 30, 2010 | | | | 4.195%4.195 | % |
| $110.0 million | | | 3/31/10March 31, 2010 | | | | 6/30/10June 29, 2010 | | | | 4.195%4.195 | % |
We have determined that these derivative instrumentsinterest rate swaps do not qualify as hedges for hedge accounting purposes. Therefore, changes in the fair value of these derivative instrumentsinterest rate swaps are included in income in the period of change. Net realized and unrealized gains or losses are reflected in the gain (loss) for derivative activities at the end of each period. For the six month period ending June 30, 2006,year ended December 31, 2007, we had $7.4$4.8 million of realized and unrealized gainslosses on these interest rate swaps. For the three months ended March 31, 2008 and March 31, 2007, we had $5.6 million and $0.6 million of realized and unrealized losses on these interest rate swaps, respectively.
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INDUSTRY OVERVIEW
Oil Refining Industry
Oil refining is the process of separating the wide spectrum of hydrocarbons present in crude oil, and in certain processes, modifying the constituent molecular structures, for the purpose of converting them into marketable finished, or refined, petroleum products optimized for specific end uses. Refining is primarily a margin-based business where both the feedstocks (the petroleum products such as crude oil or natural gas liquids that are processed and blended into refined products) and the refined finished products are commodities. It is important for a refinery to maintain high throughput rates (the volume per day processed through the refinery) and capacity utilization given the substantial fixed component in the total operating costs. There are also material variable costs associated with the fuel and by-product components that become increasingly expensive as crude prices increase. The refiner’s goal is to achieve highest profitability by maximizing the yields of high value finished products and by minimizing feedstock and operating costs.
According to the Energy Information Administration, or the EIA, as of January 1, 2006,2007, there were 142145 oil refineries operating in the United States, with the 15 smallest each having a capacity of 11,00012,500 bpd or less, and the 10 largest having capacities ranging from 306,000 to 562,500 bpd. Refiners typically are structured as part of a fully or partially integrated oil company, or as an independent entity, such as our Company.
Refining Margins
A variety of so called “crack spread” indicators are used to track the profitability of the refining industry. Among those of most relevance to our refinery are (1) the gasgasoline crack spread, (2) the heat crack spread, and (3) the2-1-1 crack spread. The gasgasoline crack spread is the simple difference in per barrel value ofbetween reformulated gasoline (gasoline with compounds or properties which meet the requirements of the reformulated gasoline regulations) in New York Harbor as traded on the New York Mercantile Exchange, or NYMEX, and the NYMEX prompt price of West Texas Intermediate, or WTI, crude oil on any given day. This provides a measure of the profitability when producing gasoline. The heat crack spread is the similar measure of the price of Number 2 heating oil in New York Harbor as traded on the NYMEX, relative to the value of WTI crude which provides a measure of the profitability of producing diesel and heating oil.distillates. The2-1-1 crack spread is a composite spread that assumes for simplification and comparability purposes that for every two barrels of WTI consumed, a refinery produces one barrel of gasoline and one barrel of heating oil; the spread is based on the NYMEX price and delivery of gasoline and heating oil in New York Harbor. The 2-1-1 crack spread provides a measure of the general profitability of a medium high complexity refinery on the day that the spread is computed. The ability of a crack spread to measure profitability is affected by the absolute crude price.
Our refinery uses a consumed2-1-1 crack spread to measure its specific daily performance in the market. The consumed 2-1-1 crack spread assumes the same relative production of gasoline and heating oil from crude, so like the NYMEX based2-1-1 crack spread, it has an inherent inaccuracy because the refinery does not produce exactly two barrels of high valued products for each two barrels of crude oil, and the relative proportions of gasoline to heating oil will vary somewhat from the 1:1 relationship. However, the consumed2-1-1 crack spread is an economically more accurate measure of performance than the NYMEX based2-1-1 crack spread since the crude price used represents the price of our actual charged crude slate and is based on the actual sale values in our marketing region, rather than on New York Harbor NYMEX numbers.Average 2-1-1 crack spreads vary from region to region depending on the supply and demand balances of crude oils and refined products and can vary seasonally and from year to year reflecting more macroeconomic factors.
Although refining margins, the difference between the per barrel prices for refined products and the cost of crude oil, can be volatile during short term periods of time due to seasonality of demand,
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refinery outages, extreme weather conditions and fluctuations in levels of refined product held in storage, longer-term averages have steadily increased over the last 10 years as a result of the improving fundamentals for the refining industry. For example, the NYMEX based2-1-1 crack spread
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averaged $3.88 per barrel from 1994 through 1998 compared to $5.83$11.02 per barrel from 20002004 to 2004.March 31, 2008. The following chart shows a rolling average of the NYMEX based 2-1-1 crack spread from 1994 through June 2006:March 31, 2008:
Source: Platts
There are a number of reasons high crude oil costs have a negative impact on our earnings. Less than 100% of the crude oil we purchase can actually be turned into profitable transportation fuels; the conversion process also produces less valuable byproducts such as pet coke, slurry and sulfur. These byproducts are less valuable than transportation fuels, and their sales prices have not increased in proportion to crude oil prices. Therefore, as the price on crude oil increases our loss on byproduct sales increases, which results in a reduction in earnings. Also, as discussed previously, as crack spreads increase in absolute terms in connection with higher crude prices, the Company realizes increasing losses on the Cash Flow Swap.
Refining Market Trends
The supply and demand fundamentals of the domestic refining industry have improved since the 1990s and are expected to remain favorable as the growth in demand for refined products continues to exceed increases in refining capacity. Over the next two decades, the EIA projects that U.S. demand for refined products will grow at an average of 1.5%0.8% per year compared to total domestic refining capacity growth of only 1.3%0.3% per year. Approximately 83.3%Substantially all of the projected demand growth is expected to come from the increased consumption of light refined products (including gasoline, diesel, jet fuel and liquefied petroleum gas), which are more difficult and costly to produce than heavy refined products (including asphalt and carbon black oil).transportation fuels.
High capital costs, historical excess capacity and environmental regulatory requirements have limited the construction of new refineries in the United States over the past 30 years. According to the EIA, domestic refining capacity decreased approximately 7%6% between January 1981 and January 20062007 from 18.6 million bpd to 17.317.4 million bpd, as more than 175 generally small and unsophisticated refineries that were unable to process heavy crude into a marketable product mix have been shut down, and no new major refinery has been built in the United States. The implementation of the federal Tier II low sulfur fuel regulations is expected to further reduce existing refining capacity.
As reflected within the U.S. Days Forward Supply and the U.S. Mogas Inventory statistics provided by the EIA, the gasoline available for consumption in the United States has declined year after year. This trend is in most part attributable to a steady increase in demand that has not been matched by an equal increase in supply. Although existing refiners are improving their utilization rates, the total number of refiners has declined. As a result, the U.S. has been dependent on imported fuels to meet domestic
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demand while the global supply which has historically been available for importation has been subject to increasing worldwide demand. With this reduction in days of available supply, we believe the U.S. will occasionally experience periods of little or no supply of gasoline in various markets as the supply and distribution system continues to strain to match available inventory with consumer demand.
In order to meet the increasing demands of the market, U.S. refineries have pursued efficiency measures to improve existing production levels. These efficiency measures and other initiatives, generally known as capacity creep, have raised productive capacity of existing refineries by approximately 1% per year since 1993. According to the EIA, between 1981 and 2004, refinery utilization increased from 69% to 93%. Over the next 2025 years, the EIA projects that utilization will remain high relative to historic levels, ranging from 92%90% to 95% of design capacity.
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Source: EIA
The price discounts available to refiners of heavy sour crude oil have widened as many refiners have turned to sweeter and lighter crude oils to meet lower sulfur fuel specifications, which has resulted in increasing the surplus of sour and heavy crude oils. As the global economy has improved, worldwide crude oil demand has increased, and OPEC and other producers have tended to incrementally produce more of the sour or heavier crude oil varieties. We believe that the combination of increasing worldwide supplies of lower cost sour and heavy crude oils and increasing demand for sweet and light crude oils will provide a cost advantage to refineries with configurations that are able to process sour crude oils.
We expect refined products that meet new and evolving fuel specifications will account for an increasing share of total fuel demand, which will benefit refiners who are able to efficiently produce these fuels. As part of the Clean Air Act, major metropolitan areas in the United States with air pollution problems must require the sale and use of reformulated gasoline meeting certain environmental standards in their jurisdictions. Boutique fuels, such as low vapor pressure Kansas City gasoline, enable refineries capable of producing such refined products to achieve higher margins.
Due to the ongoing supply and demand imbalance, the United States continues to be a net refined products importer. Imports, largely from northwest Europe and Asia, accounted for almost 14% over 12%
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of total U.S. consumption in 2004.2005. The level of imports generally increases during periods when refined product prices in the United States are materially higher than in Europe and Asia.
Based on the strong fundamentals for the global refining industry, capital investments for refinery expansions and new refineries in international markets have increased during the recent year. However, the competitive threat faced by domestic refiners is limited by U.S. fuel specifications and increasing foreign demand for refined products, particularly for light transportation fuels.
Certain regional markets in the United States, such as the Coffeyville supply area,mid-continent region where our refinery is located, do not have the necessary refining capacity to produce a sufficient amount of refined products to meet area demand and therefore rely on pipelines and other modes of transportation for incremental supply from other regions of the United States and globally. The shortage of refining capacity is a factor that results in local refiners serving these markets earning generally higher margins on their product sales than those who have to transport their products to this region over long distances.
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Notwithstanding the trends described above, the refining industry is cyclical and volatile and has undergone downturns in the past. See “Risk Factors.”
Refinery Locations
A refinery’s location can have an important impact on its refining margins because location can influence access to feedstocks and efficient distribution. There are five regions in the United States, the Petroleum Administration for Defense Districts (PADDs), that have historically experienced varying levels of refining profitability due to regional market conditions. Refiners located in the U.S. Gulf Coast region operate in a highly competitive market due to the fact that this region (PADD III) accounts for approximately 37%38% of the total number of U.S. refineries and approximately 48% of the country’s refining capacity. PADD I represents the East Coast, PADD IV the Rocky Mountains and PADD V is the West Coast.
Coffeyville operates in the Midwest (PADD II) region of the US. In 2005,2007, demand for gasoline and distillates (primarily diesel fuels, kerosene and jet fuel) exceeded refining production in the Coffeyville supply area by approximately 24%mid-continent region, which createscreated a need to import a significant portion of the region’s requirement for petroleum products from the U.S. Gulf Coast and other regions. The deficit of local refining capacity benefits local refined product pricing and could generally lead to higher margins for local refiners such as our company.
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Nitrogen Fertilizer Industry
Plant Nutrition and Nitrogen Fertilizers
Commercially produced nitrogen fertilizers give plants theprovide primary nutrients neededfor plant growth in a form they canthat is readily absorb and use.absorbable. Nitrogen is an essential element for plant growth. Absorbed by plants in larger amounts than other nutrients, nitrogen makes plants greengrowth and healthyvigor and is the nutrient most responsibleimportant element for increasing yields in crop plants. Although plants will absorb nitrogen fromNitrogen and other plant nutrients are found naturally in organic matter and soil materials thisbut are depleted by intensive crop production and harvesting. Replenishing nitrogen through application of commercial fertilizers is usually not sufficient to satisfy the demandsmost widely used way of sustaining or increasing crop plants. The supply of nutrients must, accordingly, be supplemented with fertilizers to meet the requirements of
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crops during periodsyields. Two primary sources of plant growth, to replenish nutrients removed from the soil through crop harvesting and to provide those nutrients that are not already available in appropriate amounts in the soil. The two most important sources of nutrients are manufactured or mineral fertilizers and organic manures. Farmers determine the types, quantitiesquantity and proportions of fertilizer to apply to their fields depending on, among other factors, theupon crop type, soil and weather conditions, regional farming practices, and fertilizer and crop prices.prices and other factors.
Nitrogen, which typically accounts for approximately 60% of worldwide fertilizer consumption in any planting season, is an essential element for most organic compounds in plants as it promotes protein formation and is a major component of chlorophyll, which helps to promote green healthy growth and high yields. There are no substitutes for nitrogen fertilizers in the cultivation of high-yield crops.crops such as corn, which on average requires100-160 pounds of nitrogen for each acre of plantings. The four principal nitrogen based fertilizer products are:
Ammonia. Ammonia is used in limited quantities as a direct application fertilizer, and is primarily used as a building block for other nitrogen products, including intermediate products for industrial applications and finished fertilizer products. Ammonia, consisting of 82% nitrogen, is stored either as a refrigerated liquid at minus 27 degrees, or under pressure if not refrigerated. It is gaseous at ambient temperatures and is injected into the soil as a gas. The direct application of ammonia requires farmers to make a considerable investment in pressurized storage tanks and injection machinery, and can take place only under a narrow range of ambient conditions.
Urea. Urea is formed by reacting ammonia with carbon dioxide, or CO2, at high pressure. From the warm urea liquid produced in the first, wet stage of the process, the finished product is mostly produced as a coated, granular solid containing 46% nitrogen and suitable for use in bulk fertilizer blends containing the other two principal fertilizer nutrients, phosphate and potash. We do not produce merchant urea.
Ammonium Nitrate. Ammonium nitrate is another dry, granular form of nitrogen based fertilizer. It is produced by converting ammonia to nitric acid in the presence of a platinum catalyst reaction, then further reacting the nitric acid with additional volumes of ammonia to form ammonium nitrate. We do not produce this product.
Urea Ammonium Nitrate Solution (UAN).Solution. Urea can be combined with ammonium nitrate solution to make liquid nitrogen fertilizer (urea ammonium nitrate or UAN). These solutions contain 32% nitrogen and are easy to store and transport and provide the farmer with the most flexibility in tailoring fertilizer, pesticide and fungicide applications.transport.
We currently produceIn 2007, we produced approximately 430,000326,662 tons per year of ammonia, of which approximately two-thirds is72% was upgraded into approximately 720,000576,888 tons per year of UAN.
Ammonia Production Technology — Advantages of Pet Coke Gasification
Ammonia is produced by reacting gaseous nitrogen with hydrogen at high pressure and temperature in the presence of a catalyst. Traditionally, nearly all hydrogen produced for the manufacture of nitrogen based fertilizers iswas produced by reforming natural gas at a high temperature and pressure in the presence of water and a catalyst. This process consumes a significant amount of natural gas and is believed to become unprofitable as thea result production costs increase significantly as natural gas input costs increase above $8.50-$10.00/per million Btu.prices increase.
Alternatively, hydrogen for ammonia can also be produced by gasifying pet coke. ThisPet coke is a coal-like substance that is produced during the petroleum refining process. The pet coke gasification process, which isthe nitrogen fertilizer business commercially employedemploys at our nitrogenits fertilizer plant, the only such plant in North America, takes advantage of the large cost differential between pet coke and
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natural gas in current markets. OurThe nitrogen fertilizer plant’s pet coke gasification process allows usit to use less thanapproximately 1% of the natural gas relative to other nitrogen based fertilizer facilities that are heavily dependent upon natural gas and are thus heavily impacted by natural gas price swings. WeThe nitrogen fertilizer business also benefitbenefits from the ready availability of pet coke supply from our refinery plant. Pet coke is a refinery by-product which if not used in the fertilizer plant would otherwise be sold as fuel, generating less value to the combined company.
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Fertilizer Consumption Trends
Global demand for fertilizers typically grows at predictable rates and tends to correspond to growth in grain production.production and pricing. Global fertilizer demand is driven in the long-term primarily by population growth, increases in disposable income and associated improvements in diet. Short-term demand depends on world economic growth rates and factors creating temporary imbalances in supply and demand. These factors include weather patterns, the level of world grain stocks relative to consumption, agricultural commodity prices, energy prices, crop mix, fertilizer application rates, farm income and temporary disruptions in fertilizer trade from government intervention, such as changes in the buying patterns of large countries like China or India. According to the International Fertilizer Industry Association, or IFA, from 1960 to 2005, global fertilizer demand has grown 3.7% annually and global nitrogen demand has grown at a faster rate of 4.8% annually. According to the IFA, during that45-year period, North American fertilizer demand has grown 2.4% annually with North American nitrogen fertilizer demand growing at a faster rate of 3.3% annually.
InAccording to the United States Department of Agriculture, or USDA, U.S. farmers planted 92.9 million acres of corn in 2007, exceeding the 2006 planted area by 19 percent. This increase was driven in large part by ethanol demand. The actual planted acreage is the highest on record since 1944, when farmers planted 95.5 million acres of corn. Farmers in nearly all states increased their planted corn acreage in 2007. State records were established in Illinois, Indiana, Minnesota and North Dakota, while Iowa led all states in total planted corn acres. A net effect of these additional planted acres was to increase the demand for nitrogen fertilizers by over one million tons. This equates to an annual increase of 3.3 million tons of UAN, or approximately 5 times the nitrogen fertilizer plant’s total UAN production. The USDA is forecasting as of March 2008 that total U.S. planted corn acreage in 2008 will decline to 86 million acres. Despite this decrease, Blue Johnson estimates that nitrogen fertilizer consumption by farm users in 2008 will increase by one million tons due to the need to correct for under fertilization of corn in 2007, a report entitled “Fertilizer Requirements in 2015 and 2030” prepared in 2000, the FAO projected anforecasted increase in major worldtotal planted wheat acreage and very strong crop production from 1995/97 to 2030prices. This estimated increase in nitrogen usage translates into an annual increase of 3.3 million tons of UAN, or approximately 76%. The annual growth rate forfive times the nitrogen fertilizer consumption through 2030 is projected by the FAO to be between 0.7% and 1.3% per year. This forecast assumes a slow down in the growth of the world’s population and crop production, and an improvement in fertilizer use efficiency.business’ total 2008 estimated UAN production.
The Farm Belt Nitrogen Market
AllThe majority of ourthe nitrogen fertilizer business’ product shipments target freight advantaged destinations located in the U.S. farm belt. The farm belt refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. Because shipping ammonia requires refrigerated or pressured containers and UAN is more than 65% water, transportation cost is substantial for ammonia and UAN producers.producers and importers. As a result, locally based fertilizer producers, such as our company,the nitrogen fertilizer business, enjoy a distribution cost advantage over U.S. Gulf Coast ammonia and UAN producers and importers. Southern Plains spot ammonia and Corn Beltcorn belt UAN 32 prices averaged $272/$337/ton and $157/$201/ton, respectively, for the 2002
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2003 through 2005 period. The distribution cost for a U.S. Gulf Coast importer represents approximately one quarter percent of both ammonia’s and UAN’s price.2007 period, based on data provided by Blue Johnson. The volumes of ammonia and UAN sold into thecertain farm belt markets in 2007 are set forth in the table below:
Current United States2005-2007 Average U.S. Ammonia and UAN Demand in Selected Mid-continent Areas
| | | | | | | | | | | | | | | | | |
| | | Ammonia
| | UAN
| | | Ammonia
| | UAN 32
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State | | Quantity | | Quantity | | | Quantity | | Quantity(1) | |
| | | | (thousand tons
| |
| | | (thousand tons per year) | | | per year) | |
| |
| Texas | | | 2,285 | | | | 840 | | | | 2,125 | | | | 850 | |
| Oklahoma | | | 95 | | | | 240 | | | | 95 | | | | 200 | |
| Kansas | | | 370 | | | | 635 | | | | 395 | | | | 690 | |
| Missouri | | | 315 | | | | 235 | | | | 325 | | | | 230 | |
| Iowa | | | 625 | | | | 840 | | | | 710 | | | | 900 | |
| Nebraska | | | 450 | | | | 1100 | | | | 425 | | | | 1,150 | |
| Minnesota | | | 360 | | | | 210 | | | | 310 | | | | 200 | |
Source: Blue Johnson & Associates Inc.
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| (1) | | UAN 32, which consists of 45% ammonium nitrate, 35% urea and 20% water, contains 32% nitrogen by weight and is the most common grade of UAN sold in the United States.Source: Blue Johnson |
Fertilizer Pricing Trends
The nitrogen fertilizer industry is cyclical and relatively volatile, reflecting the commodity nature of ammonia and the major finished fertilizer products (e.g., urea). Although domestic industrywideindustry-wide sales volumes of nitrogen based fertilizers vary little from one fertilizer season to the next due to the need to apply nitrogen every year to maintain crop yields, in the normal course of business industry participants are exposed to fluctuations in supply and demand, which can have significant effects on prices across all participants’ commodity business areas and products and, in turn, their operating
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results and profitability. Changes in supply can result from capacity additions or reductions and from changes in inventory levels. Demand for fertilizer products is dependent on demand for crop nutrients by the global agricultural industry, which, in turn, depends on, among other things, weather conditions in particular geographical regions. Periods of high demand, high capacity utilization and increasing operating margins tend to result in new plant investment, higher crop pricing and increased production until supply exceeds demand, followed by periods of declining prices and declining capacity utilization, until the cycle is repeated. Due to dependence of the prevalent nitrogen fertilizer technology on natural gas, the marginal cost and pricing of fertilizer products also tend to exhibit positive correlation with the price of natural gas.
Strong industry fundamentals have led current demand for nitrogen fertilizers to all time highs. US corn inventories at the end of the2008-2009 fertilizer year are projected to be at 673 million bushels, which is the lowest level since1995-1996. Corn prices are at record high levels, and corn planting for2008-2009 is projected to be higher than2007-2008. Nitrogen fertilizer prices are at record high levels due to increased demand and increasing worldwide natural gas prices. In addition, nitrogen fertilizer prices have been decoupled from their historical correlation with natural gas prices in recent years and increased substantially more than natural gas prices in 2007 and 2008 (based on data provided by Blue Johnson). The quest for healthier lives and better diets in developing countries is a primary driving factor behind the increased global demand for fertilizers. As of June 16, 2008, our order book for UAN is 367,825 tons at an average netback price of $326.56 per ton and 34,898 tons of ammonia at an average netback price of $620.61.
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The historical average annual U.S. corn belt ammonia and UAN 32 spot prices as well as natural gas and crude oil prices are detailed in the table below.
| | | | | | | | | | | | | | |
| | | Natural Gas
| | WTI
| | Ammonia
| | | | | | | | | | | | | | | | | |
Year | | ($/million btu) | | ($/bbl) | | ($/ton) | | | Natural Gas | | WTI | | Ammonia | | UAN 32 | |
| | | | ($/million btu) | | ($/bbl) | | ($/ton) | | ($/ton) | |
| |
| 1990 | | | 1.78 | | | | 24.53 | | | | 125 | | | | 1.78 | | | | 24.53 | | | | 125 | | | | 90 | |
| 1991 | | | 1.53 | | | | 21.55 | | | | 130 | | | | 1.53 | | | | 21.55 | | | | 130 | | | | 97 | |
| 1992 | | | 1.73 | | | | 20.57 | | | | 134 | | | | 1.73 | | | | 20.57 | | | | 134 | | | | 95 | |
| 1993 | | | 2.11 | | | | 18.43 | | | | 139 | | | | 2.11 | | | | 18.43 | | | | 139 | | | | 102 | |
| 1994 | | | 1.94 | | | | 17.16 | | | | 197 | | | | 1.94 | | | | 17.16 | | | | 197 | | | | 108 | |
| 1995 | | | 1.69 | | | | 18.38 | | | | 238 | | | | 1.69 | | | | 18.38 | | | | 238 | | | | 132 | |
| 1996 | | | 2.50 | | | | 22.01 | | | | 217 | | | | 2.50 | | | | 22.01 | | | | 217 | | | | 129 | |
| 1997 | | | 2.48 | | | | 20.59 | | | | 220 | | | | 2.48 | | | | 20.59 | | | | 220 | | | | 116 | |
| 1998 | | | 2.16 | | | | 14.43 | | | | 162 | | | | 2.16 | | | | 14.43 | | | | 162 | | | | 96 | |
| 1999 | | | 2.32 | | | | 19.26 | | | | 145 | | | | 2.32 | | | | 19.26 | | | | 145 | | | | 86 | |
| 2000 | | | 4.32 | | | | 30.28 | | | | 208 | | | | 4.32 | | | | 30.28 | | | | 208 | | | | 115 | |
| 2001 | | | 4.06 | | | | 25.92 | | | | 262 | | | | 4.04 | | | | 25.92 | | | | 262 | | | | 144 | |
| 2002 | | | 3.39 | | | | 26.19 | | | | 191 | | | | 3.37 | | | | 26.19 | | | | 191 | | | | 108 | |
| 2003 | | | 5.49 | | | | 31.03 | | | | 292 | | | | 5.49 | | | | 31.03 | | | | 292 | | | | 141 | |
| 2004 | | | 5.90 | | | | 41.47 | | | | 326 | | | | 6.18 | | | | 41.47 | | | | 326 | | | | 170 | |
| 2005 | | | 8.92 | | | | 56.58 | | | | 394 | | | | 9.02 | | | | 56.58 | | | | 394 | | | | 210 | |
| 2006 (through June 30) | | | 7.09 | | | | 66.92 | | | | 400 | | |
| 2006 | | | | 6.98 | | | | 66.09 | | | | 379 | | | | 196 | |
| 2007 | | | | 7.12 | | | | 72.36 | | | | 469 | | | | 290 | |
| 2008 (through May) | | | | 9.77 | | | | 106.54 | | | | 681 | | | | 377 | |
Source: Bloomberg (natural gas and WTI) and Blue Johnson & Associates, Inc.(ammonia and UAN)
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BUSINESS
We are an independent refiner and marketer of high value transportation fuels and, through a premierlimited partnership, a producer of ammonia and UAN fertilizers. We are one of only seven petroleum refiners and marketers in within the Coffeyville supply areamid-continent region (Kansas, Oklahoma, Missouri, Nebraska and Iowa). The nitrogen fertilizer business is the only operation in North America that uses a coke gasification process, and at current natural gas and pet coke prices, the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America.
Our petroleum business includes a 108,000115,000 bpd complex full coking sourmedium-sour crude refinery in Coffeyville, Kansas. In addition, our supporting businesses include (1) a crude oil gathering system serving central Kansas, and northern Oklahoma and southwestern Nebraska, (2) storage and terminal facilities for asphalt and refined fuels in Phillipsburg, Kansas, (3) a 145,000 bpd pipeline system that transports crude oil to our refinery and (3)associated crude oil storage tanks with a capacity of approximately 1.2 million barrels and (4) a rack marketing division supplying product through tanker trucks directly to customers located in close geographic proximity to Coffeyville and Phillipsburg and to customers at throughput terminals on Magellan Midstream Partners L.P.’s refined products distribution systems. In addition to rack sales (sales which are made at terminals into third party tanker trucks), we make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise Products Partners L.P. and Valero.NuStar Energy L.P. Our refinery is situated approximately 80100 miles from Cushing, Oklahoma, one of the largest crude oil trading and storage hubhubs 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.
OurThe nitrogen fertilizer business, consists of a nitrogen fertilizer manufacturing facility comprised of (1) a 1,225ton-per-day ammonia unit, (2) a 2,025ton-per-day UAN unit and (3) an 84 million standard cubic foot per day gasifier complex. We are currently enjoying unprecedented fertilizer prices which have contributed favorably to our earnings. The nitrogen fertilizer business is the only operation in North America that utilizes a coke gasification process to produce ammonia. A majorityammonia (based on data provided by Blue Johnson). In 2007, approximately 72% of the ammonia produced by ourthe fertilizer plant iswas further upgraded to UAN fertilizer.fertilizer (a solution of urea, ammonium nitrate and water used as a fertilizer). By using pet coke (a coal-like substance that is produced during the refining process) instead of natural gas as a primary raw material, we areat current natural gas and pet coke prices the nitrogen fertilizer business is the lowest cost producer and marketer of ammonia and UAN fertilizers in North America. Furthermore, approximately 80%on average during the last four years, over 75% of the pet coke utilized by us isthe fertilizer plant was produced and supplied to the fertilizer plant as a by-product of our refinery. As such, we benefitthe nitrogen fertilizer business benefits from high natural gas prices, as fertilizer prices generally increase with natural gas prices, while our input costs remain substantially the same.without a directly related change in cost (because pet coke rather than natural gas is used as a primary raw material).
We have two business segments: petroleum and nitrogen fertilizer. ForWe generated combined net sales of $2.4 billion, $3.0 billion and $3.0 billion and operating income of $270.8 million, $281.6 million and $186.6 million for the fiscal years ended December 31, 20042005, 2006 and 2005 and the twelve months ended June 30, 2006, we generated combined net sales of $1.7 billion, $2.4 billion and $3.0 billion, respectively, and combined Adjusted EBITDA of $119.6 million, $252.1 million and $357.4 million,2007, respectively. Our petroleum business generated $1.6$2.3 billion, $2.3$2.9 billion and $2.8 billion of our combined net sales, respectively, over these periods, with ourthe nitrogen fertilizer business generating substantially all of the remainder. In addition, during these three periods, our petroleum business contributed 76%, 74%$199.7 million, $245.6 million and 81%$144.9 million, respectively, of our combined operating income respectively, with our nitrogen fertilizer business contributing substantially all of the remainder.
Significant Milestones Sinceremainder contributed by the Changenitrogen fertilizer business. For the three months ended March 31, 2008, we generated combined net sales of Control in June 2005
Following the acquisition by certain affiliates$1.22 billion and operating income of The Goldman Sachs Group, Inc. (whom we collectively refer to in$87.4 million. Our petroleum business generated $1.17 billion of our combined net sales and $63.6 million of our combined operating income during this prospectus as the Goldman Sachs Funds) and certain affiliates of Kelso & Company (whom we collectively refer to in this prospectus as the Kelso Funds) in June 2005, a new senior management team led by Jack Lipinski, our Chief Executive Officer, was formed that blended the best of existing managementperiod, with highly experienced new members. Our new senior management team has executed several key strategic initiatives that we believe have significantly enhanced our competitive position and improved our financial and operational performance.
Increased Refinery Throughput and Yields. Management’s focus on crude slate optimization, reliability, technical support and operational excellence coupled with prudent expenditures on equipment has significantly improved the operating metricssubstantially all of the refinery. Historically,remainder contributed by the refinery operated at an average crude throughput rate of less than 90,000 bpd. In the second quarter of 2006, the plant averaged over 102,000 bpd of crude throughput with peak daily rates in excess of 108,000 bpd of crude. Recent operational improvements at the refinery have also allowed us to produce higher volumes of favorably priced distillates, premium gasoline and boutique gasoline grades for the Kansas City and Denver markets and to improve our liquid volume yield.nitrogen fertilizer business.
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Diversified Crude Feedstock Variety. To improve profitability, we have expanded the variety of crude grades processed in any given month from a limited few to nearly a dozen, including onshore and offshore domestic grades, various Canadian sours, heavy sours and sweet synthetics, and a variety of South American and West African imported grades. As a result of the crude slate optimization, we have improved our crude purchase cost discount to WTI by approximately $2.00 per barrel in the first half of 2006 compared to the first half of 2005.
Expanded Direct Rack Sales. To improve profitability, we have significantly expanded and intend to continue to expand rack marketing of refined products directly to customers rather than origin bulk sales. Today, we sell over 20% of our produced transportation fuels throughout the Coffeyville supply area within the mid-continent, at enhanced margins, through our proprietary terminals and at Magellan’s throughput terminals. With the expanded rack sales program, we improved our net income for the first half of 2006 compared to the first half of 2005.
Significant Plant Improvement and Capacity Expansion Projects. Management has identified and developed several significant capital projects with an estimated total cost of approximately $400 million primarily aimed at (1) expanding refinery capacity, (2) enhancing operating reliability and flexibility, (3) complying with more stringent environmental, health and safety standards, and (4) improving our ability to process heavy sour crude feedstock varieties. Substantially all of these capital expenditures are expected to be made before the end of 2007.
The following major projects under this program are expected to be completed in 2006:
| | |
| • | Construction of a new 23,000 bpd high pressure diesel hydrotreater and associated new sulfur recovery unit, which will allow the facility to meet the EPA Tier II Ultra Low Sulfur Diesel federal regulations; and |
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| • | Expansion of one of the two gasification units within the fertilizer complex, which is expected to increase ammonia production by 5,500 tons per year. |
The following major projects under this program expected to be completed in 2007 are intended to increase refinery processing capacity to up to 120,000 bpd, increase gasoline production and improve our liquid volume yield:
| | |
| • | Refinery-wide capacity expansion by increasing throughput of the existing fluid catalytic cracking unit, delayed coker, and other major process units to be completed during a plant-wide turnaround scheduled to begin in the first quarter of 2007; and |
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| • | Construction of a new grass roots 24,000 bpd continuous catalytic reformer to be completed in the third quarter of 2007. |
Once completed, these projects are intended to significantly enhance the profitability of the refinery in environments of high crack spreads and allow the refinery to operate more profitably at lower crack spreads than is currently possible. Our experienced engineering and construction team is managing these projects in-house with support from established specialized contractors, thus giving us maximum control and oversight of execution.
We have also undertaken a study to review expansion of the refinery beyond the program described above. Preliminary engineering for the first stage of a potential multi-stage expansion has been approved by our board of directors. If approved for implementation, each stage of this expansion is intended to lower the refinery crude cost by allowing the plant to process significant additional volumes of lower cost heavy sour crude from Canada or offshore. If approved for implementation, the first phase of this expansion is intended to be completed during 2009.
Our Competitive Strengths
Regional Advantage and Strategic Asset Location. Our refinery is one of only seven refineries located in the Coffeyville supplysouthern portion of the PADD II Group 3 distribution area. Because refined product demand in this area withinexceeds production, the mid-continent, a region where demand for
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refined products exceeded refining production by approximately 24% in 2005. Duehas historically required U.S. Gulf Coast imports to meet demand. We estimate that this favorable supply/demand imbalance combined with our lower pipeline transportation cost as compared to the U.S. Gulf Coast refiners we estimate that thehas allowed us to generate refining margins, in our markets, as measured by the2-1-1 crack spread, that have exceeded U.S. Gulf Coast refining margins by approximately $1.39$2.14 per barrel on average for the last four years. OurThe 2-1-1 crack spread is a general industry standard that approximates the per barrel refining margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil.
In addition, the nitrogen fertilizer business is well positionedgeographically advantaged to supply nitrogen fertilizer products to markets in Kansas, Missouri, Nebraska, Iowa, Illinois and Texas without incurring intermediate transfer, storage, barge or pipeline freight charges. We estimate thatBecause the nitrogen fertilizer business does not incur these costs, this locationalgeographic advantage provides usit with a distribution cost benefitadvantage over competitors not located in the farm belt who transport ammonia and UAN from the U.S. Gulf Coast, ammonia importers of approximately $65 per ton and over U.S. Gulf Coast UAN importers of approximately $37 per ton, assuming in each casebased on recent freight rates and handling chargespipeline tariffs for U.S. Gulf Coast importers as in effect in June 2006. These cost differentials represent a significant portion of the market price of these commodities.importers.
Access to and Ability to Process Multiple Crude Oils. Since June 2005 we have significantly expanded the variety of crude grades processed in any given month and have reduced our acquisition cost of crude relative to WTI by approximately $2.00$1.50 per barrel in the first half of 2006 compared to the first half of 2005. ProximityWhile our proximity to the Cushing crude oil trading hub minimizes the likelihood of an interruption of supply. Weto our supply, we intend to further diversify our sources of crude oil and, amongoil. Among other initiatives have secured shipper rightsin this regard, we maintain capacity on the newly built Spearhead pipeline, owned by CCPS Transportation, LLC (which is ultimately owned by Enbridge), which connects Chicago to the Cushing hub and provideshub. We have also committed to additional pipeline capacity on the proposed Keystone pipeline project currently under development by TransCanada Keystone Pipeline, LP which will provide us with an abilityaccess to secure incremental oil supplies from Canada. Further, weWe also own and operate a crude gathering system located inserving northern Oklahoma, and central Kansas and southwestern Nebraska, which allows us to acquire quality crudes at a discount to WTI.
High Quality, Modern Asset BaseRefinery with Solid Track Record. We operate a complex full coking sour crude refinery. Our refinery’s complexity allows us to optimize the yields (the percentage of refined product that is produced from crude and other feedstocks) of higher value transportation fuels (gasoline and distillate), which currently account for over 95%approximately 94% of our liquid production output. Complexity is a measure of a refinery’s ability to process lower quality crude in an economic manner; greater complexity makes a refinery more profitable. From 1995 through the first half of 2006,March 31, 2008, we have invested approximately $300$725 million to modernize our oil refinery and to meet more stringent U.S. environmental, health and safety requirements. These expendituresAs a result, we have achieved significant increases in combination with our management’s operational expertise, have allowed us to increase our average refinery crude throughput rate, from an average of less than 90,000 bpd prior to June 2005 to an average of over 102,000 bpd in the second quarter of 2006, over 94,500 bpd for all of 2006 and over 110,000 bpd in the fourth quarter of 2007 with peakmaximum daily rates in excess of 108,000 bpd. Management’s consistent focus on reliability and safety earned us120,000 bpd for the NPRA Gold Award for safety in 2005. Ourfourth quarter of 2007.
Unique Coke Gasification Fertilizer Plant. The nitrogen fertilizer plant, completed in 2000, is the newest most efficientfertilizer facility in North America and the only one of its kind in North America using a pet coke gasification process to produce ammonia. While this facility is unique to North America, gasification technology has been in use for over 50 years in various industries to produce fuel, chemicals and since 2003, has demonstrated a consistent recordother products from carbon-based source materials. Because it uses significantly less natural gas in the manufacture of operating near full capacity. Theammonia than other domestic nitrogen fertilizer plants, with the currently high price of natural gas the nitrogen fertilizer business’ feedstock cost per ton for ammonia is considerably lower than that of its natural gas-based fertilizer plant underwent a scheduled turnaround in 2006, and we have recently completed an expansioncompetitors. We estimate that the facility’s production cost advantage over U.S. Gulf Coast ammonia producers is sustainable at natural gas prices as low as $2.50 per MMBtu (at June 16, 2008, the price of the spare gasifier to increase the fertilizer production capacity.natural gas was $12.93 per MMBtu).
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Near Term Internal Expansion Opportunities. Since June 2005, we have identified and developed several significant capital projects with an estimated total cost of approximately $400 millionimprovements primarily aimed at (1) expanding refinery capacity, (2) enhancing operating reliability and flexibility, (3) complying with more stringent environmental, health and safety standards and (4) improving our ability to process heavy sour crude feedstock varieties. Once completed, these projectsWith the substantial completion of approximately $522 million of significant capital improvements (including $170 million in aggregate are expectedexpenditures for our refinery expansion project, excluding $3.7 million in related capitalized interest), we expect to significantly enhance the profitability of theour refinery in environmentsduring periods of high crack spreads and allowwhile enabling the refinery to operate more profitably at lower crack spreads than is currently possible. We are also considering aThe spare gasifier at the nitrogen fertilizer plant was expanded in 2006, increasing ammonia production by 6,500 tons per year. In addition, the nitrogen fertilizer plant is moving forward with an approximately $120 million fertilizer plant expansion, of which we estimate couldapproximately $11 million was incurred as of March 31, 2008. It is estimated that this expansion will increase ourthe nitrogen fertilizer plant’s capacity to upgrade ammonia into premium pricedpremium-priced UAN by approximately 50%. Management currently expects to 1,040,000 tons per year.
Unique Coke Gasification Fertilizer Plant. Our nitrogen fertilizer plant is the only one of its kindcomplete this expansion in North America utilizing a coke gasification process to produce ammonia, and has significantly lower feedstock costs than all other predominantly natural gas-based fertilizer plants. We estimate that we would continue to have a production cost advantage in comparison to U.S. Gulf Coast ammonia producers at natural gas prices as low as $2.50 per million Btu. This cost advantage has been more pronounced in today’s natural gas price environment, as the reported Henry Hub natural
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gas price has fluctuated between $4.50 to $15.00 per million Btu since the end of 2003. Our fertilizer business has a secure raw material supply as approximately 80% of the pet coke required by the fertilizer plant is supplied by our refinery. The sustaining capital requirements for this business are low compared to its earnings and are expected to be in the range of $3 million to $5 million per year compared to operating income of our nitrogen fertilizer segment of $71.0 million for the combined twelve months ended December 31, 2005.July 2010.
Experienced Management Team. In conjunction with the acquisition of our business by Coffeyville Acquisition LLC in June 2005 by funds affiliated with Goldman, Sachs & Co. and Kelso & Company, L.P., or the Goldman Sachs Funds and the Kelso Funds, a new senior management team was formed that blended the bestcombined selected members of existing management with highly experienced new members. Our senior management team averages over 28 years of refining and fertilizer industry experience. experience and, in coordination with our broader management team, has increased our operating income and stockholder value since June 2005.
Mr. John J. (Jack) Lipinski, our Chief Executive Officer, has over 3436 years of experience in the refining and chemicals industries, and prior to joining us in connection with the acquisition of Coffeyville Resources in June 2005, was in charge of a 550,000 bpd refining system and a multi-plant fertilizer system. Mr. Stanley A. Riemann, our Chief Operating Officer, has over 3234 years of experience, and prior to joining us in March 2004, was in charge of one of the largest fertilizer manufacturing systems in the United States. Mr. James T. Rens, our Chief Financial Officer, has over 1519 years of experience in the energy and fertilizer industries, and prior to joining us in March 2004, was the chief financial officer of two fertilizer manufacturing companies. Our management team has made significant and rapid improvements on many fronts since the acquisition of Coffeyville Resources and has succeeded in increasing operating income and shareholder value.
Our Business Strategy
Our objective is to continueThe primary business objectives for our refinery business are to increase economic throughputvalue for our operating facilities, control manufacturing expensesstockholders and take advantageto maintain our position as an independent refiner and marketer of market opportunities as they arise.refined fuels in our markets by maximizing the throughput and efficiency of our petroleum refining assets. In addition, management’s business objectives on behalf of the Partnership are to increase value for our stockholders and maximize the production and efficiency of the nitrogen fertilizer facilities. We intend to useaccomplish these objectives through the following strategies:
Pursuing Organic Expansion Opportunities. We continually evaluate opportunities to expand our existing asset base and consider capital projects that accentuate our core competitiveness in petroleum refining. We are also evaluating projects that will improve our ability to process heavy crude oil feedstocks and to increase our overall operating flexibility with respect to crude oil slates. In addition, management also continually evaluates capital projects that are intended to enhance the Partnership’s competitiveness in nitrogen fertilizer manufacturing.
Increasing the Profitability of Our Existing Assets. We strive to improve our operating efficiency and to reduce our costs by controlling our cost structure. We intend to make investments to improve the efficiency of our operations and pursue cost saving initiatives. We have recently completed the greenfield construction of a new continuous catalytic reformer. This project is expected to increase the profitability of our petroleum business through increased refined product yields and the elimination of scheduled downtime associated with the reformer that was replaced. In addition, this project reduces the dependence of our refinery on hydrogen supplied by the fertilizer facility, thereby
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allowing the nitrogen fertilizer business to generate higher margins by using the hydrogen to produce ammonia and UAN. The nitrogen fertilizer business expects, over time, to convert 100% of its production to higher-margin UAN.
Seeking Strategic Acquisitions. We intend to consider strategic acquisitions within the energy industry that are beneficial to our shareholders. We will seek acquisition opportunities in our existing areas of operation that have the potential for operational efficiencies. We may also examine opportunities in the energy industry outside of our existing areas of operation and in new geographic regions. In addition, working on behalf of the Partnership, management may pursue strategic and accretive acquisitions within the fertilizer industry, including opportunities in different geographic regions. We have no agreements or understandings with respect to any acquisitions at the present time.
Pursuing Opportunities to Maximize the Value of the Nitrogen Fertilizer Business. Our management, acting on behalf of the Partnership, will continually evaluate opportunities that are intended to enable the Partnership to grow its distributable cash flow. Management’s strategies specifically related to achieve this objective:the growth opportunities of the Partnership include the following:
| | |
| | • | ContinueExpanding UAN Production. The nitrogen fertilizer business is moving forward with an approximately $120 million nitrogen fertilizer plant expansion, of which approximately $11 million was incurred as of March 31, 2008. This expansion is expected to take advantagepermit the nitrogen fertilizer business to increase its UAN production and to result in its UAN manufacturing facility consuming substantially all of favorable supplyits net ammonia production. This should increase the nitrogen fertilizer plant’s margins because UAN has historically been a higher margin product than ammonia. The UAN expansion is expected to be complete in July 2010 and demand dynamicsit is estimated that it will result in an approximately 50% increase in the mid-continent region;nitrogen fertilizer business’ annual UAN production. The company has also begun to acquire or lease offsite UAN storage facilities and continues to expand this program. |
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| | • | Selectively investExecuting Several Efficiency-Based and Other Projects. The nitrogen fertilizer business is currently engaged in significantseveral efficiency-based and other projects in order to reduce overall operating costs, incrementally increase its ammonia production and utilize byproducts to generate revenue. For example, by redesigning the system that enhance our operating efficiencysegregates carbon dioxide, or CO2, during the gasification process, the nitrogen fertilizer business estimates that it will be able to produce approximately 25 tons per day of incremental ammonia, worth approximately $6 million per year at current market prices. The nitrogen fertilizer business estimates that this project will cost approximately $7 million (of which none has yet been incurred) and expand our capacity while rigorously controlling costs;will be completed in 2010. |
| |
| | • | ContinueEvaluating Construction of a Third Gasifier Unit and a New Ammonia Unit and UAN Unit at the Nitrogen Fertilizer Plant. The nitrogen fertilizer business has engaged a major engineering firm to help it evaluate attractive growth opportunities through acquisitionsand/or strategic alliances; |
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| • | Increase our salesthe construction and supply capabilitiesoperation of an additional gasifier unit to produce a synthesis gas from pet coke. It is expected that the addition of a third gasifier unit, together with additional ammonia and UAN units, to the nitrogen fertilizer business’ operations could result, on a long-term basis, in an increase in UAN production of approximately 75,000 tons per month. This project is in its earliest stages of review and other high value products, while finding lower cost sourcesis still subject to numerous levels of raw materials; |
|
| • | Continue to focus on being a reliable, low cost producer of petroleum and fertilizer products; and |
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| • | Continue to focus on the reliability, safety and environmental performance of our operations.internal analysis. |
Other opportunities our management may consider on behalf of the Partnership in the event that its managing general partner proceeds with an initial offering include acquiring certain of our petroleum business’ ancillary assets and providing incremental pipeline transportation and storage infrastructure services to our petroleum business. There are currently no agreements or understandings in place with respect to any such acquisitions or opportunities, and there can be no assurance that the Partnership would be able to operate any of these assets or businesses profitably.
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Our History
Prior to March 3, 2004, ourOur business was founded in 1906 by The National Refining Company, which at the time was the largest independent oil refiner in the United States. In 1944 the Coffeyville refinery was purchased by the Cooperative Refinery Association, a subsidiary of a parent company that in 1966 renamed itself Farmland Industries, Inc. Our refinery assets and the nitrogen fertilizer plant were operated as a small component of Farmland Industries, Inc., an agricultural cooperative.cooperative, until March 3, 2004. Farmland filed for bankruptcy protection on May 31, 2002.
Coffeyville Resources, LLC, a subsidiary of Coffeyville Group Holdings, LLC, won the bankruptcy court auction for Farmland’s petroleum business and a nitrogen fertilizer plant and completed the purchase of these assets on March 3, 2004. On October 8, 2004, Coffeyville Group Holdings, LLC, through two of its wholly owned subsidiaries, Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc., acquired an interest in Judith Leiber business, a designer handbag business, through an investment in CLJV Holdings, LLC (CLJV), a joint venture with The Leiber Group, Inc., whose majority stockholder was also the majority stockholder of Coffeyville Group Holdings, LLC. On June 23, 2005, the entire interest in the Judith Leiber business held by CLJV was returned to The Leiber Group, Inc. in exchange for all of its ownership interest in CLJV, resulting in a complete separation of the Immediate Predecessor and the Judith Leiber business.
On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, Coffeyville Acquisition LLC, which was formed in Delaware on May 13, 2005, acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. The Goldman Sachs FundsWith the exception of crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005, Coffeyville Acquisition LLC had no operations from its inception until the Kelso Funds own substantially all of the common unitsacquisition on June 24, 2005.
We were formed in Delaware in September 2006 as a wholly owned subsidiary of Coffeyville Acquisition LLC in order to complete the initial public offering of the businesses acquired by Coffeyville Acquisition, LLC from Coffeyville Group Holdings LLC. We completed our initial public offering on October 26, 2007. At that time, we transferred the nitrogen fertilizer business to CVR Partners, LP, a limited partnership we formed in June 2007. As consideration for the transfer, we received 30,303,000 special GP units and 30,333 special LP units in the Partnership, and the Partnership’s managing general partner, which currently owns allat that time was our indirect wholly-owned subsidiary, received the managing general partner interest and the IDRs. Immediately prior to the consummation of our capital stock.initial public offering, we sold the managing general partner, together with the IDRs, to Coffeyville Acquisition III LLC, an entity owned by the Goldman Sachs Funds, the Kelso Funds and certain members of CVR Energy’s senior management team, for its fair market value on the date of sale.
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Petroleum Business
Asset Description
We operate one of the seven refineries located inwithin the Coffeyville supply areamid-continent region (Kansas, Oklahoma, Missouri, Nebraska and Iowa). The Company’s complex cracking and coking medium-sour oil refinery has thea maximum capacity to produce 108,000of 123,500 bpd of petroleum products, which accounts for approximately 15%17% of the region’s output. As part of our comprehensive capital expenditure program, we expect to increase the refinery capacity to up to 120,000 bpd in 2007. The facility is situated on approximately 440 acres in southeastsoutheastern Kansas, approximately 80100 miles from the Cushing, Oklahoma, a major crude oil trading and storage hub.
The Coffeyville refinery is a complex facility. Complexity is a measure of a refinery’s ability to process lower quality crude in a morean economic manner. It is also a measure of a refinery’s ability to convert lower cost, more abundant heavier and sour crudes into greater volumes of higher valued refined products such as gasoline and distillate, thereby providing a competitive advantage over less complex refineries. At the time of the Subsequent Acquisition we hadWe have a modified Solomon complexity score of approximately 10.0. Due12.1, up from 10.0 in June 2005. “Modified Solomon complexity” is a standard industry measure of a refinery’s ability to process less-
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expensive feedstock, such as heavier and higher-sulfur content crude oils, into value-added products. Modified Solomon complexity is the weighted average of the Solomon complexity factors for each operating unit multiplied by the throughput of each refinery unit, divided by the crude capacity of the refinery. For the year ended December 31, 2007, our refinery’s complexity, higher valueproduct yield included gasoline (mainly regular unleaded) (45%), diesel fuel (mainly ultra low sulfur diesel) (42%), and coke and other refined products such as gasoline and diesel represent approximately an 89% product yield on a total throughput basis. Other products includeNGL (propane, butane), slurry, light cycle oil, vacuum tower bottom, or VTB, reformer feeds, sulfur, gas oil pet coke and sulfur. All of our pet coke by-product is consumed by our adjacent nitrogen fertilizer business, which enables the fertilizer plant to be cost effective, because pet coke is utilized in lieu of higher priced natural gas.
The refinery has undergone numerous expansions and upgrades over the last 10 years, with aggregate non-maintenance capital expenditures of approximately $200 million. Following completion of our present capital expenditure program we expect the Solomon complexity score to rise from 10.0 to 11.2, making the Coffeyville refinery one of the most complex mid-continent refineries.produced fuel (13%).
The refinery consists of two crude units with maximum sustainable capacities of 75,000 bpd and 45,000 bpd. It has two vacuum units with 21,000 bpdunits. A vacuum unit is a secondary unit which processes crude oil by separating product from the crude unit according to boiling point under high heat and 16,000 bpd capacities.low pressure to recover various hydrocarbons. The availability of more than one crude and vacuum unit creates redundancy in the refinery system and enables us to continue to run the refinery even if one of these units were to shut down for scheduled or unscheduled plant maintenance and upgrades. However, the maximum combined capacity of the crude units is limited by the overall downstream capacity of the vacuum units and other units.
Our petroleum business also includes the following auxiliary operating assets:
| | |
| | • | Crude Oil Gathering System. We own and operate a 25,000 bpd capacity crude oil gathering system serving central Kansas, northern Oklahoma and southwestern Nebraska. The system has field offices in Bartlesville, Oklahoma and Plainville and Winfield, Kansas. The system is comprised of over 300 miles of feeder and trunk pipelines, 4043 trucks, and associated storage facilities for gathering light, sweet Kansas, Nebraska and Oklahoma crude oils purchased from independent crude producers. We have also leasedlease a section of a third-party pipeline that will allow us to gather additional volumes of attractively priced quality crudes.from Magellan Pipeline Company, L.P. |
| |
| | • | Phillipsburg Terminal. We own storage and terminalling facilities for asphalt and refined fuels at Phillipsburg, Kansas. TheOur asphalt storage and terminalling facilities are leasedused to third partiesreceive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement. We also collect fees for refined products we store for another oil company. |
|
| • | Pipelines. We own a 145,000 bpd proprietary pipeline system that transports crude oil from Caney, Kansas to our refinery. Crude oils sourced outside of our proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to Caney, Kansas via a pipeline owned by Plains All American L.P. We also own associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our refinery. |
|
| • | Rack Marketing Division. We own a rack marketing division which supplies product through tanker trucks directly to customers located in close geographic proximity to our refinery and Phillipsburg terminal and to customers at throughput terminals on a throughput basis.Magellan Midstream Partners L.P.’s refined products distribution systems. |
Feedstocks Supply
Our refinery has the capability to process blends of a blendvariety of crudes ranging from heavy sour as well asto light sweet crudes. Currently, our refinery processes crude from a broad array of sources, approximately two-thirds domestic and one-third foreign.sources. We purchase foreign crudes from Latin America, South America, West Africa, the Middle East, West Africa, the North Sea and Canada. We purchase domestic crudes that meet pipeline specifications from Kansas, Oklahoma, Nebraska, Texas, and offshore deepwater Gulf of Mexico production. GivenWhile crude oil has historically constituted over 85% of our refinery’s ability to process a wide variety of crudes and ready access to multiple sources of crude, we have never curtailed production due to lack of crude access. Other feedstocksfeedstock inputs during the last five years, other feedstock inputs include isobutane, normal butane, natural gasoline, various grades of butanes, vacuumgas, alky feed, gas oil and vacuum tower bottom,
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or VTB, and others which are sourced from the Conway/Group 140 storage facility or regional refinery suppliers. Below is a summary of our historical feedstock inputs:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | | | Six Months Ended June 30, | |
| | | 2000 | | | 2001 | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2005 | | | 2006 | |
| | | (in barrels) | |
| |
| Crude oil | | | 31,286,728 | | | | 30,880,860 | | | | 27,172,830 | | | | 31,207,718 | | | | 33,227,971 | | | | 33,250,518 | | | | 15,982,325 | | | | 17,028,988 | |
| Natural gasoline | | | 766,228 | | | | 694,552 | | | | 1,093,629 | | | | 483,362 | | | | 317,874 | | | | 455,587 | | | | 111,620 | | | | 163,371 | |
| Normal butane | | | — | | | | — | | | | — | | | | — | | | | 530,575 | | | | 467,176 | | | | 158,116 | | | | 163,116 | |
| Isobutane | | | 924,875 | | | | 1,142,098 | | | | 1,037,855 | | | | 1,627,989 | | | | 1,615,898 | | | | 1,398,694 | | | | 645,660 | | | | 745,698 | |
| Alky feed | | | — | | | | — | | | | — | | | | — | | | | — | | | | 68,636 | | | | 51,961 | | | | 24,796 | |
| Gas oil | | | — | | | | — | | | | — | | | | — | | | | — | | | | 155,344 | | | | 34,574 | | | | 189,744 | |
| Vacuum tower bottom | | | 53,453 | | | | 32,951 | | | | 98,371 | | | | 109,974 | | | | 105,981 | | | | 99,362 | | | | 99,234 | | | | 30,208 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total Inputs | | | 33,031,284 | | | | 32,750,461 | | | | 29,402,685 | | | | 33,429,043 | | | | 35,798,299 | | | | 35,895,317 | | | | 17,083,490 | | | | 18,345,921 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
bottoms.
Crude is supplied to our refinery through our wholly owned gathering system and by pipeline.
Our crude gathering system was expanded in 2006 and nowcurrently supplies in excess of 22,00021,000 bpd of crude to the refinery (approximately 20% of total supply). A third party pipeline was leased in 2006 that will serve as part of our pipeline system and will allow for further buying of attractively priced locally produced crudes. Locally produced crudes are delivered to the
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refinery at a discount to WTI and are of similar quality to WTI. These lighter sweet crudes allow us to blend higher percentages of low cost crudes such as heavy sour Canadian while maintaining our target medium sour blend.
blend with an API gravity of28-36 degrees and 0.9-1.2% sulfur. Crude oils sourced outside of our proprietary gathering system are first delivered by common carrier pipelines (primarily Seaway) into various terminals into Cushing, Oklahoma where they are blendedby various pipelines including Seaway, Basin and then deliveredSpearhead and subsequently to Caney, KansasCoffeyville via aPlains pipeline owned by Plains All American L.P. Crudes are delivered toand our refinery from Caney, Kansas via aown 145,000 bpd proprietary pipeline system, which we own. We also maintain capacity onsystem.
For the Spearhead Pipeline owned by Enbridge from Canada. As part ofyear ended December 31, 2007, our crude oil supply optimization efforts, we leaseblend was comprised of approximately 1,550,000 barrels of65% light sweet crude oil, storage in Cushing,12% heavy sour crude oil and recently contracted to purchase23% medium/light sour crude oil. The light sweet crude oil includes our locally gathered crude oil. For the three months ended March 31, 2008, our crude oil supply blend was comprised of approximately 300 acres68% of land in the heart of the Cushinglight sweet crude storage district, which we expect will provide us a storage expansion option should the addition ofoil, 14% heavy sour crude storage be required in the future.
The following table sets forth the feedstock pipelines used by the oil refinery as of June 30, 2006:
| | | | |
| | Nominal
|
Pipeline
| | Capacity (bpd)
|
|
Seaway Pipeline (TEPPCO) from U.S. Gulf Coast to Cushing, Oklahoma | | | 350,000 | |
Spearhead (CCPS/Enbridge) from Griffith (Chicago) to Cushing, Oklahoma | | | 125,000 | |
Coffeyville Crude Oil Pipeline System from Caney, Kansas to Oil Refinery | | | 145,000 | |
Coffeyville Crude Oil Gathering and Trucking System | | | 25,000 | |
Natural Gas Liquid (NGL) Connection from/to Conway, Kansas through MAPCO and ONEOK | | | 15,000 | |
Plains-Cushing to Caney, Kansas | | | 97,000 | |
Sun Logistics Pipeline from U.S.G.C. to Cushing, Oklahoma | | | 120,000 | |
and 18% medium/light sour crude oil.
We purchase most of our crude oil requirements outside of our proprietary gathering system under a credit intermediation agreement with J. Aron. The credit intermediation agreement helps us reduce our inventory position and mitigate crude pricing risk. Once we identify cargos of crude oil and pricing terms that meet our requirements, we notify J. Aron which then provides, for a fee, credit, transportation and other logistical services for delivery of the crude to the crude oil tank farm. Generally, we select crude oil approximately 30 to 45 days in advance of the time the related refined
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products are to be marketed, except for Canadian and West African crude purchases which require an additional 30 days of lead time due to transit considerations.
Transportation Fuels
| | |
| • | Gasoline. Gasoline typically accounts for approximately 47% of our refinery’s production. Our oil refinery produces various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded and uses a computerized component blending system to optimize gasoline blending. |
|
| • | Distillates. Kerosene, diesel and off-road diesel typically account for approximately 41% of the refinery’s production. The majority of the diesel fuel we produce is low-sulfur. |
The following table summarizes our historical oil refinery yields:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended
| | | Six Months Ended
| |
| | | December 31, | | | June 30, | |
| | | 2001 | | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2005 | | | 2006 | |
| | | (in barrels) | |
| |
| Gasoline: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Regular unleaded | | | 15,118,607 | | | | 14,071,304 | | | | 16,531,362 | | | | 16,703,566 | | | | 16,154,172 | | | | 7,512,804 | | | | 8,382,403 | |
| Premium unleaded | | | 423,898 | | | | 306,334 | | | | 298,789 | | | | 220,908 | | | | 261,467 | | | | 136,075 | | | | 270,207 | |
| Sub-octane unleaded | | | 803,590 | | | | 754,264 | | | | 773,831 | | | | 797,416 | | | | 109,774 | | | | 59,986 | | | | 80,599 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total gasoline | | | 16,346,095 | | | | 15,131,902 | | | | 17,603,982 | | | | 17,721,890 | | | | 16,525,413 | | | | 7,708,865 | | | | 8,733,209 | |
| Distillate: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Kerosene | | | 25,675 | | | | 26,085 | | | | 25,149 | | | | 23,256 | | | | 32,302 | | | | 8,091 | | | | (5,542 | ) |
| Jet fuel | | | 97,354 | | | | — | | | | — | | | | — | | | | — | | | | | | | | | |
| No. 1 distillate | | | 278,325 | | | | 124,741 | | | | 342,363 | | | | 99,832 | | | | 261,048 | | | | 28,857 | | | | 3,272 | |
| No. 2 low sulfur distillate | | | 6,708,536 | | | | 6,526,883 | | | | 7,899,132 | | | | 8,896,701 | | | | 9,129,518 | | | | 4,062,492 | | | | 5,599,539 | |
| No. 2 high sulfur distillate | | | 3,138,236 | | | | 2,268,116 | | | | 3,017,785 | | | | 3,500,351 | | | | 3,916,658 | | | | 2,160,909 | | | | 2,031,624 | |
| Diesel | | | 2,105,709 | | | | 1,923,370 | | | | 1,258,279 | | | | 1,425,897 | | | | 1,259,308 | | | | 748,896 | | | | 22,869 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total distillate | | | 12,353,835 | | | | 10,869,195 | | | | 12,542,708 | | | | 13,946,037 | | | | 14,598,834 | | | | 7,009,245 | | | | 7,651,762 | |
| Liquid by-products: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| NGL (propane, butane) | | | 676,753 | | | | 583,095 | | | | 734,737 | | | | 1,137,645 | | | | 696,637 | | | | 337,088 | | | | 342,989 | |
| Slurry | | | 507,407 | | | | 445,784 | | | | 532,236 | | | | 500,692 | | | | 562,657 | | | | 229,339 | | | | 375,492 | |
| Light cycle oil sales | | | 214,504 | | | | 84,146 | | | | 42,571 | | | | — | | | | — | | | | — | | | | | |
| VTB sales | | | 188,684 | | | | 8,212 | | | | 26,438 | | | | 150,700 | | | | 134,899 | | | | | | | | 25,949 | |
| Reformer feed sales | | | 207,154 | | | | — | | | | — | | | | 79,906 | | | | 230,785 | | | | 147,178 | | | | 180,360 | |
| Gas oil sales | | | — | | | | 84,673 | | | | — | | | | — | | | | 66,274 | | | | 66,274 | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total liquid by-products | | | 1,794,502 | | | | 1,205,910 | | | | 1,335,982 | | | | 1,868,943 | | | | 1,691,252 | | | | 779,879 | | | | 924,790 | |
| Solid by-products: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Coke | | | 2,751,298 | | | | 2,068,031 | | | | 1,956,619 | | | | 2,384,414 | | | | 2,439,297 | | | | 1,193,304 | | | | 1,273,412 | |
| Sulfur | | | 92,918 | | | | 74,226 | | | | 131,137 | | | | 88,744 | | | | 100,035 | | | | 36,434 | | | | 44,755 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total solid by-products | | | 2,844,216 | | | | 2,142,257 | | | | 2,087,756 | | | | 2,473,158 | | | | 2,539,332 | | | | 1,229,738 | | | | 1,318,167 | |
| NGL production | | | 226,159 | | | | 52,682 | | | | (8,539 | ) | | | — | | | | 548,883 | | | | 291,635 | | | | 218,419 | |
| In process change | | | (347,599 | ) | | | 114,945 | | | | (120,122 | ) | | | (12,369 | ) | | | 265,280 | | | | 200,697 | | | | (307,639 | ) |
| Produced fuel | | | 1,369,413 | | | | 1,268,388 | | | | 1,489,030 | | | | 1,636,665 | | | | 1,557,689 | | | | 762,026 | | | | 812,823 | |
| Processing loss (gain) | | | (1,836,160 | ) | | | (1,382,594 | ) | | | (1,501,754 | ) | | | (1,836,025 | ) | | | (1,831,366 | ) | | | (898,595 | ) | | | (1,005,610 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total yields | | | 32,750,461 | | | | 29,402,685 | | | | 33,429,043 | | | | 35,798,299 | | | | 35,895,317 | | | | 17,083,490 | | | | 18,345,921 | |
Our oil refinery’s long-term capacity utilization has steadily improved over the years. To further enhance capacity utilization, our operations management initiativesDistribution, Sales and capital expenditures program are focused on improving crude slate flexibility, increasing inbound NGL pipeline capacity and optimizing use of raw materials and in-process feedstock.
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The following table summarizes storage capacity at the oil refinery as of June 30, 2006 which we believe is sufficient for our current needs:
| | | | |
Product
| | Capacity (barrels)
|
|
Gasoline | | | 767,000 | |
Distillates | | | 1,068,000 | |
Intermediates | | | 1,004,000 | |
Crude oil(1) | | | 1,194,000 | |
| | |
(1) | | Crude oil storage consists of 674,000 barrels of refinery storage capacity and 520,000 barrels of field storage capacity. |
Distribution Pipelines and Product TerminalsMarketing
We focus our petroleum products marketing efforts onin the midwestern states of Oklahoma, Kansas, Missouri, Nebraska,central mid-continent and Iowa for the sale of our petroleum productsRocky Mountain areas because of their relative proximity to our oil refinery and their pipeline access. Since the Subsequent Acquisition,June 2005, we have significantly expanded our rack sales. Rack sales directly toare sales made using tanker trucks via either a proprietary or third party terminal facility designed for truck loading. In the customers as opposed to origin bulk sales. Currently,year ended December 31, 2007, approximately 20%23% of the refinery’s products arewere sold through the rack system directly to retail and wholesale customers while the remaining 80% is77% was sold through pipelines via bulk spot and term contracts. We make bulk sales (sales through third party pipelines) into the mid-continent markets via Magellan and into Colorado and other destinations utilizing the product pipeline networks owned by Magellan, Enterprise and NuStar.
We are able to distribute gasoline, diesel fuel, and natural gas liquids produced at the refinery either into the Magellan or Enterprise pipelinepipelines and further on through ValeroNuStar and other Magellan systems or via the trucking system. The Magellan #2 and #3 pipelines (with capacity of 81,000 bpd and 32,000 bpd, respectively) are connected directly to the refinery and transport products to Kansas City and other northern cities. The ValeroNuStar and Magellan (Mountain) pipelines are accessible via the Enterprise outbound line (with capacity of 12,000 bpd) or through the Magellan system at El Dorado, Kansas. Our modern three-bay, bottom-loading fuels loading rack at our refinery has been in service since July 1998 with a maximum delivery capability of 225 trucks per day or 40,000 bpd of finished gasoline and diesel fuels. We own and operate storage and terminalling facilities in Phillipsburg, Kansas. We lease this storage to third parties and charge for the terminalling services. The truck terminal includes two loading locations with a capacity of approximately 95 trucks per day.
Below is a detailed summary of our product distribution pipelines and their capacities:
| | | | |
Pipeline
| | Capacity (bpd)
|
|
Magellan Pipeline #3-8” Line (from Coffeyville to northern cities via Caney, Kansas) | | | 32,000 | |
Magellan Pipeline #2-10” Line (from Coffeyville to northern cities via Barnsdall, Oklahoma) | | | 81,000 | |
Enterprise Pipeline (provides accessibility to Magellan (Mountain) and Valero systems at El Dorado, Kansas) | | | 12,000 | |
Truck Loading Rack Delivery System | | | 40,000 | |
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The following map depicts part of the Magellan pipeline, which the oil refinery uses for the majority of its distribution.
Source: Magellan Midstream Partners, L.P.
Customers
Customers for our petroleum products include other refiners, convenience store companies, railroads and farm cooperatives. We have bulk term contracts in place with many of these customers, which typically extend from a few months to one year in length. For the year ended December 31, 2007, QuikTrip Corporation accounted for 11.6% of our petroleum business sales and 64.3% of our petroleum sales were made to our 10 largest customers. For the three months ended March 31, 2008, QuikTrip Corporation accounted for 14.8% of our petroleum business sales and 66.1% of our petroleum sales were made to our 10 largest customers.
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Competition
Our oil refinery in Coffeyville, Kansas ranks second in processing capacity and fifth in refinery complexity, among the seven mid-continent fuels refineries. The following table presents certain information about us and the six other major mid-continent fuel oil refineries with which we compete:
| | | | | | | | | | | |
| | | | | Crude Capacity
| | | Solomon
| |
| | | | | (Barrels per
| | | Complexity
| |
Company | | Location | | Calendar Day) | | | Index | |
| |
| ConocoPhillips | | Ponca City, OK | | | 187,000 | | | | 13.7 | |
| CVR Energy | | Coffeyville, KS | | | 115,000 | | | | 12.1 | |
| Frontier Oil | | El Dorado, KS | | | 110,000 | | | | 13.0 | |
| Valero | | Ardmore, OK | | | 91,500 | | | | 11.2 | |
| NCRA | | McPherson, KS | | | 82,700 | | | | 13.1 | |
| Sinclair | | Tulsa, OK | | | 70,000 | | | | 6.2 | |
| Gary Williams Energy | | Wynnewood, OK | | | 52,500 | | | | 8.5 | |
| | | | | | | | | | | |
| Mid-continent Total: | | | | | 708,700 | | | | | |
| | | | | | | | | | | |
Source: Oil and Gas Journal. A Sunoco refinery located in Tulsa, Oklahoma was excluded from this table because it is not a stand-alone fuels refinery. The Solomon Complexity Index of each of these facilities has been calculated based on data from the Oil and Gas Journal together with Company estimates and assumptions.
We compete with our competitors primarily on the basis of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are costs of crude oil and other feedstock costs, refinery complexity (a measure of a refinery’s ability to convert lower cost heavy and sour crudes into greater volumes of higher valued refined products such as gasoline), refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refinery provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors.
Our competitors include trading companies such as SemFuel, L.P., Western Petroleum, Center Oil, Tauber Oil Company, Morgan Stanley and others. In addition to competing refineries located in the mid-continent United States, our oil refinery also competes with other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the U.S. Gulf Coast and the Texas Panhandle region.
Our refinery competition also includes branded, integrated and independent oil refining companies such as BP, Shell, ConocoPhillips, Valero, Sunoco and Citgo, whose strengths include their size and access to capital. Their branded stations give them a stable outlet for refinery production although the branded strategy requires more working capital and a much more expensive marketing organization.
Seasonality
Our petroleum business experiences seasonal effects as demand for gasoline products is generally higher during the summer months than during the winter months due to seasonal increases in highway traffic and road construction work. Demand for diesel fuel during the winter months also decreases due to agricultural work declines during the winter months. As a result, our results of operations for the first and fourth calendar quarters are generally lower than for those for the second and third calendar quarters. In addition, unseasonably cool weather in the summer monthsand/or unseasonably warm weather in the winter months in the markets in which we sell our petroleum products can vary demand for gasoline and diesel fuel.
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Nitrogen Fertilizer Business
We operate the largest single train ammonia and UAN production facility in North America, with ammonia production capacity of 430,000 tons per year and UAN production capacity of 720,000 tons per year. It isThe nitrogen fertilizer business operates the only nitrogen fertilizer plant in North America utilizingthat utilizes a coke gasification process to generate hydrogen feedstock that is further converted to ammonia for the production of nitrogen fertilizers. We areThe nitrogen fertilizer business is also considering amoving forward with an $120 million fertilizer plant expansion, of which approximately $11 million was incurred as of March 31, 2008, which we estimate could increase ourthe facility’s capacity to upgrade ammonia into premium priced UAN by approximately 50% and which we expect to 1,040,000 tons per year.be completed in June 2010.
OurThe facility uses a gasification process licensed from an affiliate of The General Electric Company, or General Electric, to convert pet coke to high purity hydrogen for subsequent conversion to ammonia. It uses between 950975 to 1,0501,075 tons per day of pet coke from the refinery and another 250260 to 300310 tons per day from unaffiliated, third-party sources such as other Midwestern refineries or pet coke brokers and converts it all to approximately 1,200 tons per day of ammonia. OurThe fertilizer plant has demonstrated consistent levels of production at levels close to full capacity and has the following advantages compared to competing natural gas-based facilities:
Significantly Lower Cost Position. Our nitrogen fertilizer plant’s pet coke gasification process allows us to use less thanuses approximately 1% of the natural gas relative toused by other nitrogen basednitrogen-based fertilizer facilities that are heavily dependent upon natural gas and are thus heavily impacted by natural gas price swings. Because ourthe nitrogen fertilizer plant uses pet coke, we have a significant cost advantage over other North American natural gas-based fertilizer producers. TheThis cost advantage is sustainable at natural gas prices as low as $2.50 per MMBtu. Natural gas sold at an average price of $7.12 per MMBtu in the United States in 2007. Average yearly natural gas prices have exceeded $2.50 per MMBtu since 2000, although average prices were lower in prior years. See “Industry Overview — Fertilizer Pricing Trends”. Natural gas prices are cyclical and volatile and may decline at any time. See “Risk Factors — Risks Related to the Nitrogen Fertilizer Business — Natural gas prices affect the price of the nitrogen fertilizers that the nitrogen fertilizer business sells. Any decline in natural gas prices could have a material adverse effect on our results of operations, financial condition and the ability of the nitrogen fertilizer business to make cash distributions”. CVR Energy’s adjacent refinery supplies approximately 80%has supplied on average more than 75% of our raw material.pet coke needs during the last four years.
Strategic Location with Transportation Advantage. We believeThe nitrogen fertilizer business believes that selling products to customers in close proximity to ourthe UAN plant and reducing transportation costs are keys to maintaining ourits profitability. Due to ourthe plant’s favorable location relative to end users and high product demand relative to production volume all of ourthe product shipments are targeted to freight advantaged destinations located in the U.S. farm belt. The available ammonia production at ourthe nitrogen fertilizer plant is small and easily sold into truck and rail delivery points. OurThe products leave the plant either in
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trucks for direct shipment to customers or in railcars for principally Union Pacific Railroad destinations. We doThe nitrogen fertilizer business does not incur any intermediate transfer, storage, barge freight or pipeline freight charges. Consequently, because these costs are not incurred, we estimate that ourthe plant enjoys a distribution cost advantage over those competitors who are U.S. Gulf Coast ammonia importers of approximately $65 per ton and over U.S. Gulf Coast UAN importers, of approximately $37 per ton, assuming in each case freight rates and handling chargespipeline tariffs for U.S. Gulf Coast importers as recently in effect in June 2006. Such cost differentials represent a significant portion of the market price of these commodities. For example, since the end of 2004, ammonia prices have fluctuated between $290 and $424 per ton, and UAN prices have fluctuated between $175 and $230 per ton.effect.
High and Increasing Capacity Utilization.On-Stream Factor. Capacity utilization has increased steadily over the last five and a half years of operation. The gasifier on-stream factor (ais a measure of how long the gasifier hasunits comprising our nitrogen fertilizer facility have been operational over a period) was 98.1% and 97.4% for 2005 and for the first six months of 2006, respectively.given period. We expect that efficiency of the nitrogen fertilizer plant will continue to improve with operator training, replacement of unreliable equipment, and reduced dependence on contract maintenance.
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended
| | | | |
| | | December 31, | | | Six Months Ended June 30, | |
| | | 2002 | | | 2003 | | | 2004 | | | 2005 | | | 2005 | | | 2006 | |
| |
| Gasifier on-stream(1) | | | 78.6% | | | | 90.1% | | | | 92.4% | | | | 98.1% | | | | 97.5% | | | | 97.4% | |
| Ammonia capacity utilization(2) | | | 66.0% | | | | 83.6% | | | | 76.8% | | | | 102.9% | | | | 101.3% | | | | 103.2% | |
| UAN capacity utilization(3) | | | 79.4% | | | | 93.3% | | | | 97.0% | | | | 121.2% | | | | 118.7% | | | | 121.0% | |
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, | |
| | | 2003 | | | 2004(1) | | | 2005 | | | 2006(1) | | | 2007(1) | |
| |
| Gasifier | | | 90.1 | % | | | 92.4 | % | | | 98.1 | % | | | 92.5 | % | | | 90.0 | % |
| Ammonia | | | 89.6 | % | | | 79.9 | % | | | 96.7 | % | | | 89.3 | % | | | 87.7 | % |
| UAN | | | 81.6 | % | | | 83.3 | % | | | 94.3 | % | | | 88.9 | % | | | 78.7 | % |
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| | |
| (1) | | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. |
|
(2) | | Based on nameplate capacity Excluding the impact of 1,100 tons per day. |
|
(3) | | Based on nameplate capacityturnarounds at the nitrogen fertilizer facility in the third quarter of 1,500 tons per day.2004 and 2006, (i) the on-stream factors in 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN, and (ii) the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN. |
Raw Material Supply
OurThe nitrogen fertilizer facility’s primary input is pet coke. During the past four years, more than 75% of the nitrogen fertilizer facility’s pet coke approximately 80% of which isrequirements on average were supplied by our adjacent oil refinery at market prices.refinery. Historically we havethe nitrogen fertilizer business has obtained a small amountthe remainder of its pet coke from third parties. We have had a reliable and sufficient supply of third-partyparties such as other midwestern refineries or pet coke from other Midwestern refineriesbrokers at spot prices. We believe that optimization of the use of our oil refinery’s coker should reduce the need for third-party pet coke. If necessary, the gasifier can also operate on low grade coal as an alternative, which provides an additional raw material source. There are significant supplies of low grade coal within a 60 mile60-mile radius of ourthe nitrogen fertilizer plant.
Pet coke is produced as a by-product of our refinery’s coker unit process, which is one step in refining crude oil into gasoline, diesel and jet fuel. In order to refine heavy or sour crude oil, which is lower in cost and more prevalent than higher quality crude, refiners use coker units, which help to reduce the sulfur content in fuels refined from heavy or sour crude oil. In North America, the shift from refining dwindling reserves of sweet crude oil to more readily available heavy and sour crude (which can be obtained from, among other places, the Canadian oil sands) will result in increased pet coke production. With $26.6 billion in coker unit projects planned at North American refineries as of November 2007, pet coke production is expected to increase significantly in the future.
The BOCnitrogen fertilizer plant is located in Coffeyville, Kansas, which is part of the Midwest coke market. The Midwest coke market is not subject to the same level of pet coke price variability as is the U.S. Gulf Coast coke market, due mainly to more stable transportation costs. Transportation costs have gone up substantially in both the Atlantic and Pacific sectors. Given the fact that the majority of the nitrogen fertilizer business’ suppliers are located in the Midwest, its geographic location gives it (and its similarly located competitors) a significant freight cost advantage over its U.S. Gulf Coast market competitors. The Midwest Green Coke (Chicago Area, FOB Source) annual average price over the last three years has ranged from $24.50 per ton to $27.00. The U.S. Gulf Coast market annual average price during the same period has ranged from $21.29 per ton to $49.83. Furthermore, Sinclair Tulsa Refining, located in Oklahoma, has announced a coker expansion project, and Frontier in El Dorado, Kansas has a coker expansion project under construction. These new refineries should help to further stabilize the Midwest coke market.
The Linde Group owns, operates, and maintains the air separation plant that provides contract volumes of oxygen, nitrogen, and compressed dry air to the gasifier for a monthly fee. We provideThe nitrogen fertilizer business provides and paypays for all utilities required for operation of the air separation unit.plant. The air separatorseparation plant has not experienced any long-term operating problems. The nitrogen fertilizer plant is covered for business interruption insurance for up to $1.25 billion$25.0 million in case of any interruption in the supply of oxygen from Linde from a covered peril. The BOC Group. Our agreement with The BOC GroupLinde expires in 2020.
The agreement also provides that if our requirements for liquid or gaseous oxygen, liquid or gaseous nitrogen or clean dry air exceed specified instantaneous flow rates by at least 10%, we can solicit bids from Linde and third parties to supply our incremental product needs. We importare required to provide notice to Linde of the approximate quantity of excess product that we will need and the approximate date by which we will need it; we and Linde will then jointly develop a request for proposal for soliciting bids from third parties and Linde. The bidding procedures may be limited under specified circumstances.
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The nitrogen fertilizer business importsstart-up steam for the fertilizer plant from our adjacent oil refinery, and then exportexports steam back to the oil refinery once all of its units are in service. Monthly charges and credits are booked with steam valued at the gas price for the month. We have entered into a feedstock and shared services agreement with the Partnership which regulates, among other things, the import and export ofstart-up steam between the refinery and the nitrogen fertilizer plant.
Production Process
OurThe nitrogen fertilizer plant was built in 2000 with a pair oftwo separate gasifiers to provide reliability. It uses a gasification process licensed from General Electric to convert pet coke into high purity hydrogen for subsequent conversion into ammonia. Following a turnaround completed in the second quarter of 2006, the plant is capable of processing approximately 1,300 tons per day of pet coke from the oil refinery and third-party sources and
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converting it into approximately 1,200 tons per day of ammonia. It uses a gasification process licensed from General Electric to convert the pet coke to high purity hydrogen for subsequent conversion to ammonia. A majority of the ammonia is converted to approximately 2,0752,000 tons per day of UAN. Typically 0.41 tons of ammonia are required to produce one ton of UAN.
Pet coke is first ground and blended with water and a fluxant (a mixture of fly ash and sand) to form a slurry that is then pumped into the partial oxidation gasifier. The slurry is then contacted with oxygen from an air separation unit, or ASU. Partial oxidation reactions take place and the synthesis gas, or syngas, consisting predominantly of hydrogen and carbon monoxide, is formed. The mineral residue from the slurry is a molten slag (a glasslike substance containing the metal impurities originally present in coke) and flows along with the syngas into a quench chamber. The syngas and slag are rapidly cooled and the syngas is separated from the slag.
Slag becomes a by-product of the process. The syngas is scrubbed and saturated with moisture. The syngas next flows through a shift unit where the carbon monoxide in the syngas is reacted with the moisture to form hydrogen and carbon dioxide. The heat from this reaction generates saturated steam. This steam is combined with steam produced in the ammonia unit and the excess steam not consumed by the process is sent to the adjacent oil refinery.
After additional heat recovery, the high-pressure syngas is cooled and processed in the acid gas removal, or AGR, unit. The syngas is then fed to a pressure swing absorption, or PSA, unit, where the remaining impurities are extracted. The PSA unit reduces residual carbon monoxide and carbon dioxide levels to trace levels, and the moisture-free, high-purity hydrogen is sent directly to the ammonia synthesis loop.
The hydrogen is reacted with nitrogen from the ASU in the ammonia unit to form the ammonia product. A portion of the ammonia is converted to UAN.
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The following is an illustrative Nitrogen Fertilizer Plant Process Flow Chart:
Critical equipment is set up onThe nitrogen fertilizer business schedules and provides routine maintenance schedulesto its critical equipment using ourits own maintenance technicians. We havePursuant to a Technical Services Agreement with General Electric, which licensedlicenses the gasification technology to us. Under this agreement,the nitrogen fertilizer business, General Electric experts provide technical advice and technological updates from their ongoing research as well as other licensees’ operating experiences.
The pet coke gasification process is licensed from General Electric pursuant to a license agreement that was fully paid up as of June 1, 2007. The license grants the nitrogen fertilizer business perpetual rights to use the pet coke gasification process on specified terms and conditions. The license is important because it allows the nitrogen fertilizer facility to operate at a low cost compared to facilities which rely on natural gas.
Distribution, Sales and Marketing
The primary geographic markets for ourthe fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, Colorado and Texas. We market our ammoniaAmmonia products are marketed to industrial and agricultural customers and our UAN products are marketed to agricultural customers. The direct application agricultural demand from ourthe nitrogen fertilizer plant occurs in three main use periods. The summer wheat pre-plant occurs in
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August and September. The fall pre-plant occurs in late October and November. The highest level of ammonia demand is traditionally observed in the spring pre-plant period, from March through May. There are also small fill volumes that move in the off-season to fill the available storage at the dealer level.
Ammonia and UAN are distributed by truck or by railcar. If delivered by truck, products are sold on afreight-on-board basis, and freight is normally arranged by the customer. WeThe nitrogen fertilizer business also ownowns and leaseleases a fleet of railcars. WeIt also negotiatenegotiates with distributors that have their own leased railcars to utilize these assets to deliver products. We ownThe nitrogen fertilizer business owns all of the truck and rail loading equipment at ourits facility. We operateIt operates two truck loading and eight rail loading racks for each of ammonia and UAN.
Sales and Marketing
Petroleum Business
We focus our marketing efforts on the Midwestern states of Oklahoma, Kansas, Missouri, Nebraska, and Iowa and frequently Colorado, as economics dictate, for the sale of our petroleum products because of their relative proximity to our refinery and their pipeline access. Our refinery produces approximately 90,000 bpd of gasoline and distillates, which we estimate was approximately 11% of the demand for gasoline and distillates in our target market area in the first half of 2006.
Nitrogen Fertilizer Business
The primary geographic markets for our fertilizer products are Kansas, Missouri, Nebraska, Iowa, Illinois, and Texas. We market our ammonia products to industrial and agricultural customers and our UAN products to agricultural customers. The direct application agricultural demand from our nitrogen fertilizer plant occurs in three main use periods. The summer wheat pre-plant occurs in August and September. The fall pre-plant occurs in late October and in November. The highest level of ammonia demand is traditionally in the spring pre-plant period, from March through May. There are also small fill volumes that move in the off-season to fill the available storage at the dealer level.
We market ourbusiness markets agricultural products to destinations that produce the best margins for ourthe business. These markets are primarily located on the Union Pacific railroad or destinations which can be supplied by truck. By securing this business directly, we reduce ourthe nitrogen fertilizer business reduces its dependence on distributors serving the same customer base, which enables usit to capture a larger margin and allows usit to better control ourits product distribution. Most of ourthe agricultural sales are made on a competitive spot basis. WeThe nitrogen fertilizer business also offeroffers products on a
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prepay basis for in-season demand. The heavy in-season demand periods are spring and fall in the corn belt and summer in the wheat belt. The corn belt is the primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. The wheat belt is the primary wheat producing region of the United States, which includes Kansas, North Dakota, Oklahoma, South Dakota and Texas. Some of ourthe industrial sales are spot sales, but most are on annual or multiyear contracts. Industrial demand for ammonia provides consistent sales and allows usthe nitrogen fertilizer business to better manage inventory control and generate consistent cash flow.
Customers
Petroleum Business
Customers for our petroleum products include other refiners, convenience store companies, railroads and farm cooperatives. We have bulk term contracts in place with most of these customers, which typically extend from a few months to one year in length. Our shipments to these customers are typically in the 10,000 to 60,000 barrel range (420,000 to 2,250,000 gallons) and are delivered by pipeline. We enter into these types of contracts in order to lock in a committed volume at market prices to ensure an outlet for our refinery production. For the year ended December 31, 2005, CHS Inc., SemFuel LP, QuikTrip Corporation and GROWMARK, Inc. accounted for 16.2%, 15.9%, 15.8% and 10.8%, respectively, of our petroleumThe nitrogen fertilizer business sales and for the six months ended June 30, 2006, they accounted for 2.1%, 13.6%, 16.8% and 9.8%, respectively. We sell bulk products based on industry market related indexes such as Platt’s or NYMEX related Group Market (Midwest) prices.
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In addition to bulk sales, we have implemented an aggressive rack marketing initiative. Utilizing the Magellan pipeline system we are able to reach customers such as QuikTrip, Casey’s, Murphy, Hy-Vee, Pilot Travel Centers, Flying J Truck Stops, Krause-Gentel (Kum and Go) and others. Our longer term, target customers may include industrial and commercial end users, railroads, and farm cooperatives that buy in truckload quantities. Truck terminal sales are at daily posted prices which are influenced by competitor pricing and spot market factors. Rack prices are typically higher than bulk prices.
Nitrogen Fertilizer Business
We sellsells ammonia to agricultural and industrial customers. We sellIt sells approximately 80% of the ammonia we produceit produces to agricultural customers, such as farmers in the mid-continent area between North Texas and Canada, and approximately 20% to industrial customers. Our agriculturalAgricultural customers include distributors such as MFA, United Suppliers, Inc., Brandt Consolidated Inc., ConAgra Fertilizer, Interchem, GROWMARK,and CHS, Inc., Mid West Fertilizer Inc., DeBruce Grain, Inc., and Agriliance, LLC. Our industrial Industrial customers include Tessenderlo Kerley, Inc. and Truth Chemical. We sellNational Cooperative Refinery Association. The nitrogen fertilizer business sells UAN products to retailers and distributors. Given the nature of its business, and consistent with industry practice, the nitrogen fertilizer business does not have long-term minimum purchase contracts with any of its customers.
For the yearyears ended December 31, 2005, 2006 and 2007 and the sixthree months ended June 30, 2006, ourMarch 31, 2008, the top five ammonia customers in the aggregate represented 55.2%, 51.9%, 62.1% and 52.6%68.4% of ourthe nitrogen fertilizer business’ ammonia sales, respectively, and ourthe top five UAN customers in the aggregate represented 43.1%, 30.0%, 38.7% and 29.2%42.4% of ourits UAN sales, respectively. During the year ended December 31, 2005, Brandt Consolidated Inc. and MFA accounted for 23.3% and 13.6% of ourthe nitrogen fertilizer business’ ammonia sales, respectively, and AgrilianceCHS Inc. and ConAgra Fertilizer accounted for 14.7% and 12.7% of ourits UAN sales, respectively. During the six monthsyear ended June 30,December 31, 2006, Brandt Consolidated Inc. and MFA accounted for 22.9%22.2% and 12.5%13.1% of ourthe nitrogen fertilizer business’ ammonia sales, respectively, and AgrilianceConAgra Fertilizer and CHS Inc. accounted for 8.4% and 6.8% of its UAN sales, respectively. During the year ended December 31, 2007, Brandt Consolidated Inc., MFA and ConAgra Fertilizer accounted for 6.4%17.4%, 15.0% and 5.5%14.4% of our UAN sales, respectively.
Competition
We have experienced and expect to continue to meet significant levels of competition from current and potential competitors, many of whom have significantly greater financial and other resources. See “Risk Factors — Risks Related to Our Petroleum Business — We face significant competition, both within and outside of our industry. Competitors who produce their own supply of feedstocks, have extensive retail outlets, make alternative fuels or have greater financial resources than we do may have a competitive advantage over us” and “Risk Factors — Risks Related to Our Nitrogen Fertilizer Business — Our fertilizer products are global commodities, and we face intense competition from otherthe nitrogen fertilizer producers.”
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Petroleum Business
Our oil refinery in Coffeyville, Kansas ranks third in processing capacitybusiness’ ammonia sales, respectively, and fifth in refinery complexity, amongConAgra Fertilizer accounted for 18.7% of its UAN sales. During the seven mid-continent fuels refineries. The following table presents certain information about usthree months ended March 31, 2008, Brandt Consolidated Inc. and National Cooperative Refinery Association accounted for 32.3% and 9.6% of the six other major mid-continent fuel oil refineries with which we compete:
| | | | | | | | | | | | | |
| | | | | Crude Capacity
| | Solomon
|
| | | | | (barrels per
| | Complexity
|
Company | | Location | | calendar day) | | Index |
| |
| ConocoPhillips | | | Ponca City, OK | | | | 187,000 | | | | 12.5 | |
| Frontier Oil | | | El Dorado, KS | | | | 110,000 | | | | 13.3 | |
| CVR Energy | | | Coffeyville, KS | | | | 108,000 | | | | 10.0 | |
| Valero | | | Ardmore, OK | | | | 88,000 | | | | 11.3 | |
| NCRA | | | McPherson, KS | | | | 82,200 | | | | 14.1 | |
| Gary Williams Energy | | | Wynnewood, OK | | | | 52,500 | | | | 8.0 | |
| Sinclair | | | Tulsa, OK | | | | 50,000 | | | | 8.3 | |
| | | | | | | | | | | | | |
| Mid-continent Total: | | | | | | | 677,700 | | | | | |
| | | | | | | | | | | | | |
Source: Oilnitrogen fertilizer business’ ammonia sales, respectively, and Gas Journal. A Sunoco refinery located in Tulsa, Oklahoma was excluded from this table because it is not a stand-alone fuels refinery.
We compete with our competitors primarily on the basisConAgra Fertilizer accounted for 11.1% of price, reliability of supply, availability of multiple grades of products and location. The principal competitive factors affecting our refining operations are costs of crude oil and other feedstock costs, refinery complexity, refinery efficiency, refinery product mix and product distribution and transportation costs. The location of our refinery provides us with a reliable supply of crude oil and a transportation cost advantage over our competitors.
Our competitors include trading companies such as SemFuel, L.P., Western Petroleum, Center Oil, Tauber Oil Company, Morgan Stanley and others. In addition to competing refineries located in the mid-continent United States, our oil refinery also competes with other refineries located outside the region that are linked to the mid-continent market through an extensive product pipeline system. These competitors include refineries located near the U.S. Gulf Coast and the Texas Panhandle region.
Our refinery competition also includes branded, integrated and independent oil refining companies such as BP, Shell, ConocoPhillips, Valero, Sunoco and Citgo, whose strengths include their size and access to capital. Their branded stations give them a stable outlet for refinery production although the branded strategy requires more working capital and a much more expensive marketing organization.its UAN sales.
Nitrogen Fertilizer BusinessCompetition
Competition in the nitrogen fertilizer industry is dominated by price considerations. However, during the spring and fall application seasons, farming activities intensify and delivery capacity is a significant competitive factor. We maintainThe nitrogen fertilizer plant maintains a large fleet of rail cars and we seasonally adjustadjusts inventory to enhance ourits manufacturing and distribution operations.
Domestic competition, mainly from regional cooperatives and integrated multinational fertilizer companies, is intense due to customers’ sophisticated buying tendencies and production strategies that focus on cost and service. Also, foreign competition exists from producers of fertilizer products manufactured in countries with lower cost natural gas supplies. In certain cases, foreign producers of fertilizer who export to the United States may be subsidized by their respective governments. OurThe nitrogen fertilizer business’ major competitors include Koch Nitrogen, PCS, Terra and CF Industries, among others.all of which produce more UAN than the nitrogen fertilizer business does.
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OurThe nitrogen fertilizer plant’s main competition in ammonia marketing are Koch’s plants at Beatrice, Nebraska, Dodge City, Kansas and Enid, Oklahoma, as well as Terra’s plants in Verdigris and Woodward, Oklahoma and Port Neal, Iowa.
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Based on Fertecon and Blue Johnson research, ourdata regarding total U.S. demand for UAN and ammonia, we estimate that the nitrogen fertilizer plant’s UAN production representsin 2007 represented approximately 5.7%4.5% of the total U.S. demand. Thedemand and that the net ammonia produced and marketed at Coffeyville represents less than 1% of the total U.S. demand.
Seasonality
Because the nitrogen fertilizer business primarily sells agricultural commodity products, its business is exposed to seasonal fluctuations in demand for nitrogen fertilizer products in the agricultural industry. As a result, the nitrogen fertilizer business typically generates greater net sales and operating income in the spring. In addition, the demand for fertilizers is affected by the aggregate crop planting decisions and fertilizer application rate decisions of individual farmers who make planting decisions based largely on the prospective profitability of a harvest. The specific varieties and amounts of fertilizer they apply depend on factors like crop prices, farmers’ current liquidity, soil conditions, weather patterns and the types of crops planted.
Environmental Matters
Our businessThe petroleum and operationsnitrogen fertilizer businesses are subject to extensive and frequently changing federal, state and local laws and regulations relating to the protection of the environment. These laws, their underlying regulatory requirements and the enforcement thereof some of which are described below, impact our businesspetroleum and operationsnitrogen fertilizer businesses by imposing:
| | |
| | • | restrictions on operationsand/or the need to install enhanced or additional controls; |
| |
| | • | the need to obtain and comply with permits, licenses and authorizations; |
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| | • | liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities and off-site waste disposal locations; and |
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| | • | specifications for the products we market,manufactured and marketed by our petroleum and nitrogen fertilizer businesses, primarily gasoline, diesel fuel, UAN and ammonia. |
The petroleum refining industry is subject to frequent public and governmental scrutiny of its environmental compliance. As a result, theThe laws and regulations to which we are subject are often evolving and many of them have become more stringent or have become subject to more stringent interpretation or enforcement by federal and state agencies. The ultimate impact of complying with existing laws and regulations is not always clearly known or determinable due in part to the fact that our operations may change over time and certain implementing regulations for laws such as the Resource Conservation and Recovery Act or(the “RCRA”), the RCRA,federal Clean Water Act and the federal Clean Air Act have not yet been finalized, are underfrequently undergoing governmental or judicial review or are being revised. These regulations and other new hazardous or solid waste, air andor water quality standards andor stricter fuel regulations could result in increased capital, operating and compliance costs.
The principal environmental risks associated with our operationspetroleum and nitrogen fertilizer businesses are air emissions, releases of hazardous substances into the environment, and the treatment and discharge of wastewater. The legislative and regulatory programs that affect these areas are outlined below. For a discussion of the environmental impact of the 2007 flood and crude oil discharge, see “— Flood and Crude Oil Discharge — Crude Oil Discharge” and “— Flood and Crude Oil Discharge — EPA Administrative Order on Consent.”
The Federal Clean Air Act
The federal Clean Air Act and its underlyingimplementing regulations as well as the corresponding state laws and regulations that regulate emissions of pollutants into the air affect our petroleum operations and the nitrogen fertilizer business both directly and indirectly. Direct impacts may occur through Clean Air Actfederal and state air permitting requirementsand/or emission control requirements relating to specific
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air pollutants. The federal Clean Air Act indirectly affects our petroleum operations and the nitrogen fertilizer business by extensively regulating the air emissions of sulfur dioxide or (“SO2”), volatile organic compounds, nitrogen oxides and other compounds including those emitted by mobile sources, which are direct or indirect users of our products.
The Clean Air Act imposes stringent limits on air emissions, establishes a federally mandated permit program and authorizes civil and criminal sanctions and injunctions for any failure to comply. The Clean Air Act also establishes National Ambient Air Quality Standards, or NAAQS, that states must attain. If a state cannot attain the NAAQS (i.e., is in nonattainment), the state will be required to reduce air emissions to bring the state into attainment. A geographic area’s attainment status is based on the severity of air pollution. A change in the attainment status in the area where our facilities are located could necessitate the installation of additional controls. At the current time, all areas that we operate in are classified as attainment for NAAQS.
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There have been numerous other recently promulgated National Emission Standards for Hazardous Air Pollutants, NESHAP or MACT, including, but not limited to, the Organic Liquid Distribution MACT, the Miscellaneous Organic NESHAP, Gasoline Distribution Facilities MACT, Reciprocating Internal Combustion Engines MACT, Asphalt Processing MACT, Commercial and Institutional Boilers and Process Heaters standards. Some or all of these MACTthe standards promulgated pursuant to the federal Clean Air Act, or any future promulgations of MACT standards, may require the installation of controls or changes to our petroleum operations or the nitrogen fertilizer facilities in order to comply. If we are required to installnew controls or change ourchanges to operations are needed, the costs could be significant. These new requirements, other requirements of the federal Clean Air Act, or other presently existing or future environmental regulations could cause us to expend substantial amounts to complyand/or permit our refinery to produce products that meet applicable requirements.
Air Emissions. The regulation of air emissions under the federal Clean Air Act requires us to obtain various construction and operating permits and to incur capital expenditures for the installation of certain air pollution control devices at our refinery. Various regulations specific to, or that directly impact, our industry have been implemented, including regulations that seek to reduce emissions from refineries’ flare systems, sulfur plants, large heaters and boilers, fugitive emission sources and wastewater treatment systems. Some of the applicable programs are the Benzene Waste Operations NESHAP,various general and specific source standards under the National Emission Standard for Hazardous Air Pollutants (“NESHAP”), New Source Performance Standards and New Source Review, and Leak Detection and Repair.Review. We have incurred, and expect to continue to incur, substantial capital expenditures to maintain compliance with these and other air emission regulations.
The EPA recently embarked on a Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues — New Source Review, flaring, leak detection and repair, and the Benzene Waste Operations NESHAP. The Petroleum Refining Initiative has resulted in many refiners entering into consent decrees imposing civil penalties and requiring substantial expenditures for additional or enhanced pollution control. At this time, we do not know how, if at all, the Petroleum Refining Initiative will affect us. However, inIn March 2004, we entered into a Consent Decree with the EPAU.S. Environmental Protection Agency (the “EPA”) and the KDHEKansas Department of Health and Environment (the “KDHE”) to resolve air compliance concerns raised by the EPA and KDHE related to Farmland’s prior operation of our oil refinery. The Consent Decree covers some, but not all, of the Petroleum Refining Initiative’s marquee issues.
Under the Consent Decree, we agreed to install controls on certain process equipment and make certain operational changes at our refinery. As a result of our agreement to install certain controls and implement certain operational changes, the EPA and KDHE agreed not to imposeseek civil penalties, and provided a release from liability for Farmland’s alleged noncompliance with the issues addressed by the Consent Decree. Pursuant to the Consent Decree, in the short term, we have increased the use of catalyst additives to the fluid catalytic cracking unit at the facility to reduce emissions of SO2. We will beginbegan adding catalyst to reduce oxides of nitrogen or NOx,(“NOx”) in 2007.2008. In the long term, we will install controls to minimize both SO2 and NOx emissions, which under terms of the Consent Decree require that final controls be in place by January 1, 2011. In addition, pursuant to the Consent Decree, we assumed certain cleanup obligations at the Coffeyville refinery and the Phillipsburg terminal. We agreed to retrofit certain heaters at the refinery with Ultra Low NOx burners. All heater retrofits have been performedcompleted and we are currently verifying that the heaters meet the Ultra Low NOx standards required by the Consent Decree. The Ultra Low NOx heater technology is in widespread use throughout the industry. There are other permitting, monitoring, record-keeping and reporting requirements associated with the Consent Decree. The overall cost of complying with the Consent Decree is expected to be approximately $23$41 million, of which approximately $17$35 million is expected to be capital expenditures and which does not include the cleanup obligations. No penalties are expected to be imposed as a result
Over the course of the last several years, the EPA has embarked on a National Petroleum Refining Initiative alleging industry-wide noncompliance with four “marquee” issues: New Source Review, flaring, Leak Detection and Repair, and Benzene Waste Operations NESHAP. The Petroleum Refining Initiative has resulted in many refiners entering into consent decrees imposing civil penalties and requiring substantial expenditures for additional or enhanced pollution control. The EPA has indicated that it will seek all refiners to enter into “global settlements” pertaining to all “marquee” issues. Our current Consent Decree.
Fertilizer Plant Audit.Decree covers some, but not all, of the “marquee” issues. To the extent that we were to agree to enter into a “global settlement,” we believe our incremental capital exposure would be limited primarily to the retrofit and replacement of certain existing heaters and boilers over a five to seven year timeframe. We conducted an air permitting compliance audit ofalso would incur additional operating expenses to enhance our fertilizer plant pursuant to agreements with EPA and KDHE immediately after Immediate Predecessor acquired the fertilizer plant in 2004. The audit revealed that the fertilizer plant was not properly permitted under the Clean Air Act and its implementing regulations and corresponding Kansas environmental statutes and regulations. As a result, the fertilizer plant performed air modeling to demonstrate that the current
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emissions from the facility are in complianceflaring and leak detection and control programs. In addition, consistent with federal and state air quality standards, andother refiners that the air pollution controls that are in place are the controls that arehave entered into “global settlements,” we may be required to be in place. In the event that the EPA or KDHE determines that additional controls are required, we may incur significant expenditures to comply. The completion of this process requires that we submitpay a new permit application, which we have done. We are now awaiting the final permit approval from KDHE at which time we will file a Title V air operating permit application that will include the relevant terms and conditions of the new air permit.civil penalty.
Title V Air Permitting. The petroleum refinery is a “major source” of air emissions under the Title V permitting program of the federal Clean Air Act. A final Class I (major source) operating permit was issued for our oil refinery in August 2006. We are currently in the process of amending the Title V permit to include the recently approved expansion project permit and the continuous catalytic reformer permit.
The nitrogen fertilizer plant has agreed to file a new Title V operating air permit application because the voluntary fertilizer plant audit (described in more detail above) revealed that the fertilizer plant should be permitted as a “major source” of certain air pollutants. In the meantime, the fertilizer plant is operating under the Clean Air Act’s “application shield” (which protects permittees from enforcement while an operating permit is being issued as long as the permittee complies with the permit conditions contained in the permit application), the current construction permits, other KDHE approvals and the protections of the federal and state audit policies. Once the current air permit application is approved, we will file the finalamended its Title V permit application that willto contain all terms and conditions imposed under theits new Prevention of Significant Deterioration (“PSD”) permit and anyall other air permitsand/or approvals in place. We do not anticipate significant cost or difficulty in obtaining these permits. However, in the event thatTitle V operating air permit for the EPA or KDHE determines that additional controls are required, we may incur significant expenditures to comply.
nitrogen fertilizer plant. We believe that we hold all material air permits required to operate the Phillipsburg Terminal and our crude oil transportation company’s facilities.
Release Reporting
The release of hazardous substances or extremely hazardous substances into the environment is subject to release reporting of threshold quantities under federal and state environmental laws. Our petroleum operations and the nitrogen fertilizer business periodically experience releases of hazardous substances and extremely hazardous substances that could cause usour petroleum businessand/or the nitrogen fertilizer business to become the subject of a government enforcement action or third-party claims. We report such releases promptly to federal and state environmental agencies.
PriorThe nitrogen fertilizer facility experienced an ammonia release as a result of a malfunction in August 2007 and reported the excess ammonia emissions to the acquisitionEPA and KDHE. The EPA has investigated the release and has requested additional data. Our incident investigation related to the release indicates that the malfunction could not have been reasonably anticipated or avoided and we have forwarded our results to the EPA.
As a result of an inspection by OSHA following the August 2007 ammonia release OSHA issued citations against both the nitrogen fertilizer plant by Immediate Predecessorfacility and the refinery seeking penalties totaling $163,000. We have agreed to settle all allegations as a result of this incident with payment of a $163,000 penalty and review and, if necessary, implement improvements in 2004general health and during the periodsafety programs at each facility, which may include integrating the plant was owned by Immediate Predecessor, the facility experienced heat exchanger equipment deterioration at an unanticipated rate, resulting in upset/malfunction air releases of ammonia into the environment. We replaced the equipment in August 2004 with a new metallurgy design that also experienced an unanticipated deterioration rate. The new equipment was subsequently replaced in 2005 by a redesigned exchanger with upgraded metallurgy, which has operated without additional ammonia emissions. Other critical exchanger metallurgy was upgraded during our most recent July 2006 turnaround. We have reported the excess emissions of ammonia to EPAalarm and KDHE as part of an air permitting audit of the facility. Additional equipment, repairs to existing equipment, changes to current operations, government enforcement or third-party claims could result in significant expenditures and liability.notification systems.
Fuel Regulations
Tier II, Low Sulfur Fuels. The EPA interprets the Clean Air Act to authorize the EPA to require modifications in the formulation of the refined transportation fuel products we manufacture in order to limit the emissions associated with their final use. The EPA believes such limits are necessary to protect new automobile emission control systems that may be inhibited by sulfur in the fuel. For example, in In February 2000, the EPA promulgated the Tier II Motor Vehicle Emission Standards Final Rule
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for all passenger vehicles, establishing standards for sulfur content in gasoline. These regulations mandate that the sulfur content of gasoline at any refinery shall not exceed 30 ppm during any calendar year beginning January 1, 2006. TheseSuch compliant gasoline is referred to as Ultra Low Sulfur Gasoline (“ULSG”). Phase-in of these requirements began being phased in during 2004. In addition, in January 2001, the EPA promulgated its on-road diesel regulations, which required a 97% reduction in the sulfur content of diesel sold for highway use by June 1, 2006, with full compliance by January 1, 2010. The EPA adopted a rule for off-road diesel in May 2004. The off-road diesel regulations will generally require a 97% reduction in the sulfur content of diesel sold for off-road use by June 1, 2010. Such compliant diesel is referred to as Ultra Low Sulfur Diesel (“ULSD”). Our production of ULSG and ULSD made us eligible for significant tax benefits in 2007, and we expect to be eligible for significant tax benefits in 2008 as well.
Modifications have been and will continue to be required at our refinery as a result of the Tier II gasoline and low sulfur diesel standards. In February 2004 the EPA granted us approval under a “hardship waiver” that would deferdefers meeting final low sulfur Tier II gasoline standards until January 1, 2011 in exchange for ourand deferred meeting low sulfur highway diesel requirements byuntil January 1, 2007. We are currently incompleted the construction and startup phase of our Ultra Low Sulfur Diesel Hydrodesulfurization unit which utilizes technologyin late 2006 in accordance with widespread use throughout the industry. Based onconditions of the “hardship waiver.” We are currently continuing our preliminary estimates, we believe thatphased
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construction and startup of projects related to meeting our compliance date with ULSG standards and may agree to meet these standards one year early as described below. Compliance with the Tier II gasoline and on-road diesel standards required us to spend approximately $133 million during 2006 and approximately $103 million during 2007, and we estimate that compliance will require us to spend approximately $97 million during 2006 (most of which has already been spent), approximately $11 million during 2007 and approximately $12$68 million between 2008 and 2010. Changes in equipment or construction costs could require significantly greater expenditures.
In 2007, as a result of the flood, our refinery exceeded the required average gasoline sulfur standard mandated by the hardship waiver. We are re-negotiating provisions of the hardship waiver and have agreed in principal to meet the final low sulfur Tier II gasoline standards by January 1, 2010 (one year earlier than required under the hardship waiver) in consideration for the EPA’s agreement not to seek a penalty for the 2007 sulfur exceedance and higher gasoline sulfur limits for 2008 and 2009.
Methyl Tertiary Butyl Ether (MTBE).Greenhouse Gas Emissions
The United States Congress has considered various proposals to reduce greenhouse gas emissions, but none have become law, and presently, there are no federal mandatory greenhouse gas emissions requirements. While it is probable that Congress will adopt some form of federal mandatory greenhouse gas emission reductions legislation in the future, the timing and specific requirements of any such legislation are uncertain at this time. In the absence of existing federal regulations, a number of states have adopted regional greenhouse gas initiatives to reduce CO2 and other greenhouse gas emissions. In 2007, a group of Midwest states, including Kansas (where our refinery and the nitrogen fertilizer facility are located), formed the Midwestern Greenhouse Gas Accord, which calls for the development of acap-and-trade system to control greenhouse gas emissions and for the inventory of such emissions. However, the individual states that have signed on to the accord must adopt laws or regulations implementing the trading scheme before it becomes effective, and the timing and specific requirements of any such laws or regulations in Kansas are uncertain at this time.
In 2007, the U.S. Supreme Court decided that CO2 is an air pollutant under the federal Clean Air Act for the purposes of vehicle emissions. Similar lawsuits have been filed seeking to require the EPA previously required gasoline to contain a specified amountregulate CO2 emissions from stationary sources, such as our refinery and the fertilizer plant, under the federal Clean Air Act. Our refinery and the nitrogen fertilizer plant produce significant amounts of oxygenCO2 that are vented into the atmosphere. If the EPA regulates CO2 emissions from facilities such as ours, we may have to apply for additional permits, install additional controls to reduce CO2 emissions or take other as yet unknown steps to comply with these potential regulations. For example, we may have to purchase CO2 emission reduction credits to reduce our current emissions of CO2 or to offset increases in certain regions that exceed the National Ambient Air Quality Standards for either ozone or carbon monoxide. This oxygen requirement had been satisfied by adding to gasoline one of many oxygen-containing materials including, among others, methyl tertiary butyl ether, or MTBE. As a result of growing public concern regarding possible groundwater contamination resulting from the use of MTBE as a source of required oxygen in gasoline, MTBE has been banned for use as a gasoline additive. To the bestCO2 emissions associated with expansions of our knowledge, noneoperations.
Compliance with any future legislation or regulation of greenhouse gas emissions, if it occurs, may result in increased compliance and operating costs and may have a material adverse effect on our results of operations, financial condition, and the ability of the Successor,nitrogen fertilizer business to make distributions. In anticipation of the Immediate Predecessorpotential legislation or Farmland used MTBEregulation of greenhouse gas emissions, the nitrogen fertilizer business is looking into initiatives to reduce greenhouse gas emissions, particularly CO2, and is working with a company involved in our petroleum products. We cannot make any assurance asCO2 capture and storage systems to whether MTBE was addedtry to our petroleum products after those products left our facilitiesdevelop plans whereby the nitrogen fertilizer business may, in the future, either sell approximately 850,000 tons per year of high purity CO2 produced by the nitrogen fertilizer plant to oil and gas exploration and production companies to enhance oil recovery or whether MTBE-containing products were distributed through our pipelines.pursue an economic means of geologically sequestering such CO2. This project is currently in development, but, if completed, is expected to include either the direct sale of CO2 or the sale of verified emission reduction credits should the credits accrete value in the future due to the implementation of mandatory emissions caps for CO2.
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The Clean Water Act
The federal Clean Water Act of 1972 affects our petroleum operations and the nitrogen fertilizer business by regulating the treatment of wastewater and imposing restrictions on effluent dischargedischarges into, or impacting, navigable water. Regular monitoring, reporting requirements and performance standards are preconditions for the issuance and renewal of permits governing the discharge of pollutants into water. We maintainOur petroleum business maintains numerous discharge permits as required under the National Pollutant Discharge Elimination System program of the federal Clean Water Act and havehas implemented internal programs to oversee our compliance efforts. Our nitrogen fertilizer facility operates under pretreatment requirements and has a permit to discharge our process wastewater to the local publicly owned treatment works.
All of our facilities are subject to Spill Prevention, Control and Countermeasures or SPCC,(“SPCC”) requirements under the Clean Water Act. The SPCC rules were modified in 2002 with the modifications to go into effect in 2004. In 2004, certain requirements of the rule were extended. Changesextended, and additional modifications are expected. When the modifications to our operationsthe SPCC rule become final, we may be required to make capital expenditures in order to comply with the modified SPCC rule.rule; however, we do not anticipate that any such costs will be significant.
In addition, we are regulated under the Oil Pollution Act.Act of 1990 (the “Oil Pollution Act”). Among other requirements, the Oil Pollution Act requires the owner or operator of a tank vessel or facility to maintain an emergency oil response plan to respond to releases of oil or hazardous substances. We have developed and implemented such a plan for each of our facilities covered by the Oil Pollution Act. Also, in case of such releases, the Oil Pollution Act requires responsible parties to pay the resulting removal costs and damages, provides for substantial civil penalties, and authorizes the imposition of criminal and civil sanctions for violations. States where we have operations have laws similar to the Oil Pollution Act.
Wastewater Management. We have a wastewater treatment plant at our refinery permitted to handle an average flow of 2.2 million gallons per day. The facility uses a complete mix activated sludge or CMAS,(“CMAS”) system with three CMAS basins. The plant operates pursuant to a KDHE permit.
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We are also implementing a comprehensive spill response plan in accordance with the EPA rules and guidance.
Ongoing fuels terminal and asphalt plant operations at Phillipsburg generate only limited wastewater flows (e.g., boiler blowdown, asphalt loading rack condensate, groundwater treatment). These flows are handled in a wastewater treatment plant that includes a primary clarifier, aerated secondary clarifier, and a final clarifier to a lagoon system. The plant operates pursuant to a KDHE Water Pollution Control Permit. To control facility runoff, management implements a comprehensive Spill Response Plan. Phillipsburg also has a timely and current application on file with the KDHE for a separate storm water control permit.
Resource Conservation and Recovery Act (RCRA)
Our operations are subject to the RCRA requirements for the generation, treatment, storage and disposal of hazardous wastes. When feasible, RCRA materials are recycled instead of being disposed ofon-site or off-site. RCRA establishes standards for the management of solid and hazardous wastes. Besides governing current waste disposal practices, RCRA also addresses the environmental effects of certain past waste disposal operations, the recycling of wastes and the regulation of underground storage tanks containing regulated substances.
Waste Management. There are two closed hazardous waste units at the refinery and eight other hazardous waste units in the process of being closed pending state agency approval. In addition, one closed interim status hazardous waste landfarm located at the Phillipsburg terminal is under long-term post closure care.
We have set aside approximately $3.2 million in financial assurance for closure/post-closure care for hazardous waste management units at the Phillipsburg terminal and the Coffeyville refinery.
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Impacts of Past Manufacturing. We are subject to a 1994 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Coffeyville refinery. In accordance with the order, we have documented existing soil and ground water conditions, which require investigation or remediation projects. The Phillipsburg terminal is subject to a 1996 EPA administrative order related to investigation of possible past releases of hazardous materials to the environment at the Phillipsburg terminal, which operated as a refinery until 1991. The Consent Decree that we signed with the EPA and KDHE requires us to complete all activities in accordance with federal and state rules.rules and to maintain financial assurance (e.g., a bond or letter of credit) for the costs of doing so. See “— Financial Assurance,” below.
The anticipated remediation costs through 20102011 were estimated, as of September 8, 2006,March 31, 2008, to be as follows:follows (in millions):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | Total
| | | | | | | | | Total
| |
| | | Site
| | | | Total O&M
| | Estimated
| | | Site
| | | | Total O&M
| | Estimated
| |
| | | Investigation
| | Capital
| | Costs
| | Costs
| | | Investigation
| | | | Costs
| | Costs
| |
Facility | | Costs | | Costs | | Through 2010 | | Through 2010 | | | Costs | | Capital Costs | | Through 2011 | | Through 2011 | |
| |
| Coffeyville Oil Refinery | | $ | 0.5 | | | $ | — | | | $ | 1.0 | | | $ | 1.5 | | | $ | 0.3 | | | $ | — | | | $ | 1.1 | | | $ | 1.4 | |
| Phillipsburg Terminal | | | 0.3 | | | | — | | | | 1.9 | | | | 2.2 | | | | 0.3 | | | | — | | | | 1.9 | | | | 2.2 | |
| | | | | | | | | | | | | | | | | | | |
| Total Estimated Costs | | $ | 0.8 | | | $ | — | | | $ | 2.9 | | | $ | 3.7 | | | $ | 0.6 | | | $ | — | | | $ | 3.0 | | | $ | 3.6 | |
| | | | | | | | | | | | | | | | | | | |
These estimates are based on current information and could go up or down as additional information becomes available through our ongoing remediation and investigation activities. At this point, we have estimated that, over ten years starting in 2008, we will spend between $5.4$5.8 million and $6.8$6.3 million to remedy impacts from past manufacturing activity at the Coffeyville refinery and to address existing soil and groundwater contamination at the Phillipsburg terminal. It is possible that additional costs will be required after this ten year period.
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Financial Assurance. We were required in the Consent Decree to establish $15.0 million in financial assurance to cover the projected cleanup costs under the 1994 and 1996 EPA administrative orders described above, in the event we failed to fulfill ourclean-up obligations. In accordance with the Consent Decree, this financial assurance is partially secured by a bond posted by Original Predecessor, Farmland. We are replacing the financial assurance currently provided by Farmland on a quarterly basis and, so far, have replaced approximately $4.5 million. At this point, it is not clear what the amount of financial assurance will be when replaced. Although it may be significant, we do not expect it will be more than $15.0 million.
Environmental Insurance. We have entered into several environmental insurance policies as part of our overall risk management strategy. Our primary pollution legal liability policy provides us with an aggregate limit of $50.0$25.0 million subject to a $1.0$5.0 million self-insured retention. This policy covers cleanup costs resulting from pre-existing or new pollution conditions and bodily injury and property damage resulting from pollution conditions. It also includes a $25.0 million business interruption sub-limit subject to a ten day45-day waiting period. Our excess pollution legal liability policies provide us with up to an additional $50.0 million of aggregate limit. The excess pollution legal liability policies may not provide coverage until the $25.0 million of underlying limit available in the primary pollution legal liability policy has been exhausted. We also have a financial assurance policy linked to our pollution legal liability policy that provides a $4.0 million limit per pollution incident and an $8.0 million aggregate policy limit related specifically to closed RCRA units at the Coffeyville refinery and the Phillipsburg terminal. Each of these policies contains substantial exclusions; as such, we cannot guaranteethere can be no assurance that we will have coverage for all or any particular liabilities.
We also have For a cost cap remediation policydiscussion of our insurance policies that provides $25.0 million ofrelate to coverage for the cost of remediation exceeding $16.0 million, known as the attachment point, for the remediation program at the Coffeyville refinery2007 flood and the Phillipsburg terminal. The policy expires in 2014. In February 2006, we were notified that credit ratings for the cost cap remediation insurance carrier deteriorated below the approved thresholds in our current borrowing agreements. We obtained a waivercrude oil discharge, see “— Flood and consent from our lenders to replace the current carrier with a carrier with acceptable credit ratings. We have until October 26, 2006 to replace this carrier per the waiver and consent.Crude Oil Discharge — Insurance.”
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On September 7, 2006, we requested permanent relief in the requirement to provide the cost cap remediation policy as it is our opinion that the replacement insurance is not economical and that the $16.0 million attachment point likely will not be exceeded. We have not yet received a formal response on this issue from our lenders.
Financial Assurance. We were required in the Consent Decree to establish $15 million in financial assurance to cover the projected cleanup costs posed by the Coffeyville and Phillipsburg facilities in the event our company ceased to operate as a going concern. In accordance with the Consent Decree, this financial assurance is currently provided by a bond posted by Original Predecessor, Farmland. We will be required to replace the financial assurance currently provided by Farmland. If the financial assurance is not replaced by March 3, 2007, we must reimburse Farmland through eight equal quarterly payments beginning in April 2007. At this point, it is not clear what the amount of financial assurance will be when replaced. Although it may be significant, it is unlikely to be more than $15 million. The form of this financial assurance that will be required by EPA (cash, letter of credit, financial test, etc.) has not been determined.
Environmental Remediation
Under the Comprehensive Environmental Response, Compensation, and Liability Act or CERCLA,(“CERCLA”), RCRA, and related state laws, certain persons may be liable for the release or threatened release of hazardous substances. These persons include the current owner or operator of property where a release or threatened release occurred, any persons who owned or operated the property when the release occurred, and any persons who disposed of, or arranged for the transportation or disposal of, hazardous substances at a contaminated property. Liability under CERCLA is strict, retroactive and joint and several, so that any responsible party may be held liable for the entire cost of investigating and remediating the release of hazardous substances. The liability of a party is determined by the cost of investigation and remediation, the portion and toxicity of the hazardous substance(s) the party contributed, the number of solvent potentially responsible parties, and other factors.
As is the case with all companies engaged in similar industries, we face potential exposure from future claims and lawsuits involving environmental matters. These matters, includeincluding soil and water contamination, personal injury andor property damage allegedly caused by hazardous substances whichthat we, or potentially Farmland, manufactured, handled, used, stored, transported, spilled, released or disposed of. We cannot assure you that we will not become involved in future proceedings related to our release of hazardous or extremely hazardous substances or that, if we were held responsible for
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the risk of releases, spills, discharges, leaks, accidents, fires or other events and minimize the potential effects thereof. We are currently completing the additionstart-up of the final additions of a new $19$27 million refinery flare system that will replacereplaced any remaining atmospheric sumps in our refinery. We are also assessinghave assessed the potential impacts on building occupancy caused by the location and design of our refinery and fertilizer plant control rooms and operator shelters. We have relocated non-essential personnel and contractors away from the process areas and are currently constructing and installing permanent blast-proof operator control rooms and outside shelters. We expect the costs to upgrade or relocate these areas to be between $3$4 million and $5$6 million over the next two to five years. The current plan would consolidate
In 2007, OSHA began PSM inspections of all refineries under its jurisdiction as part of its National Emphasis Program (the “NEP”) following OSHA’s investigation of PSM issues relating to the refinery control boardsmultiple fatality explosion and equipment into a central control building that would also house operationsfire at the BP Texas City facility in 2005. Completed NEP inspections have resulted in OSHA levying significant fines and technical personnel and would lead to improved communication and efficiency for operationpenalties against most of the refinery.refineries inspected to date. At this time, our refinery has not been inspected in connection with OSHA’s NEP program. Although we believe that our PSM program is in substantial compliance with OSHA PSM regulations, an OSHA NEP inspection could result in the imposition of significant fines and penalties as well as significant additional capital expenditures related to PSM.
Emergency Planning and Response. We have an emergency response plan that describes the organization, responsibilities and plans for responding to emergencies in the facilities. This plan is communicated to local regulatory and community groups. We haveon-site warning siren systems and personal radios. We will continue to audit our programs and consider improvements in our management systems and equipment.
Security. We have a comprehensive security program to protect our refinery and the nitrogen fertilizer facility from unauthorized entry and exit and potential acts of terrorism. Recent changes in the U.S. Department of Homeland Security rules and requirements may require enhancements and improvements to our current program.
Community Advisory Panel (CAP).Panel. We have developed and continue to support ongoing discussions with the community to share information about our operations and future plans. Our CAPcommunity advisory panel includes wide representation of residents, business owners and local elected representatives for the city and county.
Employees
As of June 30, 2006, we had a total of 570March 31, 2008, 455 employees of which 401 were employed in our petroleum business, and 108110 were employed by ourthe nitrogen fertilizer business. The remaining 61business and 49 employees were employed at our offices in Sugar Land, Texas and Kansas City, Kansas.
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We entered into collective bargaining agreements which, coveras of March 31, 2008, covered approximately 38%42% of our employees (all of whom work in our petroleum business) with the Metal Trades Union and the United Steelworkers of America, whichAmerica. The collective bargaining agreements expire in March 2009. We believe that our relationship with our employees is excellent.good.
Prior to the consummation of our initial public offering, we entered into a services agreement with the Partnership and the managing general partner of the Partnership pursuant to which we agreed to provide certain management and other services to the Partnership, the managing general partner of the Partnership, and the nitrogen fertilizer business. The services we provide under the agreement include the following services, among others:
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| • | services by our employees as the Partnership’s corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve the Partnership on a shared, part-time basis only, unless we and the Partnership agree otherwise; |
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| • | administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
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| • | management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; |
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| • | recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions; |
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| • | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice; |
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| • | recommending the payment of distributions; and |
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| • | managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time. |
Personnel performing the actual day-to-day business and operations of the Partnership at the plant level are employed directly by the Partnership and its subsidiaries, which bear all personnel costs for these employees. We pay all compensation and benefits for our executive officers, including executive officers who perform services for the Partnership, and we are reimbursed by the managing general partner of the Partnership for a pro rata portion of such compensation and benefits based on the percentage of time each officer works for the Partnership. For more information on this services agreement, see “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.”
Properties
Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas. We lease approximately 22,000 square feet at that location. The following table contains certain information regarding our other principal properties:properties
| | | | | | | | |
Location | | Acres | | Own/Lease | | | Use |
| |
| Coffeyville, KS | | 440 | | | Own | | | Oil refinery, nitrogenfertilizer plant
and office buildings |
| Phillipsburg, KS | | 200 | | | Own | | | Terminal facility |
Montgomery County, KS
(Coffeyville (Coffeyville Station) | | 20 | | | Own | | | Crude oil storage |
Montgomery County, KS
(Broome (Broome Station) | | 20 | | | Own | | | Crude oil storage |
| Bartlesville, OK | | 25 | | | Own | | | Truck storage and
office buildings |
| Winfield, KS | | 5 | | | Own | | | Truck storage |
Cushing, OK (pending) | | 300185 | | | Own | | | Crude oil storage |
Cowley County, Kansas
(HooserKS (Hooser Station) | | 80 | | | Own | | | Crude oil storage |
| Holdrege, NE | | 7 | | | Own | | | Crude oil storage |
| Stockton, KS | | 6 | | | Own | | | Crude oil storage |
| Sugar Land, TX | | 22,000 (square feet) | | | Lease | | | Office space |
| Kansas City, KS | | 19,00018,400 (square feet) | | | Lease | | | Office space |
Our executive offices are located at 2277 Plaza Drive in Sugar Land, Texas. We lease approximately 22,000 square feet at that location. Rent under the lease is currently approximately $515,000 annually, plus operating expenses, increasing to approximately $550,000 in 2009. The lease expires in 2011. Rent under our lease for the Kansas City office space is approximately $268,000 annually, plus a portion of operating expenses and taxes. The lease expires in 2009. We expect that our current owned and leased facilities will be sufficient for our needs over the next twelve months.
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In January 2008, we transferred ownership of certain parcels of land, including land that the fertilizer plant is situated on, to the Partnership so that the Partnership would be able to operate the fertilizer plant on its own land. Additionally, in October 2007, we entered into a new cross easement agreement with the Partnership so that both we and the Partnership will be able to access and utilize each other’s land in certain circumstances in order to operate our respective businesses in a manner to provide flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other parties’ property. For more information on this cross-easement agreement, see “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.”
As of December 31, 2007, we had storage capacity for 769,000 barrels of gasoline, 1,068,000 barrels of distillates, 928,000 barrels of intermediates and 3,364,000 barrels of crude oil. The crude oil storage consisted of 674,000 barrels of refinery storage capacity, 520,000 barrels of field storage capacity and 2,170,000 barrels of storage at Cushing, Oklahoma.
Legal Proceedings
We are, and will continue to be, subject to litigation from time to time in the ordinary course of our business, including matters such as those described above under “— Environmental Matters.”Matters”. We are not party to any pending legal proceedings that we believe will have a material impact on our business.business, and there are no existing legal proceedings where we believe that the reasonably possible loss or range of loss is material.
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FLOOD AND CRUDE OIL DISCHARGE
Overview
During the weekend of June 30, 2007, torrential rains in southeastern Kansas caused the Verdigris River to overflow its banks and flood the city of Coffeyville. The river crested more than ten feet above flood stage, setting a new record for the river. Approximately 2,000 citizens and hundreds of homes throughout the city of Coffeyville were affected. Our refinery and the nitrogen fertilizer plant, both of which are located in close proximity to the Verdigris River, were severely flooded and were forced to conduct emergency shutdowns and evacuations. The majority of the refinery’s process units were under four to six feet of water and portions of the refinery’s tank farms and wastewater treatment area were covered with eight to ten feet of water. As a result, the refinery and nitrogen fertilizer facilities sustained major damage and required extensive repairs.
Property Damage and Lost Earnings
The refinery sustained damage to a large number of pumps, motors, tanks, control rooms and other buildings, electrical equipment and electronic controls, and required significantclean-up in the areas surrounding the water and wastewater treatment plants. We hired nearly 1,000 extra contract workers to help repair and replace damaged equipment. The refinery started operating its reformer on August 6, 2007 and began to charge crude oil to the facility on August 9, 2007. Substantially all of the refinery’s units were in operation by August 20, 2007.
The nitrogen fertilizer facility, situated on slightly higher ground, sustained less damage than the refinery. Bringing the nitrogen fertilizer plant back on line involved replacing or repairing 30% of all electric drives, repairing 60% of the plant’s motor control centers, refurbishing 100% of the plant’s distributive control systems and programmable logic controllers and repairing the main control room. The nitrogen fertilizer facility initiated startup at its production facility on July 13, 2007.
As of March 31, 2008, total third party costs to repair the refinery and fertilizer facilities were approximately $82.5 million and $4.0 million, respectively. In addition, we currently estimate that approximately $2.1 million in third party costs related to the repair of flood damaged property will be recorded in future periods. We are currently uncertain how much of these amounts we will be able to recover through insurance. See “— Insurance.”
Crude Oil Discharge
Because the Verdigris River rose so rapidly during the flood, much faster than predicted, our employees had to shut down and secure the refinery in six to seven hours, rather than the 24 hours typically needed for such an effort. Despite our efforts to secure the refinery prior to its evacuation as a result of the flood, we estimate that 1,919 barrels (80,600 gallons) of crude oil and 226 barrels of crude oil fractions were discharged from our refinery into the Verdigris River flood waters beginning on or about July 1, 2007. In particular, crude oil and its fractions were released from refinery storage tanks and the refinery sewer system. Crude oil was carried by floodwaters downstream from our refinery and into residential and commercial areas.
In response to the crude oil discharge, on July 1, 2007 we established an incident command center and assembled a team of environmental consultants and oil spill response contractors to manage our response to the crude oil discharge.
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| • | The O’BRIEN’S Group managed the overall process, including containment and recovery. The O’BRIEN’S Group is the largest provider of emergency preparedness and crisis management services to the energy and internal shipping industries. |
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| • | United States Environmental Services, LLC provided operations support. This firm is a full-service environmental contracting company specializing in environmental emergency response, |
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| | in-plant industrial services, contaminated site remediation, chemical/biological terrorism response, safety training and industrial hygiene. |
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| • | The Center for Toxicology and Environmental Health oversaw sampling, analysis and reporting for the operation. This firm specializes in toxicology, risk assessment, industrial hygiene, occupational health and response to emergencies involving the release or threat of release of chemicals. |
On July 2, 2007, the EPA dispatched additional oil spill response contractors to the site with the EPA’s mobile command post to monitor and coordinate pollution assessments related to the flooding and the crude oil discharge.
Beginning on or about July 2, 2007, the EPA’s oil spill response contractors and we began jointly conducting daily aerial overflights of the Coffeyville area and our refinery. On or about July 2, 2007, (a) crude oil from the refinery was observed to be in the flood waters surrounding the above-ground storage tanks located at our refinery and (b) oil was observed in the Verdigris River and in flood waters that had inundated a portion of the city of Coffeyville.
Representatives from the KDHE and the Oklahoma Department of Environmental Quality have also been heavily involved in the response to the oil discharge.
EPA Administrative Order on Consent
On July 10, 2007, we entered into an administrative order on consent (the “Consent Order”) with the EPA. As set forth in the Consent Order, the EPA concluded that the discharge of oil from our refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, we agreed to perform specified remedial actions to respond to the discharge of crude oil from our refinery.
Under the Consent Order, within 90 days after the completion of such remedial action, we will submit to the EPA for review and approval a final report summarizing the actions taken to comply with the Consent Order. We have worked with the EPA throughout the recovery process and we could be required to reimburse the EPA’s costs under the federal Oil Pollution Act. Except as otherwise set forth in the Consent Order, the Consent Order does not limit the EPA’s rights to seek other legal, equitable or administrative relief or action as it deems appropriate and necessary against us or from requiring us to perform additional activities pursuant to applicable law. Among other things, the EPA reserved the right to assess administrative penalties against usand/or to seek civil penalties against us. In addition, the Consent Order states that it is not a satisfaction of or discharge from any claim or cause of action against us or any person for any liability we or such person may have under statutes or the common law, including any claims of the United States, for penalties, costs and damages.
We expect to substantially complete remediation of the contamination caused by the crude oil discharge by July 31, 2008 and anticipate minor remedial actions thereafter. Total net costs recorded as of March 31, 2008 associated with remediation efforts and third party property damage incurred by the crude oil discharge are approximately $27.3 million. This amount is net of anticipated insurance recoveries of $21.4 million. In 2007, the Company received insurance proceeds of $10.0 million under its property insurance policy, $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge and $1.5 million under its builders’ risk policy. These amounts do not include potential fines or penalties which may be imposed by regulatory authorities or costs arising from potential natural resource damages claims (for which we are unable to estimate a range of possible costs at this time) or possible additional damages arising from lawsuits related to the flood.
Property Repurchase Program and Claims for Property Damage
On July 19, 2007 we commenced a program to purchase approximately 330 homes and certain other properties in connection with the flood and the crude oil discharge. We offered to purchase the
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property of approximately 330 residential landowners (with the consent and cooperation of the city of Coffeyville) for 110% of their pre-flood appraised value (to be established by appraisal conducted without consideration of the flood), without release or other waiver of any rights by the landowners, and without deduction for the greater harm unquestionably caused to these properties by the flood itself. As of March 31, 2008, 322 of these approximately 330 residential properties are under contract. We estimate that this program will cost approximately $17.5 million, excluding certain costs associated with remediation.
In addition, in early July 2007 we opened a claims center in Coffeyville and established a toll-free number to facilitate the recording and processing of claims for compensation by those who may have incurred property and other damages related to the oil discharge. Staff assisted local residents in filing claims related to the 2007 flood and crude oil discharge. We also offered a toll-free number at the claims call center which was answered 24 hours a day. Call center operators collected property owners’ information and forwarded it to claims adjustors. The claims adjustors contacted property owners to schedule appointments. Operators also directed callers to local, state and federal disaster response agencies for additional assistance. As of the date of this prospectus, we have adjusted most of these claims.
Litigation
As a result of the crude oil discharge, two putative class action lawsuits (one federal and one state) were filed against usand/or our subsidiaries in July 2007. The federal suit, Danny Dunham vs. Coffeyville Resources, LLC, et al., was filed in the United States District Court for the District of Kansas at Wichita (case number6:07-cv-01186-JTM-DWB). The state suit, Western Plains Alliance, LLC and Western Plains Operations, LLC v. Coffeyville Resources Refining & Marketing, LLC, was filed in the District Court of Montgomery County, Kansas (case number 07CV99I).
Plaintiff’s complaint in the federal suit alleged that the crude oil discharge resulted from our negligent operation of the refinery and that class members suffered unspecified damages, including damages to their personal and real property, diminished property value, lost full use and enjoyment of their property, lost or diminished business income and comprehensive remediation costs. The federal suit sought recovery under the federal Oil Pollution Act, Kansas statutory law imposing a duty of compensation on a party that releases any material detrimental to the soil or waters of Kansas, and the Kansas common law of negligence, trespass and nuisance. This suit was dismissed on November 6, 2007 for lack of subject matter jurisdiction, and no appeal was taken.
The state suit sought class certification under applicable law. The proposed class would have consisted of all persons and entities who own or have owned real property within the “contaminated area”, and all businessesand/or other entities located within the “contaminated area”. The Court conducted an evidentiary hearing on the issue of class certification on October 24 and 25, 2007 and ruled against class certification, leaving only the original two plaintiffs who have agreed, subject to final documentation, to settle their claims and dismiss the state lawsuit.
We recently received 16 notices of claims under the Oil Pollution Act from private claimants in an aggregate amount of approximately $4.4 million. No lawsuits related to these claims have yet been filed.
Insurance
During and after the time of the 2007 flood and crude oil discharge, Coffeyville Resources, LLC was insured under insurance policies that were issued by a variety of insurers and which covered various risks, such as damage to our property, interruption of our business, environmental cleanup
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costs, and potential liability to third parties for bodily injury or property damage. These coverages include the following:
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| • | Our primary property damage and business interruption insurance program provided $300 million of coverage for flood-related damage, subject to a deductible of $2.5 million per “occurrence” and a45-day waiting period for business interruption loss. While we believe that property insurance should cover substantially all of the estimated total physical damage to our property, our insurance carriers have cited potential coverage limitations and defenses that might preclude such a result. |
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| • | Our builders’ risk policy provided coverage for property damage to buildings in the course of construction. Flood-related loss or damage was subject to a $100,000 deductible and sub-limit of $50 million. |
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| • | Our environmental insurance coverage program provided coverage for bodily injury, property damage, and cleanup costs resulting from new pollution conditions. At the time of the flood, the program included a primary policy with a $25.0 million aggregate limit of liability. This policy was subject to a $1 million self-insured retention. In addition, at the time of the flood we had a $25.0 million excess policy that was triggered by exhaustion of the primary policy. The excess policy covered bodily injury and property damage resulting from new pollution conditions, but did not cover cleanup costs. |
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| • | Our umbrella and excess liability coverage program provided $100 million of coverage for claims in excess of $5.0 million and other applicable insurance for third-party claims of property damage and bodily injury arising out of the sudden and accidental discharge of pollutants. |
Coffeyville Resources, LLC promptly notified its insurers of the flood, the crude oil discharge, and related claims and lawsuits. We are in the process of submitting our claims to, responding to information requests from, and negotiating with the insurers with respect to costs and damages related to the 2007 flood and crude oil discharge. Our property insurers have raised a question as to whether our facilities are principally located in “Zone A” which is subject to a $10 million insurance limit for flood or “Zone B” which is subject to a $300 million insurance limit for flood. We have reached agreement with 32.5% of our property insurers that our facilities are principally located in Zone B. Our remaining property insurers have not, at this time, agreed to this position. In addition, our primary environmental liability insurance carrier has asserted that our pollution liability claims are for “cleanup” which is subject to a $10 million sub-limit, rather than “property damage” which is covered to the limits of the policy. The excess carrier has reserved its rights under the primary carrier’s position. While we will vigorously contest the primary carrier’s position, we believe that if that position were upheld, our umbrella and excess Comprehensive General Liability policies would continue to provide coverage for these claims. Although each insurer has reserved its rights under various policy exclusions and limitations and has cited potential coverage defenses, we are vigorously pursuing our insurance recovery claims. We expect that ultimate recovery will be subject to negotiation and, if negotiation is unsuccessful, litigation.
Our insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs we have incurred relating to the damages and losses suffered. This coverage, however, applies only to losses incurred after a business interruption of 45 days. Because both the refinery and the nitrogen fertilizer plant were restored to operation within this45-day period, a majority of the lost profits incurred because of the flood are unlikely to be paid by our business interruption insurance.
Financial Impact on Our Results
Total gross costs recorded due to the flood and related crude oil discharge that were included in our statement of operations for the year ended December 31, 2007 were approximately $146.8 million.
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Of these gross costs, approximately $101.9 million were associated with repair and other matters as a result of the flood damage to our facilities. Included in this cost was $7.6 million of depreciation for temporarily idled facilities, $6.1 million of salaries, $2.2 million of professional fees and $86.0 million for other repair and related costs. There were approximately $44.9 million of costs recorded for the year ended December 31, 2007 related to the third party and property damage remediation as a result of the crude oil discharge.
Total gross costs recorded due to the flood and related oil discharge that were included in our statement of operations for the three months ended March 31, 2008 were approximately $7.6 million. Of these gross costs for the three month period ended March 31, 2008, approximately $3.8 million were associated with repair and other matters as a result of the flood damage to our facilities. Included in this cost was $0.3 million of professional fees and $3.5 million for other repair and related costs. There were also $3.8 million of costs recorded related to the third party and property damage remediation as a result of the crude oil discharge. We anticipate that approximately $2.1 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods.
As of March 31, 2008, we had received insurance proceeds of $10.0 million under our property insurance policy, an additional $10.0 million under our environmental policies related to recovery of certain costs associated with the crude oil discharge and $1.5 million under our Builder’s Risk Insurance Policy. Although we believe that we will recover substantial additional sums under our insurance policies, we are not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of our claims. The difference between what we ultimately receive under our insurance policies compared to what has been recorded in our financial statements could be material to our financial statements. Ultimate recovery may require litigation. We could recover substantially less than our full claim.
Below is a summary of the gross cost and reconciliation of the insurance receivable as of March 31, 2008 (in millions):
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| | | Total Costs | | | | |
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| Total gross costs incurred | | $ | 154.5 | | | | | |
| Total insurance receivable | | | (107.2 | ) | | | | |
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| Net costs associated with the flood | | $ | 47.3 | | | | | |
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| | | Receivable
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| | | Reconciliation | |
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| Total insurance receivable | | $ | 107.2 | |
| Less insurance proceeds received | | | (21.5 | ) |
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| Insurance receivable | | $ | 85.7 | |
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MANAGEMENT
Executive Officers and Directors
Prior to this offering, our business was operated by Coffeyville Acquisition LLC and its subsidiaries. In connection with the offering, Coffeyville Acquisition LLC formed a wholly owned subsidiary, CVR Energy, Inc., which will own all of Coffeyville Acquisition LLC’s subsidiaries and which will conduct our business through its subsidiaries following this offering. The following table sets forth the names, positions and ages (as of June 30, 2006)the executive officers and directors of each person who has been anCVR Energy. We also indicate in the biographies below which executive officer or director of Coffeyville Acquisition LLCofficers and who will be an executive officer or directordirectors of CVR Energy Inc. upon completionalso hold similar positions with the managing general partner of this offering.the Partnership. Senior management of CVR Energy manages the Partnership pursuant to the services agreement described under “The Nitrogen Fertilizer Limited Partnership — Intercompany Agreements.” All of the named executive officers of CVR Energy listed below will devote all of their time to CVR Energy and its wholly-owned subsidiaries, except that certain of them will also devote a portion of their time to the management of the Partnership.
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Name | | Age | | | Position |
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| John J. Lipinski | | | 55 | 57 | | | Chairman of the Board of Directors, Chief Executive Officer President and DirectorPresident |
| Stanley A. Riemann | | | 5557 | | | Chief Operating Officer |
| James T. Rens | | | 4041 | | | Chief Financial Officer and Treasurer |
| Edmund S. Gross | | | 55 | 57 | | | Senior Vice President, General Counsel and Secretary |
| Daniel J. Daly, Jr. | | | 62 | | | Executive Vice President, Strategy |
| Robert W. Haugen | | | 4850 | | | Executive Vice President, Refining Operations |
| Wyatt E. Jernigan | | | 5456 | | | Executive Vice President, Crude Oil Acquisition and Petroleum Marketing |
| Kevan A. Vick | | | 5254 | | | Executive Vice President and Fertilizer General Manager Nitrogen Fertilizer |
| Christopher G. Swanberg | | | 4850 | | | Vice President, Environmental, Health and Safety |
Wesley ClarkScott L. Lebovitz | | | 6032 | | | Director |
Scott LebovitzRegis B. Lippert | | | 3168 | | | Director |
| George E. Matelich | | | 5052 | | | Director |
| Steve A. Nordaker | | | 61 | | | Director |
| Stanley de J. Osborne | | | 3537 | | | Director |
| Kenneth A. Pontarelli | | | 3637 | | | Director |
| Mark E. Tomkins | | | 52 | | | Director |
John J. Lipinskihas served as our chairman of the board since October 2007, our chief executive officer and president and a member of our board of directors since September 2006, and as chief executive officer and president and a director of Coffeyville Acquisition LLC since June 24, 2005.2005 and chief executive officer and president of Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC since October 2007. Since October 2007, Mr. Lipinski has more than 34also served as the chief executive officer, president and a director of the managing general partner of the Partnership. Mr. Lipinski has over 35 years of experience in the petroleum refining and nitrogen fertilizer industries. He began his career with Texaco Inc. In 1985, Mr. Lipinski joined The Coastal Corporation, eventually serving as Vice President of Refining with overall responsibility for Coastal Corporation’s refining and petrochemical operations. Upon the merger of Coastal with El Paso Corporation in 2001, Mr. Lipinski was promoted to Executive Vice President of Refining and Chemicals, where he was responsible for all refining, petrochemical, nitrogen basednitrogen-based chemical processing, and lubricant operations, as well as the corporate engineering and construction group. Mr. Lipinski left El Paso in 2002 and became an independent management consultant. In 2004, he became a Managing Director and Partner of Prudentia Energy, an advisory and management firm. Mr. Lipinski graduated from Stevens Institute of Technology with a Bachelor of Engineering (Chemical) and received a Juris Doctor degree from Rutgers University School of Law.
Stanley A. Riemannhas served as chief operating officer of our company since September 2006, chief operating officer of Coffeyville Acquisition since June 2005, chief operating officer of
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Coffeyville Resources since February 2004 and its predecessorschief operating officer of Coffeyville Acquisition II and Coffeyville Acquisition III since March 3, 2004.October 2007. Since October 2007 Mr. Riemann has also served as the chief operating officer of the managing general partner of the Partnership. Prior to joining our company in MarchFebruary 2004, Mr. Riemann held various positions associated with the Crop Production and Petroleum Energy Division of Farmland Industries, Inc.for over 29 years, including, most recently, Executive Vice President of Farmland Industries and President of Farmland’s Energy and Crop Nutrient Division. In this capacity, he was directly responsible for managing the petroleum refining operation and all domestic fertilizer operations, which included the Trinidad and Tobago nitrogen fertilizer operations. His leadership also extended to managing Farmland’s interests in SF Phosphates in Rock Springs, Wyoming and Farmland Hydro, L.P., a phosphate production operation in Florida, and managing all company-wide transportation assets and services. On May 31, 2002, Farmland Industries, Inc. filed for Chapter 11 bankruptcy protection. Mr. Riemann served as a board member and board chairman on several industry organizations including the Phosphate Potash Institute, the Florida Phosphate Council, and the International Fertilizer Association. He currently serves on the Boardboard of The Fertilizer Institute. Mr. Riemann received a bachelor of scienceB.S. from the University of Nebraska and an MBAM.B.A. from Rockhurst University.
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James T. Renshas served as chief financial officer and treasurer of our company since September 2006, chief financial officer and its predecessorstreasurer of Coffeyville Acquisition since March 3, 2004.June 2005, chief financial officer and treasurer of Coffeyville Resources since February 2004 and chief financial officer and treasurer of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. Since October 2007, Mr. Rens has also served as chief financial officer and treasurer of the managing general partner of the Partnership. Before joining our company, Mr. Rens was a consultant to the Original Predecessor’s majority shareholder from November 2003 to March 2004, assistant controller at Koch Nitrogen Company from June 2003, which was when Koch acquired the majority of Farmland’s nitrogen fertilizer business, to November 2003 and Director of Finance of Farmland’s Crop Production and Petroleum Divisions from January 2002 to June 2003. From May 1999 to January 2002, Mr. Rens was Controllercontroller and chief financial officer of Farmland Hydro L.P. Mr. Rens has spent 15over 19 years in various accounting and financial positions associated with the fertilizer and energy industry. Mr. Rens received a Bachelor of ScienceB.S. degree in accounting from Central Missouri State University.
Edmund S. Grosshas served as senior vice president, general counsel and secretary of our company since October 2007, senior vice president, general counsel and its predecessorssecretary of Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007, vice president, general counsel and secretary of our company since September 2006, secretary of Coffeyville Acquisition since June 2005, and general counsel and secretary of Coffeyville Resources since July 2004. Since October 2007 Mr. Gross has also served as the senior vice president, general counsel, and secretary of the managing general partner of the Partnership. Prior to joining Coffeyville Resources, Mr. Gross was Of Counsel at Stinson Morrison Hecker LLP in Kansas City, Missouri from 2002 to 2004, was Senior Corporate Counsel with Farmland Industries, Inc. from 1987 to 2002 and was an associate and later a partner at Weeks,Thomas & Lysaught, a law firm in Kansas City, Kansas, from 1980 to 1987. Mr. Gross received a Bachelor of Arts degreeB.A. in history from Tulane University, a Juris DoctorJ.D. from the University of Kansas and an MBAM.B.A. from the University of Kansas.
Daniel J. Daly, Jr. has been our executive vice president, strategy since December 2007 and was our Senior Vice President, Administration and Controls from September 2006 through December 2007 and our Vice President, Accounting and Administration from June 2005 through August 2006. From December 2004 to June 2005 Mr. Daly was self-employed as a consultant in mergers & acquisitions. From 1978 to 2001 Mr. Daly worked at Coastal Corporation, first as Manager of Transportation and Supply Operations and then as Controller, Refining Division and Vice President and Controller, Refining and Marketing. Following the merger of Coastal with El Paso in 2001, Mr. Daly served as Vice President and Controller of Tosco Corporation from January 2001 to December 2001. Mr. Daly received a B.S. in commerce from St. Louis University.
Robert W. Haugenjoined our business on June 24, 2005 and has served as executive vice president, refining engineering and constructionoperations at our company since September 2006 and as executive vice
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president — engineering & construction at Coffeyville Resources since June 24, 2005. Since October 2007 Mr. Haugen has also served as executive vice president, refining operations at Coffeyville Acquisition LLC since April 2006.and Coffeyville Acquisition II. Mr. Haugen brings 25 years of experience in the refining, petrochemical and nitrogen fertilizer business to our company. Prior to joining us, Mr. Haugen was a Managing Director and Partner of Prudentia Energy, an advisory and management firm focused on mid-stream/midstream/downstream energy sectors, from January 2004 to June 2005. On leave from Prudentia, he served as the Senior Oil Consultant to the Iraqi Reconstruction Management Office for the U.S. Department of State. Prior to joining Prudentia Energy, Mr. Haugen served in numerous engineering, operations, marketing and management positions at the Howell Corporation and at the Coastal Corporation. Upon the merger of Coastal and El Paso in 2001, Mr. Haugen was named Vice President and General Manager for the Coastal Corpus Christi Refinery, and later held the positions of Vice President of Chemicals and Vice President of Engineering and Construction. Mr. Haugen received a B.S. in Chemical Engineeringchemical engineering from the University of Texas.
Wyatt E. Jerniganhas served as executive vice president, of crude oil acquisition and petroleum marketing at our company since September 2006 and as executive vice president — crude & feedstocks at Coffeyville Acquisition LLCResources since June 24, 2005. Since October 2007 Mr. Jernigan has also served as executive vice president, crude oil acquisition and petroleum marketing at Coffeyville Acquisition and Coffeyville Acquisition II. Mr. Jernigan has 30 years of experience in the areas of crude oil and petroleum products related to trading, marketing, logistics and business development. Most recently, Mr. Jernigan was Managing Director with Prudentia Energy, an advisory and management firm focused on mid-stream/downstream energy sectors, from January 2004 to June 2005. Most of his career was spent with Coastal Corporation and El Paso, where he held several positions in crude oil supply, petroleum marketing and asset development, both domestic and international. Following the merger between Coastal Corporation and El Paso in 2001, Mr. Jernigan assumed the role of Managing Director for Petroleum Markets Originations. Mr. Jernigan attended Virginia Wesleyan College, majoring in Sociology,sociology, and has training in petroleum fundamentals from the University of Texas.
Kevan A. Vickhas served as executive vice president and fertilizer general manager of Coffeyville Resources Nitrogen Fertilizers Manufacturing at our company since September 2006, andsenior vice president at Coffeyville Resources Nitrogen Fertilizers since February 27, 2004 and executive vice president and fertilizer general manager of Coffeyville Acquisition LLCIII since March 3, 2004.October 2007. Since October 2007 Mr. Vick has also served as executive vice president and fertilizer general manager of the managing general partner of the Partnership. He has served on the board of directors of Farmland MissChem Limited in Trinidad and SF Phosphates. He has nearly 30 years of experience in the Farmland organization and is one of the most highly respected executivesan experienced executive in the nitrogen fertilizer industry, known for both his technical expertise and his in-depth knowledge of the commercial marketplace. Prior to joining Coffeyville Acquisition LLC,Resources, he was general manager of nitrogen manufacturing at Farmland from January 2001 to February 2004. Mr. Vick received a bachelor of scienceB.S. in chemical engineering from the University of Kansas and is a licensed professional engineer in Kansas, Oklahoma and Iowa.
Christopher G. Swanberghas served as vice president, environmental, health and safety at our company since September 2006, as vice president, environmental, health and safety at Coffeyville Resources LLC since June 24, 2005.2005 and as vice president, environmental, health and safety at Coffeyville Acquisition II and Coffeyville Acquisition III since October 2007. Since October 2007 Mr. Swanberg has also served as vice president, environmental, health and safety at the managing general partner of the Partnership. He has
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served in numerous management positions in the petroleum refining industry such as Manager, Environmental Affairs for the refining and marketing division of Atlantic Richfield Company (ARCO), and Manager, Regulatory and Legislative Affairs for Lyondell-Citgo Refining. Mr. Swanberg’s experience includes technical and management assignments in project, facility and corporate staff positions in all environmental, safety and health areas. Prior to joining Coffeyville Resources, he was Vice Presidentvice president of Sage Environmental Consulting, an environmental consulting firm focused on petroleum refining and petrochemicals, from September 2002 to June 2005
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and Senior HSE Advisor of Pilko & Associates, LP from September 2000 to September 2002. Mr. Swanberg received a B.S. in Environmental Engineering Technologyenvironmental engineering technology from Western Kentucky University and an MBAM.B.A. from the University of Tulsa.
Wesley ClarkScott L. Lebovitzhas been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLCII and Coffeyville Acquisition III since September 20, 2005. Since March 2003 he has been the Chairman and Chief Executive Officer of Wesley K. Clark & Associates, a business services and development firm based in Little Rock, Arkansas. Mr. ClarkOctober 2007. He was also serves as senior advisor to GS Capital Partners V Fund, L.P. From March 2001 to February 2003 he was a Managing Director of the Stephens Group Inc. From July 2000 to March 2001 he was a consultant for Stephens Group Inc. Prior to that time, Mr. Clark served as the Supreme Allied Commander of NATO andCommander-in-Chief for the United States European Command and as the Director of the Pentagon’s Strategic Plans and Policy operation. Mr. Clark retired from the United States Army as a four-star general in July 2000 after 38 years in the military and received many decorations and honors during his military career. Mr. Clark is a graduate of the United States Military Academy and studied as a Rhodes Scholar at the Magdalen College at the University of Oxford. Mr. Clark is a director of Argyle Security Acquisition Corp.
Scott Lebovitzhas been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLCfrom June 2005 until October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since June 24, 2005.October 2007. Mr. Lebovitz is a Vice Presidentmanaging director in the Merchant Banking Division of Goldman, Sachs & Co. Mr. Lebovitz joined Goldman, Sachs & Co. in 1997.1997 and became a managing director in 2007. He is a director of Energy Future Holdings Corp. and Village Voice Media Holdings, LLC. He received his B.S. in Commercecommerce from the University of Virginia.
Regis B. Lipperthas been a member of our board since June 2007. He was also a member of the board of directors of Coffeyville Acquisition from June 2007 until October 2007. He is the founder, principal shareholder and a director of INTERCAT, Inc., a specialty chemicals company which primarily develops, manufactures, markets and sells specialty catalysts used in petroleum refining. Mr. Lippert serves as president and chief executive officer of INTERCAT, Inc. and its affiliate companies and is a Managing Director of INTERCAT Europe B.V. Mr. Lippert is also a director of Indo Cat Private Limited, an Indian company which is part of a joint venture between INTERCAT, Inc. and Indian Oil Corporation Limited. Prior to founding INTERCAT, Mr. Lippert served from 1981 to 1985 as President, Chief Executive Officer and a director of Katalistiks, Inc., a manufacturer of fluid cracking catalysts which ultimately became a subsidiary of Union Carbide Corporation. From 1979 to 1981, Mr. Lippert was an Executive Vice President with Catalysts Recovery, Inc. In this capacity he was responsible for developing the joint venture which ultimately formed Katalistiks. From 1963 to 1979, Mr. Lippert was employed by Engelhard Minerals and Chemical Co., where he attained the position of Director of Sales and Marketing/Catalysts. Mr. Lippert attended Carnegie-Mellon University where he studied metallurgy. He is a member of the National Petroleum Refiners Association.
George E. Matelichhas been a member of our board of directors since September 2006, a member of the board of directors of Coffeyville Acquisition since June 2005 and a member of the board of directors of Coffeyville Acquisition LLCIII since June 24, 2005.October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since October 2007. Mr. Matelich has been a Managing Directormanaging director of Kelso & Company since 1990.1989. Mr. Matelich has been affiliated with Kelso since 1985. Mr. Matelich is a Certified Public Accountantcertified public accountant and holds a Certificate in Management Consulting. Mr. Matelich received a B.A. in business administration from the University of Puget Sound and an M.B.A. (Finance and Business Policy) from the Stanford Graduate School of Business. He is a director of Global Geophysical Services, Inc., Shelter Bay Energy Inc. and Waste Services, Inc. Mr. MatelichHe is also a Trustee of the University of Puget Sound.Sound and serves on the National Council of the American Prairie Foundation.
Steve A. Nordakerhas been a member of our board since June 2008. He has served as senior vice president, finance of Energy Capital Group Holdings LLC, a development company dedicated to building, owning and operating gasification and IGCC units for the refining, petrochemical and fertilizer industries, since June 2004. Mr. Nordaker has also worked as a financial consultant for various companies in the areas of acquisitions, divestitures, restructuring and financial matters since January 2002. From 1996 through 2001, he was a managing director at J.P. Morgan Securities/JPMorgan Chase Bank in the global chemicals group and global oil & gas group. From 1992 to 1995, he was a managing director in the Chemical Bank worldwide energy, refining and petrochemical group. From 1982 to 1992, Mr. Nordaker served in numerous banking positions in the energy group at Texas Commerce Bank. Mr. Nordaker was Manager of Projects for the Frantz Company, an engineering consulting firm, from 1977 through 1982 and worked as a Chemical Engineer for UOP, Inc. from 1968 through 1977. Mr. Nordaker received a B.S. in chemical engineering from South Dakota School of Mines and Technology and an M.B.A. from the University of Houston.
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Stanley de J. Osbornehas been a member of our board of directors since September 2006, a member of the board of directors of Coffeyville Acquisition since June 2005 and a member of the board of directors of Coffeyville Acquisition LLCIII since June 24, 2005.October 2007. He has also been a member of the board of directors of the managing general partner of the Partnership since October 2007. Mr. Osborne has beenwas a Vice President of Kelso & Company from 2004 through 2007 and has been a managing director since 2004.2007. Mr. Osborne has been affiliated with Kelso since 1998. Prior to joining Kelso, Mr. Osborne was an Associate at Summit Partners. Previously, Mr. Osborne was an Associate in the Private Equity Group and an Analyst in the Financial Institutions Group at J.P. Morgan & Co. He received a B.A. in Government from Dartmouth College. Mr. Osborne is a director of Custom Building Products, Inc., Global Geophysical Services, Inc., Karat Acquisition LLC, Shelter Bay Energy Inc. and Traxys S.A.
Kenneth A. Pontarellihas been a member of our board of directors since September 2006 and a member of the board of directors of Coffeyville Acquisition LLCII and Coffeyville Acquisition III since October 2007. He has also been a director of the managing general partner of the Partnership since October 2007. He also was a member of the board of directors of Coffeyville Acquisition from June 24, 2005.2005 until October 2007. Mr. Pontarelli is a partner managing director in the Merchant Banking Division of Goldman, Sachs & Co. Mr. Pontarelli joined Goldman, Sachs & Co. in 1992 and became a managing director in 2004. He is a director of CCS, Inc., Cobalt International Energy, L.P., an oilEnergy Future Holdings Corp., Knight Holdco LLC, and gas exploration and development company, Horizon Wind Energy LLC, a developer, owner and operator of wind power projects, and NextMedia Group,Kinder Morgan, Inc., a privately owned radio broadcasting and outdoor advertising company. He received a B.A. from Syracuse University and an M.B.A. from Harvard Business School.
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Mark E. Tomkinshas been a member of our board since January 2007. He also was a member of the board of directors of Coffeyville Acquisition from January 2007 until October 2007. Mr. Tomkins has served as the senior financial officer at several large companies during the past ten years. He was Senior Vice President and Chief Financial Officer of Innovene, a petroleum refining and chemical polymers business and a subsidiary of British Petroleum, from May 2005 to January 2006, when Innovene was sold to a strategic buyer. From January 2001 to May 2005 he was Senior Vice President and Chief Financial Officer of Vulcan Materials Company, a publicly traded construction materials and chemicals company. From August 1998 to January 2001 Mr. Tomkins was Senior Vice President and Chief Financial Officer of Chemtura (formerly GreatLakes Chemical Corporation), a publicly traded specialty chemicals company. From July 1996 to August 1998 he worked at Honeywell Corporation as Vice President of Finance and Business Development for its polymers division and as Vice President of Finance and Business Development for its electronic materials division. From November 1990 to July 1996 Mr. Tomkins worked at Monsanto Company in various financial and accounting positions, including Chief Financial Officer of the growth enterprises division from January 1995 to July 1996. Prior to joining Monsanto he worked at Cobra Corporation and as an auditor in private practice. Mr. Tomkins received a B.S. degree in business, with majors in Finance and Management, from Eastern Illinois University and an M.B.A from Eastern Illinois University and is a certified public accountant. Mr. Tomkins is a director of W.R. Grace & Co. and Elevance Renewable Sciences, Inc.
Board of Directors
Our board of directors consists of sixeight members. The current directors are included above. Our directors are elected annually to serve until the next annual meeting of stockholders or until their successors are duly elected and qualified.
Prior to the completion of this offering, ourOur board will havehas an audit committee, a compensation committee, and a nominating and corporate governance committee and a conflicts committee. Our board of directors has determined that we are a “controlled company” under the rules of ,the New York Stock Exchange, and, as a result, will qualify for, and may rely on, exemptions from certain corporate governance requirements of the .New York Stock Exchange. Pursuant to the “controlled company” exception to the board of directors and committee composition requirements, we are exempt from the rules that require that (a) our board of directors be comprised of a majority of “independent directors,” (b) our compensation committee be comprised
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solely of “independent directors” and (c) our nominating and corporate governance committee be comprised solely of “independent directors” as defined under the rules of the New York Stock Exchange. The controlled company exemption does not modify the independence requirements for the audit committee. The Sarbanes-Oxley Act and the New York Stock Exchange rules require that our audit committee be composed entirely of independent directors, except that our audit committee is only required to have a majority of independent directors until October 22, 2008. The audit committee currently has three members, two of which are independent directors. Thus, the composition of our audit committee satisfies the independence requirements of the New York Stock Exchange and the Sarbanes-Oxley Act. Steve A. Nordaker and Mark E. Tomkins are the independent directors currently serving on the audit committee. Our board has affirmatively determined that Messrs. Steve A. Nordaker and Mark E. Tomkins are independent directors under the rules of the SEC and the NYSE. We do not believe that our reliance on the exemption that allows our audit committee to consist only of a majority of independent directors until October 22, 2008 will adversely affect the ability of our audit committee to act independently and to satisfy applicable independence requirements.
Audit Committee. OurThe members of the audit committee will be comprisedare Messrs. Mark Tomkins, Steve A. Nordaker, and Stanley de J. Osborne. Mr. Tomkins is chairman of Messrs. , ,the audit committee. Our board of directors has determined that Mr. Tomkins qualifies as an “audit committee financial expert.” Our board of directors has also determined that Mr. Nordaker and .Mr. Tompkins are “independent directors” as discussed above. The audit committee’s responsibilities will beare to review the accounting and auditing principles and procedures of our company with a view to providing for the safeguard of our assets and the reliability of our financial records by assisting the board of directors in monitoring our financial reporting process, accounting functions and internal controls; to oversee the qualifications, independence, appointment, retention, compensation and performance of our independent registered public accounting firm; to recommend to the board of directors the engagement of our independent accountants; to review with the independent accountants the plans and results of the auditing engagement; and to oversee “whistle-blowing” procedures and certain other compliance matters.
Compensation Committee. OurThe members of the compensation committee will be comprisedare Messrs. George E. Matelich, Steve A. Nordaker, Kenneth Pontarelli and Mark Tomkins. Mr. George E. Matelich is the chairman of Messrs. , , and .the compensation committee. The principal responsibilities of the compensation committee will beare to establish policies and periodically determine matters involving executive compensation, recommend changes in employee benefit programs, grant or recommend the grant of stock options and stock awards and provide counsel regarding key personnel selection. A subcommittee of the compensation committee consisting of Messrs. Nordaker and Tomkins will make stock and option awards to the extent deemed necessary or advisable for regulatory purposes. See “Compensation Discussion and Analysis.”
Nominating and Corporate Governance Committee. OurThe members of the nominating and corporate governance committee will be comprisedare Messrs. Scott L. Lebovitz, Stanley de J. Osborne, John J. Lipinski and Regis B. Lippert. Mr. Scott L. Lebovitz is the chairman of Messrs. , ,the nominating and .corporate governance committee. The principal duties of the nominating and corporate governance committee will beare to recommend to the board of directors proposed nominees for election to the board of directors by the stockholders at annual meetings and to develop and make recommendations to the board of directors regarding corporate governance matters and practices.
Conflicts Committee. The members of the conflicts committee are Messrs. Steve A. Nordaker and Mark Tomkins. The principal duties of the conflicts committee are to determine, in accordance with the conflicts of interests policy adopted by our board of directors, if the resolution of a conflict of interest between CVR Energy and our subsidiaries, on the one hand, and the Partnership, the Partnership’s managing general partner or any subsidiary of the Partnership, on the other hand, is fair and reasonable to us.
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Compensation Committee Interlocks and Insider Participation
Our compensation committee is comprised of Messrs. George E. Matelich, Steve A. Nordaker, Kenneth A. Pontarelli and Mark E. Tomkins. Mr. Matelich is a managing director of Kelso & Company and Mr. Pontarelli is a partner managing director in the Merchant Banking Division of Goldman, Sachs & Co. For a description of the Company’s transactions with certain affiliates of Kelso & Company and certain affiliates of Goldman, Sachs & Co., see “Certain Relationships and Related Party Transactions — Transactions with the Goldman Sachs Funds and the Kelso Funds” below.
Mr. John J. Lipinski, our chairman of the board and chief executive officer, servedis also a director of and serves on the compensation committee of Coffeyville Acquisition LLC during 2005 and 2006.INTERCAT, Inc., a privately held company of which Regis B. Lippert, who serves as a director on our board, is the chief executive officer. Otherwise, no interlocking relationship exists between our board of directors or compensation committee and the board of directors or compensation committee of any other company.
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DirectorCOMPENSATION DISCUSSION AND ANALYSIS
Executive Compensation
Non-employeeOverview
The compensation committee of the board of directors who dooversees companywide compensation practices and has specifically reviewed, developed and administered executive compensation programs and made recommendations to the board of directors of Coffeyville Acquisition LLC (prior to our initial public offering) and CVR Energy (following our initial public offering) on compensation matters. Messrs. George E. Matelich, Kenneth Pontarelli and John J. Lipinski served as members of Coffeyville Acquisition LLC’s committee during 2006 and prior to our initial public offering. Following our initial public offering, our board of directors established a compensation committee for CVR Energy comprised of Messrs. George E. Matelich (as chairperson), Kenneth Pontarelli, Wesley Clark and Mark Tomkins, which took over the duties of the compensation committee of the board of directors of Coffeyville Acquisition LLC. As of June 2008, Messrs. George E. Matelich (as chairperson), Steve A. Nordaker, Kenneth Pontarelli and Mark Tomkins are the members of our compensation committee. For purposes of this Compensation Discussion and Analysis, the “board of directors” and the “compensation committee” refer to the board of directors and compensation committee of Coffeyville Acquisition LLC prior to our initial public offering and CVR Energy following our initial public offering. The definitions of certain defined terms used in this Compensation Discussion and Analysis, including Phantom Unit Plan I, Phantom Unit Plan II, phantom points, phantom service points, phantom performance points, common units, profits interests, override units, operating units and value units, among others, are contained in the section of this prospectus entitled “Glossary of Selected Terms.”
The executive compensation philosophy of the compensation committee is threefold:
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| • | To align the executive officers’ interest with that of the stockholders and stakeholders, which provides long-term economic benefits to the stockholders; |
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| • | To provide competitive financial incentives in the form of salary, bonuses, and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and |
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| • | To maintain a compensation program whereby the executive officers, through exceptional performance and equity ownership, will have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders. |
The compensation committee reviews and makes recommendations to the board of directors regarding our overall compensation strategy and policies, with the full board of directors having the final authority on compensation matters. The board of directors may from time to time delegate to the compensation committee the authority to take actions on specific compensation matters or with respect to compensation matters for certain employees or officers. In the past, there has been no such delegation, but our board of directors may delegate to the compensation committee, for example, in order to comply with Section 16 of the Exchange Act or Section 162(m) of the Internal Revenue Code of 1986 when those laws require actions by outside or non-employee directors, as applicable.Rule 16b-3 issued under Section 16 of the Exchange Act provides that transactions between an issuer and its officers or directors involving issuer securities may be exempt from Section 16(b) of the Exchange Act if it meets certain requirements, one of which is approval by a committee of the board of directors of the issuer consisting of two or more non-employee directors. Section 162(m) of the Internal Revenue Code limits deductions by publicly held corporations for compensation paid to its “covered employees” (i.e., its chief executive officer and next four highest compensated officers) to the extent that the employee’s compensation for the taxable year exceeds $1,000,000. This limit does not work for entities affiliated with us are entitledapply to receive an annual retainer“qualified performance-based compensation”, which requires, among other things, satisfaction of $40,000. In addition, alla performance goal that is established by a committee of the board of directors are reimbursed for travel expenses and otherout-of-pocket costs incurred in connection with their attendance at meetings.consisting of two or more outside directors.
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The compensation committee (1) develops, approves and oversees policies relating to compensation of our chief executive officer and other executive officers, (2) discharges the board’s responsibility relating to the establishment, amendment, modification, or termination of our 2007 Long Term Incentive Plan, the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) (the “Phantom Unit Plan I”) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (the “Phantom Unit Plan II”), health and welfare plans, incentive plans, defined contribution plans (401(k) plans), and any other benefit plan, program or arrangement which we sponsor or maintain and (3) discharges the responsibilities of the override unit committee of the board of directors.
Specifically, the compensation committee reviews and makes recommendations to the board of directors regarding annual and long-term performance goals and objectives for the chief executive officer and our other senior executives; reviews and makes recommendations to the board of directors regarding the annual salary, bonus and other incentives and benefits, direct and indirect, of the chief executive officer and our senior executives; reviews and authorizes the company to enter into employment, severance or other compensation agreements with the chief executive officer and other senior executives; administers our executive incentive plans, including the Phantom Unit Plan I and the Phantom Unit Plan II; establishes and periodically reviews perquisites and fringe benefits policies; reviews annually the implementation of our company-wide incentive bonus program; oversees contributions to our 401(k) plan; and performs such duties and responsibilities as may be assigned by the board of directors to the compensation committee under the terms of any executive compensation plan, incentive compensation plan or equity-based plan and as may be assigned to the compensation committee with respect to the issuance and management of the override units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.
The compensation committee has regularly scheduled meetings concurrent with the board of directors meetings and additionally meets at other times as needed throughout the year. Frequently issues are discussed via teleconferencing. The chief executive officer, while a member of the compensation committee prior to our becoming a public company, did not participate in the determination of his own compensation, thereby avoiding any potential conflict of interest. However, he actively provided and will continue to provide guidance and recommendations to the committee regarding the amount and form of the compensation of the other executive officers and key employees. During 2006 and prior to our becoming a public company, given that the compensation committee consisted of senior representatives of the Goldman Sachs Funds and the Kelso Funds, as well as our chief executive officer, the board did not change or reject decisions made by the compensation committee.
Compensation paid to executive officers is closely aligned with our performance on both a short-term and long-term basis. Compensation is structured competitively in order to attract, motivate and retain executive officers and key employees and is considered crucial to our long-term success and the long-term enhancement of stockholder value. Compensation is structured to ensure that the executive officers’ objectives and rewards are directly correlated to our long-term objectives and the executive officers’ interests are aligned with those of stockholders. To this end, the compensation committee believes that the most critical component of compensation is equity compensation.
The following discusses in detail the foundation underlying and the drivers of our executive compensation philosophy, and also how the related decisions are made. Qualitative information related to the most important factors utilized in the analysis of these decisions is described.
Elements of Compensation
The three primary components of the compensation program are salary, an annual cash incentive bonus, and equity awards. Executive officers are also provided with benefits that are generally available to our salaried employees.
While these three components are related, we view them as separate and analyze them as such. The compensation committee believes that equity compensation is the primary motivator in
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attracting and retaining executive officers. Salary and cash incentive bonuses are viewed as secondary; however, the compensation committee views a competitive level of salary and cash bonus as critical to retaining talented individuals.
Base Salary
We fix the base salary of each of our executive officers at a level that we believe enables us to hire, motivate and retain individuals in a competitive environment and to reward satisfactory individual and company performance. In determining its recommendations for salary levels, the compensation committee takes into account peer group pay and individual performance.
With respect to our peer group, management, through the chief executive officer, provides the compensation committee with information gathered through a detailed annual review of executive compensation programs of other publicly and privately held companies in our industry, which are similar to us in size and operations (among other factors). In 2007, management reviewed and provided information to the compensation committee regarding the salary, bonus and other compensation amounts paid to named executive officers in respect of 2006 for the following independent refining companies, which we view as members of our peer group: Frontier Oil Corporation, Holly Corporation and Tesoro Corporation. Management also reviewed the following fertilizer businesses for executives focused on our fertilizer business: CF Industries Holdings Inc. and Terra Industries, Inc. It then averaged these peer group salary levels over a number of years to develop a range of salaries of similarly situated executives of these companies, and used this range as a factor in determining base salary (and overall cash compensation) of the named executive officers. Management also reviewed the differences in levels of compensation among the named executive officers of this peer group, and used these differences as a factor in setting a different level of salary and overall compensation for each of our named executive officers based on their relative positions and levels of responsibility.
With respect to individual performance, the compensation committee considered, among other things, the following specific achievements over the past 12 months with respect to Mr. Lipinski.
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| • | Flood Response. Mr. Lipinski directed the Company’s successful response to an unprecedented flood which devastated portions of the city of Coffeyville during the weekend of June 30, 2007 and closed down our refinery and the nitrogen fertilizer plant. The flood also resulted in a crude oil discharge from our refinery into the Verdigris River that required an immediate environmental response. Under Mr. Lipinski’s leadership, the refinery was restored to full operation in approximately six weeks, and the fertilizer plant, situated on higher ground, returned to full operation in approximately 18 days. In addition, Mr. Lipinski oversaw our efforts to work closely with the EPA and Kansas and Oklahoma regulators to review and analyze the environmental effects of the crude oil discharge and coordinate a property repurchase project in which we purchased approximately 300 homes from citizens of Coffeyville at their pre-flood values (or greater). This effort contributed to a successful outcome in our defense of two class action lawsuits. |
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| • | Initial Public Offering. Mr. Lipinski supervised the initial filing of our registration statement with the Securities and Exchange Commission in September 2006 and the consummation of our initial public offering in October 2007. The initial public offering process required a large amount of time and attention due to the turnaround in the first quarter of 2007, the decision to move our nitrogen fertilizer operations into a limited partnership structure, and the flood which occurred during the weekend of June 30, 2007. We ultimately listed our shares of common stock on the New York Stock Exchange and sold 23 million shares in the offering at an initial price of $19.00 per share. |
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| • | Business Expansion. Mr. Lipinski directed the Company’s growth strategy beginning in 2005, which included our refinery expansion project during 2006 and 2007 and the fertilizer plant UAN expansion project that commenced in 2007. Nearly every process unit at the refinery was involved in the refinery expansion project, which was consummated in the fourth quarter of |
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| | 2007. Our refinery throughput rates, averaging less than 90,000 bpd prior to June 2005, averaged over 110,000 bpd of crude during the fourth quarter of 2007, a record rate for our refinery. In addition, the blend of crudes was optimized to accommodate larger volumes of heavy sour crude. We processed more than 21,000 bpd of heavy sour crude in the fourth quarter of 2007, as compared with 2,700 bpd of heavy sour crude in the first quarter of 2006. Part of this project also included the addition of a new 24,000 bpd continuous catalytic reforming (“CCR”) unit which replaced an older technology unit two-thirds its size. The new CCR increased reforming capacity and also over time will produce more hydrogen, which over time will reduce our refinery’s dependence on the nitrogen fertilizer business for hydrogen purchases. The fertilizer plant UAN expansion project is expected to enable the nitrogen fertilizer plant to consume substantially all of its net ammonia production in the production of UAN, historically a higher margin product than ammonia. We estimate that it will result in an approximately 50% increase in the fertilizer plant’s annual UAN production. |
With respect to individual performance of Messrs. Riemann, Rens, Haugen and Daly, the compensation committee considered, among other things, management’s immediate and effective response to the June 2007 flood, the successful completion of our initial public offering in October 2007 and the expansion of our refinery’s capacity as evidenced by achievement of record throughput rates in the fourth quarter of 2007.
Each of the named executive officers has an employment agreement which sets forth his base salary. Salaries are reviewed annually by the compensation committee with periodic informal reviews throughout the year. Adjustments, if any, are usually made on January 1st of the year immediately following the review. In the fourth quarter of 2006, the compensation committee determined that Mr. Haugen’s base salary should be increased from $225,000 to $275,000 due to his increased responsibilities with our Company. The base salaries of Mr. Lipinski, Mr. Riemann and Mr. Rens were not adjusted at that time. The compensation committee most recently reviewed the level of cash salary and bonus for each of the executive officers in November 2007 and noted certain changes of responsibilities and promotions. Individual performance, the practices of our peer group of companies and changes in an executive officer’s status were considered, and each measurement was given relatively equal weight. The compensation committee recommended that the board of directors increase the 2008 salaries of Messrs. Lipinski (to $700,000 from $650,000), Riemann (to $375,000 from $350,000) and Rens (to $300,000 from $250,000), respectively, effective January 1, 2008, due to the increase in the cost of living and in order align their total compensation with compensation paid by companies in our peer group. Prior to October 23, 2007, Mr. Daly did not have an employment agreement with the Company. His base salary of $215,000 for 2007 was increased to $220,000 effective January 1, 2008 pursuant to the terms of the October 23, 2007 employment agreement. Mr. Haugen’s salary for 2008 remained at $275,000.
In addition, the compensation committee determined that no equity awards should be made to the named executive officers in connection with our initial public offering in 2007. However, the compensation committee may elect to make restricted stock grants, option grants or other equity grants during 2008 in its discretion. In addition, Coffeyville Acquisition III LLC, which owns the managing general partner of the Partnership, made limited equity grants of interests in Coffeyville Acquisition III LLC to the executive officers in 2007.
Annual Bonus
We use information about total cash compensation paid by members of our peer group of companies, the composition of which is discussed above, in determining both the level of bonus award and the ratio of salary to bonus because we believe that maintaining a level of bonus and a ratio of fixed salary (which is fixed and guaranteed) to bonus (which may fluctuate) that is in line with those of our competitors is an important factor in retaining the executives. The compensation committee also desires that a significant portion of our executive officers’ compensation package be at risk. That is, a portion of the executive officers’ overall compensation would not be guaranteed and would be
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determined based on individual and company performance. With respect to individual performance, the compensation committee considered the specific achievements of our named executive officers, as described above.
Our program provides for greater potential bonus awards as the authority and responsibility of a position increase. Our chief executive officer has the greatest percentage of his compensation at risk in the form of a discretionary bonus. Bonuses are determined based on our analysis of the total compensation packages for executive officers in our peer group. Our named executive officers retain a significant percentage of their compensation package at risk in the form of potential discretionary bonuses.
Bonuses may be paid in an amount equal to the target percentage, less than the target percentage or greater than the target percentage based on current year performance as recommended by the compensation committee. The performance determination takes into account overall operational performance, financial performance, factors affecting shareholder value including growth initiatives, and the individual’s personal performance. The determination of whether the target bonus amount should be paid is not based on specific metrics, but rather a general assessment of how the business performed as compared to the business plan developed for the year. Due to the nature of the business, financial performance alone may not dictate or be a fair indicator of the performance of the executive officers. Conversely, financial performance may exceed all expectations, but it could be due to outside forces in the industry rather than true performance by an executive that exceeds expectations. In order to take this mismatch into consideration and to assess the executive officers’ performance on their own merits, the compensation committee makes an assessment of the executive officer’s performance separate from the actual financial performance of the company, although such measurement is not based on any specific metrics.
The compensation committee reviewed the individualized performance and company performance as compared to expectations for the year ended December 31, 2007. Under their employment agreements, the 2007 target bonuses were the following percentages of salary for each of the following: Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann (200%), Mr. Haugen (120%) and Mr. Daly (80%). The bonuses in respect of 2007 performance were greater than target for Messrs. Lipinski and Rens due to their significant and continuous involvement in our initial public offering, which was consummated in October 2007, and due to their effective leadership role in and their coordination of the effective response to the flood that occurred during the weekend of June 30, 2007. Bonuses in respect of 2007 performance were less than target for Messrs. Riemann and Haugen because of a review of how the business performed as compared to our business plan developed for the year. Mr. Daly’s bonus was approximately equivalent to his target bonus amount. Under their employment agreements, the 2008 target bonuses will be the following percentages of salary for each of the following: Mr. Lipinski (250%), Mr. Rens (120%), Mr. Riemann (200%), Mr. Haugen (120%) and Mr. Daly (80%).
Annual cash incentive bonuses for our named executive officers are established as part of their respective individual employment agreements. Each of these employment agreements provides that the executive will receive an annual cash performance bonus determined in the discretion of the board of directors, with a target bonus amount specified as a percentage of salary for that executive officer based on individualized performance goals and company performance goals. In connection with the review of peer company compensation practices with respect to total cash compensation paid as described above, in November 2007, the compensation committee did not adjust the future target percentage for the performance-based annual cash bonus for executive officers as the Committee felt such targets were comparable to, and appropriate with respect to, its peer companies.
Equity
We use equity incentives to reward long-term performance. The issuance of equity to executive officers is intended to generate significant future value for each executive officer if the company’s
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performance is outstanding and the value of the company’s equity increases for all stockholders. The compensation committee believes that this also promotes long-term retention of the executive. The equity incentives were negotiated to a large degree at the time of the acquisition of our business in June 2005 (with additional units that were not originally allocated in June 2005 issued in December 2006) in order to bring the executive officers’ compensation package in line with executives at private equity portfolio companies, based on the private equity market practices at that time.
The greatest share of total compensation to the chief executive officer and other named executive officers (as well as selected senior executives and key employees) is in the form of equity: common units in our two largest stockholders, Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, override units within Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and common and override units in Coffeyville Acquisition III LLC, the entity which owns the managing general partner of the Partnership which holds the nitrogen fertilizer business. Any financial obligations related to such common units and override units reside with the issuer of such units and not with CVR Energy. Separately, Coffeyville Resources, LLC, a subsidiary of CVR Energy, issued phantom points to certain members of management, and any financial obligations related to such phantom points are the obligations of CVR Energy. The total number of such awards is detailed in this prospectus and was approved by the board of directors.
The limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC provide the methodology for payouts for most of this equity based compensation. In general terms, the agreements provide for two classes of interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC: (1) common units and (2) profits interests, which are called override units (and consist of both operating units and value units). Each of the named executive officers has a capital account under which his balance is increased or decreased to reflect his allocable share of net income and gross income of Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, the capital that the named executive officer contributed in exchange for his common units, distributions paid to such named executive officer and his allocable share of net loss and items of gross deduction. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC may make distributions to their members to the extent that the cash available to them is in excess of the business’ reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds. All cash payable pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC will be paid by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively, and will not be paid by CVR Energy. Although CVR Energy is required to recognize a compensation expense with respect to such awards, CVR Energy also records a contribution to capital with respect to these awards, and as a result, there is no cash effect on CVR Energy.
The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) (which we refer to as the Phantom Unit Plan I) works in correlation with the methodology established by the Coffeyville Acquisition LLC limited liability company agreement and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (which we refer to as the Phantom Unit Plan II) works in correlation with the methodology established by the Coffeyville Acquisition II LLC limited liability company agreement.
The limited liability company agreement of Coffeyville Acquisition III LLC provides for two classes of interests in Coffeyville Acquisition III LLC: (1) common units and (2) profits interests, which are called override units. Each of the named executive officers has a capital account under which his balance is increased or decreased to reflect his allocable share of net income and gross income of Coffeyville Acquisition III LLC, the capital that the named executive officer contributed, distributions paid to such named executive officer and his allocable share of net loss and items of gross deduction. Coffeyville Acquisition III LLC may make distributions to its members to the extent that the cash available to it is in excess of the business’ reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds.
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All issuances of override units and phantom points made through December 31, 2007 were made at what the board of directors determined to be their fair value on their respective grant dates. For a more detailed description of these plans, please see “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC”, “— Executive Officers’ Interests in Coffeyville Acquisition III LLC”, and “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”, below.
Additionally, there was a pool of override units under the Coffeyville Acquisition LLC limited liability company agreement that had not been issued as of December 2006. It was the intent that, upon a filing of a registration statement, the unallocated override units in the pool would be issued. The compensation committee recommended that all remaining override units in the pool available be issued to John J. Lipinski on December 29, 2006. The compensation committee made its decision and recommendation to the board of directors to grant Mr. Lipinski these additional units based on his accomplishments (and made the decision and recommendation without any input from Mr. Lipinski). Mr. Lipinski has been and will continue to be instrumental in positioning the company to become more competitive and in increasing the capacity of the refinery operations through his negotiating and obtaining favorable crude oil pricing, as well as in helping to gain access to capital in order to expand overall operations of both segments of our business. The increased value and growth of the business is directly attributable to the actions and leadership that Mr. Lipinski has provided for the overall executive management group.
Additionally, due to the significant contributions of Mr. Lipinski as reflected above, in December 2006 the compensation committee awarded him for his services 0.1044200 shares in Coffeyville Refining & Marketing, Inc. and 0.2125376 shares in Coffeyville Nitrogen Fertilizers, Inc. This approximated 0.31% and 0.64% of each company’s total shares outstanding, respectively, at that time. The shares were issued to compensate him for his exceptional performance related to the operations of the business. In connection with the formation of Coffeyville Refining & Marketing Holdings, Inc. in August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. Prior to our becoming a public company in October 2007, these shares were exchanged for 247,471 shares of common stock in CVR Energy at an equivalent fair market value.
We also established a stock incentive plan in connection with our initial public offering in October 2007. No awards have been established at this time for the chief executive officer or other named executive officers. In keeping with the compensation committee’s stated philosophy, such awards will be intended to help achieve the compensation goals necessary to run our business. As stated above, the compensation committee may elect to make awards under this plan in 2008 at its discretion.
Other Forms of Compensation
Each of our executive officers has a provision in his employment agreement providing for certain severance benefits in the event of termination without cause. These severance provisions are described in the “Employment Agreements and Other Arrangements” section below. The severance arrangements were all negotiated with the original employment agreements between the executive officer and the company. There are no change of control arrangements, but the compensation committee believed that there needed to be some form of compensation upon certain events of termination of services as is customary for similar companies.
As a general matter, we do not provide a significant number of perquisites to named executive officers.
Compensation Policies and Philosophy
Ours is a commodity business with high volatility and risk where earnings are not only influenced by margins, but also by unique, innovative and aggressive actions and business practices on the part of the executive team. The compensation committee routinely reviews financial and operational
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performance compared to our business plan, positive and negative industry factors, and the response of the senior management team in dealing with and maximizing operational and financial performance in the face of otherwise negative situations. Due to the nature of our business, performance of an individual or the business as a whole may be outstanding; however, our financial performance may not depict this same level of achievement. The financial performance of the company is not necessarily reflective of individual operational performance. These are some of the factors used in setting executive compensation. Specific performance levels or benchmarks are not necessarily used to establish compensation; however, the compensation committee takes into account all factors to make a subjective determination of related compensation packages for the executive officers.
The compensation committee has not adopted any formal or informal policies or guidelines for allocating compensation between long-term and current compensation, between cash and non-cash compensation, or among different forms of compensation other than its belief that the most crucial component is equity compensation. The decision is strictly made on a subjective and individual basis considering all relevant facts.
For compensation decisions, including decisions regarding the grant of equity compensation relating to executive officers (other than our chief executive officer and chief operating officer), the compensation committee typically considers the recommendations of our chief executive officer.
In recommending compensation levels and practices, our management reviews peer group compensation practices based on publicly available data. The analysis is done in-house in its entirety and is reviewed by executive officers who are not members of the compensation committee. The analysis is based on public information available through proxy statements and similar sources. Because the analysis is almost always performed based on prior year public information, it may often be somewhat outdated. We have not historically and at this time do not intend to hire or rely on independent consultants to analyze or prepare formal surveys for us. We do receive certain unsolicited executive compensation surveys; however, our use of these is limited as we believe we need to determine our baseline based on practices of other companies in our industry.
Because we are now a public company, Section 162(m) of the Internal Revenue Code limits the deductibility of compensation in excess of $1 million paid out to our executive officers unless specific and detailed criteria are satisfied. We believe that it is in our best interest to deduct compensation paid to our executive officers. We will consider the anticipated tax treatment to the company and our executive officers in the review and determination of the compensation payments and incentives. No assurance, however, can be given that the compensation will be fully deductible under Section 162(m).
Nitrogen Fertilizer Limited Partnership
A number of our executive officers, including our chief executive officer, chief operating officer, chief financial officer, general counsel, executive vice president/general manager for nitrogen fertilizer, and vice president, environmental, health and safety, serve as executive officers for both our company and the Partnership. These executive officers receive all of their compensation and benefits from us, including compensation related to services for the Partnership, and are not paid by the Partnership or its managing general partner. However, the Partnership or the managing general partner must reimburse us pursuant to a services agreement for the time our executive officers spend working for the Partnership. The percentage of each named executive officer’s compensation that represents the services provided to the Partnership in 2007 are approximately as follows: John J. Lipinski (25%), Stanley A. Riemann (40%), James T. Rens (35%), Robert W. Haugen (5%) and Daniel J. Daly, Jr. (10%).
We have entered into a services agreement with the Partnership and its managing general partner in which we have agreed to provide management services to the Partnership for the operation of the nitrogen fertilizer business. Under this agreement, any of the Partnership, its managing general partner or Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, are required to pay
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us (i) all costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share must be determined by us on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs; and (iv) various other administrative costs in accordance with the terms of the agreement. Either we or the managing general partner of the Partnership may terminate the agreement upon at least 90 days notice.
Summary Compensation Table
The following table sets forth certain information with respect to compensation for the yearyears ended December 31, 20052006 and December 31, 2007 earned by our chief executive officer, formerour chief executivefinancial officer and our fourthree other most highly compensated executive officers as of December 31, 2005.2007. In this prospectus, we refer to these individuals as our named executive officers.
Summary Compensation Table
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| | Incentive Plan
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Name and Principal Position | | Year | | Salary | | Bonus(1) | | Compensation | | Year | | Salary | | Bonus(1) | | Awards(3) | | Compensation(1)(4) | | Compensation(5) | | Total |
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| John J. Lipinski | | | 2005 | | | | 315,000 | | | | 1,336,301 | | | | 2,633,925 | (2) | | | 2007 | | | $ | 650,000 | | | $ | 1,850,000 | | | | — | | | | — | | | $ | 12,189,955 | (6) | | $ | 14,689,955 | |
| Chief Executive Officer | | | | | | | | | | | | | | | 2006 | | | $ | 650,000 | | | $ | 1,331,790 | | | $ | 4,326,188 | | | $ | 487,500 | | | $ | 5,007,935 | (7) | | $ | 11,803,413 | |
| Philip L. Rinaldi | | | 2005 | | | | 180,385 | | | | — | | | | 382,599 | (3) | |
| Former Chief Executive Officer(4) | | | | | | | | | | | | | |
| James T. Rens | | | | 2007 | | | $ | 250,000 | | | $ | 400,000 | | | | — | | | | — | | | $ | 2,761,144 | (8) | | $ | 3,411,144 | |
| Chief Financial Officer | | | | 2006 | | | $ | 250,000 | | | $ | 205,000 | | | | — | | | $ | 130,000 | | | $ | 695,316 | (9) | | $ | 1,280,316 | |
| Stanley A. Riemann | | | 2005 | | | | 329,410 | | | | 896,012 | | | | 1,178,595 | (5) | | | 2007 | | | $ | 350,000 | | | $ | 722,917 | (2) | | | — | | | | — | | | $ | 4,911,011 | (10) | | $ | 5,983,928 | |
| Chief Operating Officer | | | | | | | | | | | | | | | 2006 | | | $ | 350,000 | | | $ | 772,917 | (2) | | | — | | | $ | 210,000 | | | $ | 943,789 | (11) | | $ | 2,276,706 | |
| Kevan A. Vick | | | 2005 | | | | 183,061 | | | | 307,931 | | | | 609,641 | (6) | |
Executive Vice President
General Manager
Nitrogen Fertilizer | | | | | | | | | | | | | |
| James T. Rens | | | 2005 | | | | 211,346 | | | | 269,971 | | | | 609,641 | (7) | |
| Chief Financial Officer | | | | | | | | | | | | | |
| Wyatt E. Jernigan | | | 2005 | | | | 116,376 | | | | 340,515 | | | | 609,641 | (8) | |
Executive Vice President
Crude Oil Acquisition and
Petroleum Marketing | | | | | | | | | | | | | |
| Robert W. Haugen | | | | 2007 | | | $ | 275,000 | | | $ | 230,000 | | | | — | | | | — | | | $ | 2,822,978 | (12) | | $ | 3,327,978 | |
| Executive Vice President, | | | | 2006 | | | $ | 225,000 | | | $ | 205,000 | | | | — | | | $ | 117,000 | | | $ | 695,471 | (13) | | $ | 1,242,471 | |
| Refining Operations | | | | | | | | | | | | | | | | | | | | | | |
| Daniel J. Daly, Jr. | | | | 2007 | | | $ | 215,000 | | | $ | 200,000 | | | | — | | | | — | | | $ | 2,355,059 | (14) | | $ | 2,770,059 | |
| Executive Vice President, | | | | 2006 | | | $ | 185,000 | | | $ | 175,000 | | | | — | | | $ | 96,200 | | | $ | 714,705 | (15) | | $ | 1,170,905 | |
| Strategy | | | | | | | | | | | | | | | | | | | | | | |
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| (1) | | Bonuses are reported for the year in which they were earned, though they may have been paid the following year. |
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| (2) | | Includes a retention bonus in the valueamount of profit interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”$122,917. |
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| (3) | | Includes (1) a lump sum severance paymentReflects the amount recognized for financial statement reporting purposes for the fiscal years ended December 31, 2006 and December 31, 2007 with respect to shares of $173,999.72 (which represents six monthscommon stock of base salary equal to $175,000 less the aggregateeach of Mr. Rinaldi’s share of premium payments for continuing health care coverage), (2) $3,470.40, which represents the dollar value of the company’s cost of continued health care coverage for six months, (3) $91,000, which represents a pro rata portion of Mr. Rinaldi’s 2005 bonus paid as a component of severance (4) $36,346, which represents 5.4 weeks of earned but unused vacationCoffeyville Refining & Marketing, Inc. and paid time off, (5) $15,000 in lieu of outplacement services, (6) $23,332.99, which represents two months’ salary in lieu of receiving two months’ written notice from us less an amount paid by usCoffeyville Nitrogen Fertilizers, Inc. granted to Mr. Rinaldi subsequent to his termination dateLipinski effective December 28, 2006. In connection with the formation of $35,000.01, (7) $30,000, which amount represents paymentCoffeyville Refining & Marketing Holdings, Inc. in August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for consulting services providedan equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. In connection with our initial public offering in October 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. were exchanged by Mr. Rinaldi following his terminationLipinski for 247,471 shares of employment and (8) $9,450, which represents a pre-separation company contribution under the company’s 401(k) plan in 2005.our common stock. |
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| (4) | | Mr. Rinaldi served as Chief Executive officer from March 3, 2004Reflects cash awards to June 24, 2005.the named individuals in respect of 2006 performance pursuant to our Variable Compensation Plan. Beginning in 2007, our executive officers no longer participated in this plan. |
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| (5) | | Includes (1) a company contributionThe amounts shown represent grants of $9,450 under the company’s 401(k) plan in 2005 and (2) $1,169,145, which represents the value of profitprofits interests in Coffeyville Acquisition LLC, that were grantedCoffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and grants of phantom points in Phantom Unit Plan I and Phantom Unit Plan II and reflect the dollar amounts recognized for financial statement reporting purposes for the years ended December 31, 2006 and December 31, 2007 in accordance with SFAS 123(R). For the 2006 amounts, assumptions used in the calculation are included in footnote 5 to our audited financial statements for the year ended December 31, 2006 included in the Company’s registration statement on July 25, 2005. The value of the profit interests was determined by a third-party valuation using binomial modeling basedForm S-1/A filed on company projections of undiscounted future cashOctober 16, 2007. For |
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| | flows.the 2007 amounts, assumptions used in the calculation are included in footnote 3 to our audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. The profitprofits interests in Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and the phantom points in Phantom Unit Plan I and Phantom Unit Plan II are more fully described below under “Executives’“— Executive Officers’ Interests in Coffeyville Acquisition LLC.LLC and Coffeyville Acquisition II LLC”, “— Executive Officers’ Interests in Coffeyville Acquisition III LLC”, and “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. |
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| (6) | | Includes (1)(a) a company contribution of $9,450 under the company’sour 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC that were granted in 2005 and (2) $600,191, which representsin the valueamount of profit$8,057,632, (e) profits interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The valueDecember 29, 2006 in the amount of the profit$1,595,428, (f) profits interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”III LLC that were granted in October 2007 in the amount of $1,080 and (g) phantom points granted during the period ending December 31, 2006 in the amount of $2,519,640. |
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| (7) | | Includes (1)(a) a company contribution of $9,450 under the company’sour 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) forgiveness of a note that Mr. Lipinski owed to Coffeyville Acquisition LLC in the amount of $350,000, (d) forgiveness of accrued interest related to the forgiven note in the amount of $17,989, (e) profits interests in Coffeyville Acquisition LLC granted in 2005 and (2) $600,191, which representsin the valueamount of profit$630,059, (f) a cash payment in respect of taxes payable on his December 28, 2006 grant of subsidiary stock in the amount of $2,481,346, (g) profits interests in Coffeyville Acquisition LLC that were granted on July 25, 2005. The valueDecember 29, 2006 in the amount of $20,510 and (h) phantom points granted during the profit interests was determined by a third-party valuation using binomial modeling based on company projectionsperiod ending December 31, 2006 in the amount of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”$1,495,211. |
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| (8) | | Includes (1)(a) a company contribution of $9,450 under the company’sour 401(k) plan in 2005 and (2) $600,191, which represents2007, (b) the valuepremiums paid by us on behalf of profitthe executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,836,087, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $201 and (f) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $911,768. |
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| (9) | | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on July 25, 2005. The valuebehalf of the profitexecutive officer with respect to our executive life insurance program in 2006, (c) profits interests was determined by a third-party valuation using binomial modeling based on company projections of undiscounted future cash flows. The profit interests are more fully described below under “— Executives’ Interests in Coffeyville Acquisition LLC.”LLC granted in 2005 in the amount of $279,670 and (d) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $651,299. |
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| (10) | | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $3,576,617, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $393, (f) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $1,097,527 and (g) a relocation bonus of $222,099. |
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| (11) | | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and (d) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $541,061. |
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| (12) | | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,836,087, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $201, (f) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $911,768 and (g) a relocation bonus of $61,500. |
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| (13) | | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and (d) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $541,061. |
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| (14) | | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,324,168, (d) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $144 and (e) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $1,016,972. |
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| (15) | | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $103,543 and (d) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $603,491. |
Employment Agreements Separation and Consulting Agreement and Other Arrangements
Employment Agreements
John J. Lipinski. On July 12, 2005, Coffeyville Resources, LLC entered into an employment agreement with Mr. Lipinski, as Chief Executive Officer.Officer, which was subsequently assumed by CVR Energy and amended and restated effective as of December 29, 2007. The agreement has a rolling term of three years so that at the end of each month it automatically renews for one additional month, or the Rolling Contract Period, unless otherwise terminated by usCVR Energy or Mr. Lipinski. Mr. Lipinski receives an annual base salary of $650,000.$700,000. Mr. Lipinski is eligible to receive a performance-based annual cash bonus with a target payment equal to 75%250% of his annual base salary to be based upon individualand/or company performance criteria as established by our board of directors for each fiscal year.
Mr. Lipinski’s agreement provides for certain severance payments that may be due following the termination of his employment. These benefits are described below under “— Potential Payments Upon Termination or Change-of-Control.”
Stanley A. Riemann, James T. Rens, Robert W. Haugen and Daniel J. Daly, Jr. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Mr. Riemann, Mr. Rens, and Mr. Haugen. The agreements were subsequently assumed by CVR Energy and amended and rested effective as of December 29, 2007. The agreements have a term of three years and expire in December 2010, unless otherwise terminated earlier by the parties. CVR Energy entered into an employment agreement with Mr. Daly on October 23, 2007 and amended that agreement as of November 30, 2007. The agreements provide for an annual base salary of $375,000 for Mr. Riemann, $300,000 for Mr. Rens, $275,000 for Mr. Haugen and $220,000 for Mr. Daly. Each executive officer is eligible to receive a performance-based annual cash bonus to be based upon individualand/or company performance criteria as established by the board of directors of Coffeyville Resources, LLC for each fiscal year. The agreement providestarget annual bonus percentages are as follows: Mr. Riemann (200%), Mr. Rens (120%), Mr. Haugen (120%) and Mr. Daly (80%).
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These agreements provide for certain severance payments that formay be due following the period during which he was employed in 2005, Mr. Lipinski wastermination of the executive officers’ employment. These benefits are described below under “— Potential Payments Upon Termination or Change of Control”.
Long Term Incentive Plan
The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP, permits the grant of options, stock appreciation rights, or SARs, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). Individuals who are eligible to receive awards and grants under the LTIP include our and our subsidiaries’ employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below. As of December 31, 2007, no awards had been made under the LTIP to any of our executive officers.
Shares Available for Issuance. The LTIP authorizes a portionshare pool of his annual bonus pro-rated7,500,000 shares of our common stock, 1,000,000 of which may be issued in respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of days Mr. Lipinski was employed during such period and based uponshares available for issuance under the individualand/or Company performance criteria establishedLTIP shall be increased by the boardnumber of directorsshares previously allocable to the expired, canceled, settled or otherwise terminated portion of Coffeyville Resources, LLCthe award. As of December 31, 2007, 7,463,600 shares of common stock were available for such period. In addition to his annual bonus, Mr. Lipinskiissuance under the LTIP.
Administration and Eligibility. The LTIP is administered by a committee, which is currently the compensation committee. The committee determines who is eligible to participate in any special bonus program that the boardLTIP, determines the types of directors of Coffeyville Resources, LLC may implementawards to reward senior management for extraordinary performance onbe granted, prescribes the terms and conditions establishedof all awards, and construes and interprets the terms of the LTIP. All decisions made by such board.the committee are final, binding and conclusive.
If Mr. Lipinski’sAward Limits. In any three calendar year period, no participant may be granted awards in respect of more than 6,000,000 shares in the form of (i) stock options, (ii) SARs, (iii) performance-based restricted stock and (iv) performance share units, with the above limit subject to the adjustment provisions discussed below. The maximum dollar amount of cash or the fair market value of shares that any participant may receive in any calendar year in respect of performance units may not exceed $3,000,000.
Type of Awards. Below is a description of the types of awards available for grant pursuant to the LTIP.
Stock Options. The compensation committee is authorized to grant stock options to participants. The stock options may be either nonqualified stock options or incentive stock options. The exercise price of any stock option must be equal to or greater than the fair market value of a share on the date the stock option is granted. The term of a stock option cannot exceed 10 years (except that options may be exercised for up to 1 year following the death of a participant even, with respect to nonqualified stock options, if such period extends beyond the 10 year term). Subject to the terms of the LTIP, the option’s terms and conditions, which include but are no limited to, exercise price, vesting, treatment of the award upon termination of employment, is terminated eitherand expiration of the option, are determined by Coffeyville Resources, LLC without causethe committee and other thanwill be set forth in an award agreement. Payment for disability or by Mr. Lipinski for good reason (as these terms are defined in Mr. Lipinski’s agreement), then Mr. Lipinski is entitled to receive as severance (a) salary continuation for 36 months and (b) the continuationshares purchased upon exercise of medical benefits for thirty-six months at active-employee rates or until such time as Mr. Lipinski becomes eligible for medical benefits from a subsequent employer. If Mr. Lipinski’s employment is terminated as a result of his disability, then in addition to any payments toan option must be made to Mr. Lipinski under disability plan(s)in full at the time of purchase. The exercise price may be paid (i) in cash or its equivalent (e.g., Mr. Lipinski is entitled to supplemental disability payments equal to,check), (ii) in shares of our common stock already owned by the participant, on terms determined by the committee, (iii) in the aggregate, Mr. Lipinski’s base salaryform of other property as determined by the committee, (iv) through participation in effect immediately before his disability. Such supplemental disability paymentsa “cashless exercise” procedure involving a broker or (v) by a combination of the foregoing.
SARs. The compensation committee may, in its discretion, either alone or in connection with the grant of an option, grant a SAR to a participant. The terms and conditions of the award will be made for a period of 36 months from the date of disability. If Mr. Lipinski’s employment is terminated at any time during the Rolling Contract Period by reason of his death, then Mr. Lipinski’s beneficiary (or his estate) will be paid the base salary Mr. Lipinski would have received had he remained employed through such date.set
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Notwithstandingforth in an award agreement. SARs may be exercised at such times and be subject to such other terms, conditions, and provisions as the foregoing, Coffeyville Resources, LLCcommittee may at itsimpose. SARs that are granted in tandem with an option may only be exercised upon the surrender of the right to purchase insurance to coveran equivalent number of shares of our common stock under the obligationsrelated option and may be exercised only with respect to the shares of our common stock for which the related option is then exercisable. The committee may establish a maximum amount per share that would be payable upon exercise of a SAR. A SAR entitles the participant to receive, on exercise of the SAR, an amount equal to the product of (i) the excess of the fair market value of a share of our common stock on the date preceding the date of surrender over the fair market value of a share of our common stock on the date the SAR was issued, or, if the SAR is related to an option, the per-share exercise price of the option and (ii) the number of shares of our common stock subject to the SAR or portion thereof being exercised. Subject to the discretion of the committee, payment of a SAR may be made (i) in cash, (ii) in shares of our common stock or (iii) in a combination of both (i) and (ii).
Dividend Equivalent Rights. The compensation committee may grant dividend equivalent rights either Mr. Lipinski’s supplemental disability paymentsin tandem with an award or as a separate award. The terms and conditions applicable to each dividend equivalent right would be specified in an award agreement. Amounts payable in respect of dividend equivalent rights may be payable currently or, if applicable, deferred until the payments duelapsing of restrictions on the dividend equivalent rights or until the vesting, exercise, payment, settlement or other lapse of restrictions on the award to Mr. Lipinski’s beneficiarywhich the dividend equivalent rights relate.
Service Based Restricted Stock and Restricted Stock Units. The compensation committee may grant awards of time-based restricted stock and restricted stock units. Restricted stock and restricted stock units may not be sold, transferred, pledged or estate by reasonotherwise transferred until the time, or until the satisfaction of his death. Mr. Lipinskisuch other terms, conditions and provisions, as the committee may determine. When the period of restriction on restricted stock terminates, unrestricted shares of our common stock will be requireddelivered. Unless the committee otherwise determines at the time of grant, restricted stock carries with it full voting rights and other rights as a stockholder, including rights to cooperatereceive dividends and other distributions. At the time an award of restricted stock is granted, the committee may determine that the payment to the participant of dividends be deferred until the lapsing of the restrictions imposed upon the shares and whether deferred dividends are to be converted into additional shares of restricted stock or held in obtaining such insurance. If any payments or distributions due to Mr. Lipinskicash. The deferred dividends would be subject to the excise tax imposed under Section 4999same forfeiture restrictions and restrictions on transferability as the restricted stock with respect to which they were paid. Each restricted stock unit represents the right of the Internal Revenue Codeparticipant to receive a payment upon vesting of 1986,the restricted stock unit or on any later date specified by the committee. The payment will equal the fair market value of a share of common stock as amended, thenof the date the restricted stock unit was granted, the vesting date or such paymentsother date as determined by the committee at the time the restricted stock unit was granted. At the time of grant, the committee may provide a limitation on the amount payable in respect of each restricted stock unit. The committee may provide for a payment in respect of restricted stock unit awards (i) in cash or distributions will be “cutback” so that they will no longer(ii) in shares of our common stock having a fair market value equal to the payment to which the participant has become entitled.
Share Awards. The compensation committee may award shares to participants as additional compensation for service to us or a subsidiary or in lieu of cash or other compensation to which participants have become entitled. Share awards may be subject to other terms and conditions, which may vary from time to time and among participants, as the excise tax.committee determines to be appropriate.
The agreement requires Mr. Lipinski to abide by restrictive covenants relating to non-disclosure, non-solicitationPerformance Share Units and non-competition during his employmentPerformance Units. Performance share unit awards and for specified periods following termination of his employment.
Stanley A. Riemann, Kevan A. Vick, James T. Rens and Wyatt E. Jernigan. On July 12, 2005, Coffeyville Resources, LLC entered into employment agreements with each of Mr. Riemann, as Chief Operating Officer; Mr. Vick, as Executive Vice President — General Manager Nitrogen Fertilizer; Mr. Rens, as Chief Financial Officer; and Mr. Jernigan, as Executive Vice President — Crude Oil Acquisition and Petroleum Marketing. The agreements have a term of three years and expire on June 24, 2008, unless otherwise terminated earlierperformance unit awards may be granted by the parties. The agreements provide for an annual base salary of $350,000 for Mr. Riemann, $250,000 for Mr. Rens, $225,000 for Mr. Jernigancompensation committee under the LTIP. Performance share units are denominated in shares and $200,000 for Mr. Vick. Each executive is eligiblerepresent the right to receive a performance-based annual cash bonus withpayment in an amount based on the fair market value of a target payment equal to 52% of his annual base salary (60% for Mr. Riemann) to be based upon individualand/or companyshare on the date the performance criteria as establishedshare units were granted, become vested or any other date specified by the boardcommittee, or a percentage of directorssuch amount depending on the level of Coffeyville Resources, LLC for each fiscal year. Forperformance goals attained. Performance units are denominated in a specified dollar amount and represent the year 2005, each executive was also eligibleright to receive an annual bonus under the 2005 Coffeyville Resources, LLC and Affiliated Companies Performance Based Income Sharing Plan with appropriate adjustments to the performance criteria thereunder to reflect the impact, if any,a payment of the transactions that were contemplated in the Stock Purchase Agreement among Coffeyville Acquisition LLC and the other parties thereto, dated May 15, 2005. In addition to their annual bonuses, the executives are eligible to participate in any special bonus program that the board of directors of Coffeyville Resources, LLC may implement to reward senior management for extraordinary performance on terms and conditions established by the board of directors of Coffeyville Resources, LLC. Mr. Riemann’s agreement provides that he will receive retention bonuses of approximately $245,833 in the aggregate during the years 2006 and 2007. Mr. Vick’s agreement provides that he will receive retention bonuses of approximately $105,115 in the aggregate during the years 2006 and 2007.
If an executive’s employment is terminated either by Coffeyville Resources, LLC without cause and other than for disabilityspecified dollar amount or by the executive for good reason (as such terms are defined in the relevant agreement), then the executive is entitled to receive as severance (a) salary continuation for 12 months (18 months for Mr. Riemann) and (b) the continuation of medical benefits for 12 months (18 months for Mr. Riemann) at active-employee rates or until such time as the executive becomes eligible for medical benefits from a subsequent employer. The agreements provide that if any payments or distributions due to an executive would be subject to the excise tax imposed under Section 4999percentage of the Internal Revenue Code, as amended, then such payments or distributions will be “cutback” so that they will no longer be subject tospecified dollar amount, depending on the excise tax.
The agreements require eachlevel of the executives to abide by restrictive covenants relating to non-disclosure, non-solicitation and non-competition during their employment and for specified periods following termination of their employment.
Separation and Consulting Agreement with Philip L. Rinaldi
Mr. Rinaldi served as chief executive officer from March 3, 2004 until June 24, 2005. In connection with his separation, Coffeyville Resources, LLC entered into a separation and consulting agreement with him. This agreement provides that Mr. Rinaldi would continue to provide variousperformance goals attained.
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consulting servicesSuch awards would be earned only if performance goals established for performance periods are met. A minimum one-year performance period is required. At the time of grant the committee may establish a maximum amount payable in respect of a vested performance share or performance unit. The committee may provide for payment (i) in cash, (ii) in shares of our common stock having a fair market value equal to the payment to which the participant has become entitled or (iii) by a combination of both (i) and (ii).
Performance-Based Restricted Stock. The compensation committee may grant awards of performance-based restricted stock. The terms and conditions of such award will be set forth in an award agreement. Such awards would be earned only if performance goals established for performance periods are met. Upon the lapse of the restrictions, the committee will deliver a stock certificate or evidence of book entry shares to the participant. Awards of performance-based restricted stock will be subject to a minimum one-year performance cycle. At the time an award of performance-based restricted stock is granted, the committee may determine that the payment to the participant of dividends will be deferred until the lapsing of the restrictions imposed upon the performance-based restricted stock and whether deferred dividends are to be converted into additional shares of performance-based restricted stock or held in cash.
Performance Objectives. Performance share units, performance units and performance-based restricted stock awards under the LTIP may be made subject to the attainment of performance goals based on one month commencingor more of the following business criteria: (i) stock price; (ii) earnings per share; (iii) operating income; (iv) return on equity or assets; (v) cash flow; (vi) earnings before interest, taxes, depreciation and amortization, or EBITDA; (vii) revenues; (viii) overall revenue or sales growth; (ix) expense reduction or management; (x) market position; (xi) total stockholder return; (xii) return on investment; (xiii) earnings before interest and taxes, or EBIT; (xiv) net income; (xv) return on net assets; (xvi) economic value added; (xvii) stockholder value added; (xviii) cash flow return on investment; (xix) net operating profit; (xx) net operating profit after tax; (xxi) return on capital; (xxii) return on invested capital; or (xxiii) any combination, including one or more ratios, of the foregoing.
Performance criteria may be in respect of our performance, that of any of our subsidiaries, that of any of our divisions or any combination of the foregoing. Performance criteria may be absolute or relative (to our prior performance or to the performance of one or more other entities or external indices) and may be expressed in terms of a progression within a specified range. The compensation committee may, at the time performance criteria in respect of a performance award are established, provide for the manner in which performance will be measured against the performance criteria to reflect the effects of extraordinary items, gain or loss on the disposal of a business segment (other than the provisions for operating losses or income during the phase-out), unusual or infrequently occurring events and transactions that have been publicly disclosed, changes in accounting principles, the impact of specified corporate transactions (such as a stock split or stock dividend), special charges and tax law changes, all as determined in accordance with generally accepted accounting principles (to the extent applicable).
Amendment and Termination of the LTIP. Our board of directors has the right to amend the LTIP except that our board of directors may not amend the LTIP in a manner that would impair or adversely affect the rights of the holder of an award without the award holder’s consent. In addition, our board of directors may not amend the LTIP absent stockholder approval to the extent such approval is required by applicable law, regulation or exchange requirement. The LTIP will terminate on the tenth anniversary of the date of stockholder approval. The board of directors may terminate the LTIP at any earlier time except that termination datecannot in exchangeany manner impair or adversely affect the rights of the holder of an award without the award holder’s consent.
Repricing of Options or SARs. Unless our stockholders approve such adjustment, the compensation committee will not have authority to make any adjustments to options or SARs that would
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reduce or would have the effect of reducing the exercise price of an option or SAR previously granted under the LTIP.
Change in Control. The effect, if any, of a change in control on each of the awards granted under the LTIP may be set forth in the applicable award agreement.
Adjustments. In the event of a reclassification, recapitalization, merger, consolidation, reorganization, spin-off,split-up, stock dividend, stock split or reverse stock split, or similar transaction or other change in corporate structure affecting our common stock, adjustments and other substitutions will be made to the LTIP, including adjustments in the maximum number of shares subject to the LTIP and other numerical limitations. Adjustments will also be made to awards under the LTIP as the compensation committee determines appropriate. In the event of our merger or consolidation, liquidation or dissolution, outstanding options and awards will either be treated as provided for a consulting fee equal to $30,000. Mr. Rinaldi was previously a party to an employmentin the agreement and the following payments were provided pursuant to that agreemententered into in connection with his separation: (a) a lump sumthe transaction (which may include the accelerated vesting and cancellation of the options and SARs or the cancellation of options and SARs for payment equalof the excess, if any, of the consideration paid to six months’stockholders in the transaction over the exercise price of his base salary less his aggregate sharethe options or SARs), or converted into options or awards in respect of premium payments for continuing health care coverage (the total payment equaling approximately $174,000), (b) the continuation of his health care benefits for a period of six months and (c) an amount equal to approximately $165,679, which amount represents a pro rata portion of Mr. Rinaldi’s 2005 bonus, earned but unused vacation and paid time off, paymentsame securities, cash, property or other consideration that stockholders received in lieu of outplacement services and salary in lieu of notice of termination that was required under his employment agreement. Mr. Rinaldi was subject to six-month post-separation non-solicitation and non-competition covenants. Mr. Rinaldi remains subject to a confidentiality covenant.connection with the transaction.
Stock Incentive Plan
We intend to adopt a stock incentive plan under which certain of our executives and employees may be granted options or other equity based compensation in respect of our stock. The stock incentive plan will be designed to enable us to attract, retain and motivate our officers and employees and to further align their interests with those of our stockholders by providing for, or increasing, their ownership interests in us.
Executives’Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC
The following is a summary of the material terms of the Coffeyville Acquisition LLC Second Amended and Restated Limited Liability Company Agreement orand the Coffeyville Acquisition II LLC Agreement as they relate to the limited liability company interests granted to our named executive officers (with the exception of Mr. Rinaldi) pursuant to those agreements as of December 31, 2007. We refer to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC collectively as the LLC Agreement asAgreements. The terms of June 30, 2006.the two limited liability company agreements which relate to the interests granted to our named executive officers are identical to each other.
GeneralGeneral.
The LLC Agreement providesAgreements provide for two classes of interests in Coffeyville Acquisition LLC:the respective limited liability companies: (i) common units and (ii) profits interests, which are called override units (which consist of eitherboth operating units orand value units) (Common(common units and override units are collectively referred to as units)“units”). The common units provide for voting rights and have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition LLC.LLC and Coffeyville Acquisition II LLC, as applicable. Such voting rights cease, however, if the executive officer holding common units ceases to provide services to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, as applicable, or one of its or their subsidiaries. The common units were issued to our named executive officers in the following amounts (as subsequently adjusted) in exchange for an initial capital contributions in the following amounts: Mr. Lipinski (capital contribution of $10 per common unit: Mr. Lipinski (65,000$650,000 in exchange for 57,446 units), Mr. Riemann (40,000(capital contribution of $400,000 in exchange for 35,352 units), Mr. Rens (25,000(capital contribution of $250,000 in exchange for 22,095 units), Mr. Vick (25,000Haugen (capital contribution of $100,000 in exchange for 8,838 units) and Mr. Jernigan (10,000Daly (capital contribution of $50,000 in exchange for 4,419 units). These named executive officers were also granted override units, which consist of operating units and value units, in the following amounts: Mr. Lipinski (315,818(an initial grant of 315,818 operating units and 631,637 value units and a December 2006 grant of 72,492 operating units and 144,966 value units), Mr. Riemann (140,185 operating units and 280,371 value units), Mr. Rens (71,965 operating units and 143,931 value units), Mr. VickHaugen (71,965 operating units and 143,931 value units) and Mr. Jernigan (71,965Daly (51,901 operating units and 143,931103,801 value units). Override units have no voting rights attached to them, but have the rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition LLC.LLC or Coffeyville Acquisition II LLC, as applicable. Our named executive officers were not required to make any capital contribution with respect to the override units; override units were issued only to certain members of management who own common units and who agreeagreed to provide services to Coffeyville Acquisition LLC. LLC or Coffeyville Acquisition II LLC, as applicable.
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In addition, common units were issued to the following executive officers in the following amounts (as subsequently adjusted) in exchange for an initialthe following capital contributions: Mr. Kevan Vick (capital contribution of $10 per common unit: Mr. Robert W. Haugen (10,000$250,000 in exchange for 22,095 units), Mr. Edmund Gross (3,000(capital contribution of $30,000 in exchange for 2,651 units), Mr. Christopher Swanberg (capital contribution of $25,000 in exchange for 2,209 units) and Mr. Chris Swanberg (2,500Wyatt Jernigan (capital contribution of $100,000 in exchange for 8,838 units). Also, Mr. HaugenVick was also granted override71,965 operating units in the following amounts:and 143,931 value units and Mr. Jernigan was granted 71,965 operating units and 143,931 value units.
If all of the shares of common stock of our sharesCompany held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at $24.92 per share, which was the price of our initial public offering pricecommon stock on June 16, 2008, and cash was distributed to members pursuant to the limited liability company agreements of Coffeyville Acquisition LLC Agreement,and Coffeyville Acquisition II LLC, our named executive officers would receive a cash payment in respect of their override units in the following approximate amounts:
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Mr. Lipinski ($ ),66.0 million), Mr. Riemann ($ ),25.7 million), Mr. Rens ($ ),13.2 million), Mr. VickHaugen ($ )13.2 million), and Mr. JerniganDaly ($ ).9.5 million).
Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC expect to distribute the proceeds of the sale of common stock in this offering to their members pursuant to their respective limited liability company agreements. Assuming the underwriters’ option to purchase additional shares is not exercised, if all of the shares of common stock of our Company to be sold in this offering by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at $24.92 per share, which was the price of our common stock on June 16, 2008, each of our named executive officers will receive a cash payment in respect of their override units in the following approximate amounts: Mr. Lipinski ($3.5 million), Mr. Riemann ($1.6 million), Mr. Rens ($0.9 million), Mr. Haugen ($0.7 million), and Mr. Daly ($0.5 million).
Forfeiture of Override Units Upon Termination of EmploymentEmployment.
If the executive officer ceases to provide services to Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, or a subsidiary due to a termination for “Cause”“cause” (as such term is defined in the LLC Agreement)Agreements), the executive officer will forfeit all of his override units. If the executive officer ceases to provide services for any reason other than Causecause before the fifth anniversary of the date of grant of his operating units, and provided that an event that is an “Exit Event” (as such term is defined in the LLC Agreement)Agreements) has not yet occurred and there is no definitive agreement in effect regarding a transaction that would constitute an Exit Event, then (a) unless the termination was due to the Executive’sexecutive officer’s death or “Disability”“disability” (as that term is defined in the LLC Agreement)Agreements), in which case a different vesting schedule will apply based on when the death or Disabilitydisability occurs, all value units will be forfeited and (b) a percentage of the operating units will be forfeited according to the following schedule: if terminated before the second anniversary of the date of grant, 100% of operating units are forfeited; if terminated on or after the second anniversary of the date of grant, but before the third anniversary of the date of grant, 75% of operating units are forfeited; if terminated on or after the third anniversary of the date of grant, but before the fourth anniversary of the date of grant, 50% of operating units are forfeited; and if terminated on or after the fourth anniversary of the date of grant, but before the fifth anniversary of the date of grant, 25% of his operating units are forfeited.
Adjustments to Capital Accounts; DistributionsDistributions.
Each of the executivesexecutive officers has a capital account under which his balance is increased or decreased, as applicable, to reflect his allocable share of net income and gross income of Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, the capital that the executive officer contributed, distributions paid to such executive officer and his allocable share of net loss and items of gross deduction.
Value units owned by the executivesexecutive officers do not participate in distributions under the LLC AgreementAgreements until the “Current Value” is at least two times the “Initial Price” (as these terms are defined in the LLC Agreement)Agreements), with full participation occurring when the Current Value is four times the Initial Price and pro rata distributions when the Current Value is between two and four times the Initial Price. The board of directors of Coffeyville Acquisition LLC will determine the “Benchmark Amount” with respect to each override unit at the time of its grant, which for all override units granted as of July 25, 2005, was $10.and Coffeyville Acquisition II LLC may make distributions to its
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their members to the extent that the cash available to itthem is in excess of the business’sapplicable business’ reasonably anticipated needs. Distributions are generally made to members’ capital accounts in proportion to the number of units each member holds. Distributions in respect of override units (both operating units and value units), however, will be reduced until the total reductions in proposed distributions in respect of the override units equals the Benchmark Amount (i.e., $11.31 for override units granted on July 25, 2005 $10)and $34.72 for Mr. Lipinski’s later grant). (ThereThe boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC will determine the “Benchmark Amount” with respect to each override unit at the time of its grant. There is also acatch-up provision with respect to any value unit that was not previously entitled to participate in a distribution because the Current Value was not at least four times the Initial Price.)
Put and Call Rights
The executives have put rights with respect to their common units, so that following their termination of employment, they have the right to sell all (but not less than all) of their common units to Coffeyville Acquisition LLC at their “Fair Market Value” (as that term is defined in the LLC Agreement) if they were terminated without “Cause,” or as a result of death, “Disability” or resignation with “Good Reason” (each as defined in the LLC Agreement) or due to “Retirement” (as that term is defined in the LLC Agreement). Coffeyville Acquisition LLC has call rights with respect to the executives’ common units, so that following the executives’ termination of employment, Coffeyville Acquisition LLC has the right to purchase the common units at their Fair Market Value if the executive was terminated without Cause, or as a result of the executive’s death, Disability or resignation with
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Good Reason or due to Retirement. The call price will be the lesser of the common unit’s Fair Market Value or Carrying Value (which means the capital contribution, if any, made by the executive in respect of such interest less the amount of distributions made in respect of such interest) if the executive is terminated for Cause or he resigns without Good Reason. For any other termination of employment, the call price will be at the Fair Market Value or Carrying Value of such common units, in the sole discretion of Coffeyville Acquisition LLC’s board of directors. No put or call rights apply to override units following the executive’s termination of employment unless Coffeyville Acquisition LLC’s board of directors (or the compensation committee thereof) determines in its discretion that put and call rights will apply.
Other Provisions Relating to UnitsUnits.
The executivesexecutive officers are subject to transfer restrictions on their units, although they may make certain transfers of their units for estate planning purposes.
Executive Officers’ Interests in Coffeyville Acquisition III LLC
Coffeyville Acquisition III LLC, the sole owner of the managing general partner of the Partnership, is owned by the Goldman Sachs Funds, the Kelso Funds, our executive officers, Mr. Wesley Clark, Magnetite Asset Investors III L.L.C. and certain members of our senior management team. The following is a summary of the material terms of the Coffeyville Acquisition III LLC Agreement alsolimited liability company agreement as they relate to the limited liability company interests held by our executive officers.
General. The Coffeyville Acquisition III LLC limited liability company agreement provides for certain tag-alongtwo classes of interests in Coffeyville Acquisition III LLC: (i) common units and drag-along(ii) profits interests, which are called override units.
The common units provide for voting rights and have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition III LLC. Such voting rights cease, however, if the executive officer holding common units ceases to provide services to Coffeyville Acquisition III LLC or one of its subsidiaries. In October 2007, CVR Energy’s executive officers made the following capital contributions to Coffeyville Acquisition III LLC and received a number of Coffeyville Acquisition III LLC common units equal to their pro rata portion of all contributions: Mr. Lipinski ($68,146), Mr. Riemann ($16,360), Mr. Rens ($10,225), Mr. Haugen ($4,090), Mr. Daly ($2,045), Mr. Jernigan ($4,090), Mr. Gross ($1,227), Mr. Vick ($10,225) and Mr. Swanberg ($1,022).
Override units have no voting rights attached to them, but have rights with respect to profits and losses of, and distributions from, Coffeyville Acquisition III LLC. The override units have the following terms:
| | |
| • | Approximately 25% of all of the override units have been awarded to members of our management team. These override units automatically vested. These units will be owned by the members of our management team even if they no longer perform services for us or are no longer employed by us. The following executive officers received the following grants of this category of override units: Mr. Lipinski (81,250), Mr. Riemann (30,000), Mr. Rens (16,634), Mr. Haugen (16,634), Mr. Jernigan (14,374), Mr. Gross (8,786), Mr. Vick (13,405), Mr. Swanberg (8,786) and Mr. Daly (13,269). |
|
| • | Approximately 75% of the override units have been awarded to members of our management team responsible for the growth of the nitrogen fertilizer business. Some portion of these units may be awarded to members of management added in the future. These units vest on a five-year schedule, with 33.3% vesting on the third anniversary of the closing date of the Partnership’s initial public offering (if any such offering occurs), an additional 33.4% vesting on the fourth anniversary of the closing date of such an offering, and the remaining 33.3% vesting on the fifth anniversary of the closing date of such an offering. Override units are entitled to distributions whether or not they have vested. Management members will forfeit unvested units if they are no longer employed by us; however, if a management member has three full years of service with the Partnership following the completion of an initial public offering of the |
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| | |
| | Partnership, such management member may retire at age 62 and will be entitled to permanently retain all of his or her units whether or not they have vested pursuant to the vesting schedule described above. Units forfeited will be either retired or reissued to others (with a catchup payment provision); retired units will increase the unit values of all other units on a pro rata basis. The following executive officers received the following grants of this category of override units: Mr. Lipinski (219,378), Mr. Riemann (75,000), Mr. Rens (48,750), Mr. Haugen (13,125), Mr. Jernigan (11,250), Mr. Gross (22,500), Mr. Vick (45,000), Mr. Swanberg (11,250) and Mr. Daly (18,750). |
The override units granted to management are entitled to 15% of all distributions made by Coffeyville Acquisition III LLC. All vested and unvested override units are entitled to distributions. To the extent that at any time not all override units have yet been granted, the override units that have been granted will be entitled to the full 15% of all distributions (e.g., if only 90% of the override units have been granted, the holders of these 90% are entitled to 15% of all distributions).
A portion of the override units may be granted in the future to new members of management. A catch up payment will be made to new members of management who receive units at a time when the current unit value has increased from the initial unit value.
The value of the common units and override units in Coffeyville Acquisition III LLC depends on the ability of the Partnership’s managing general partner to make distributions. The managing general partner will not receive any distributions from the Partnership until the Partnership’s aggregate adjusted operating surplus through December 31, 2009 has been distributed. Based on the Partnership’s current projections, the Partnership believes that the executive officers will not begin to receive distributions on their common and override units until after December 31, 2010.
Adjustments to Capital Accounts; Distributions. Each of the executive officers has a capital account under which his balance is increased or decreased, as applicable, to reflect his allocable share of net income and gross income of Coffeyville Acquisition III LLC, the capital that the executive officer contributed, distributions paid to such executive officer and his allocable share of net loss and items of gross deduction.
Override units owned by the executive officers do not participate in distributions under the Coffeyville Acquisition III LLC limited liability company agreement until the “Current Value” is at least equal to the “Initial Price” (as these terms are defined in the Coffeyville Acquisition III LLC limited liability company agreement). Coffeyville Acquisition III LLC may make distributions to its members to the extent that the cash available to it is in excess of the business’ reasonably anticipated needs. Distributions are generally made to members’ units.capital accounts in proportion to the number of units each member holds. Distributions in respect of override units, however, will be reduced until the total reductions in proposed distributions in respect of the override units equals the aggregate capital contributions of all members.
Other Provisions Relating to Coffeyville Acquisition III LLC Units. The executive officers are subject to transfer restrictions on their Coffeyville Acquisition III LLC units, although they may make certain transfers of their units for estate planning purposes.
Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)
The following is a summary of the material terms of the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), or the Phantom Unit Plan I, and the Coffeyville Resources LLC Phantom Unit Appreciation Plan (Plan II), or the Phantom Unit Plan II, as they relate to our named executive officers. Payments under the Phantom Unit Plan I are tied to distributions made by Coffeyville Acquisition LLC, and payments under the Phantom Unit Plan II are tied to distributions made by Coffeyville Acquisition II LLC. We refer to the Phantom Unit Plan I and Phantom Unit Plan II collectively as the Phantom Unit Plans.
General. The Phantom Unit Plan I and Phantom Unit Plan II are administered by the compensation committees of the boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II
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LLC, as applicable. The Phantom Unit Plans provide for two classes of interests: phantom service points and phantom performance points (collectively referred to as phantom points). Holders of the phantom service points and phantom performance points have the opportunity to receive a cash payment when distributions are made pursuant to the LLC Agreements in respect of operating units and value units, respectively. The phantom points represent a contractual right to receive a payment when payment is made in respect of certain profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, as applicable.
Phantom points have been granted under each of the Phantom Unit Plans to our named executive officers in the following amounts: Mr. Lipinski (1,368,571 phantom service points and 1,368,571 phantom performance points, which represents approximately 14% of the total phantom points awarded), Mr. Riemann (596,133 phantom service points and 596,133 phantom performance points, which represents approximately 6% of the total phantom points awarded), Mr. Rens (495,238 phantom service points and 495,238 phantom performance points, which represents approximately 5% of the total phantom points awarded), Mr. Haugen (495,238 phantom service points and 495,238 phantom performance points, which represents approximately 5% of the total phantom points awarded) and Mr. Daly (552,381 phantom service points and 552,381 phantom performance points, which represents approximately 6% of the total phantom points awarded).
If all of the shares of common stock of our company held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at $24.92 per share, which was the closing price of our common stock on June 16, 2008, and cash was distributed to members pursuant to the LLC Agreement and the Coffeyville Acquisition II LLC Agreement, our named executive officers would receive a cash payment in respect of their phantom points in the following amounts: Mr. Lipinski ($8.8 million), Mr. Riemann ($3.8 million), Mr. Rens ($3.2 million), Mr. Haugen ($3.2 million) and Mr. Daly ($3.5 million). The compensation committees of the boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC have authority to make additional awards of phantom points under the Phantom Unit Plans.
Assuming the underwriters’ option to purchase additional shares is not exercised, if all of the shares of common stock of our Company to be sold in this offering by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC were sold at $24.92 per share, which was the price of our common stock on June 16, 2008, each of our named executive officers will receive a cash payment in respect of their phantom points in the following approximate amounts: Mr. Lipinski ($0.5 million), Mr. Riemann ($0.2 million), Mr. Rens ($0.2 million), Mr. Haugen ($0.2 million), and Mr. Daly ($0.2 million).
Phantom Point Payments. Payments in respect of phantom service points will be made within 30 days from the date distributions are made pursuant to the LLC Agreements in respect of operating units. Cash payments in respect of phantom performance points will be made within 30 days from the date distributions are made pursuant to the LLC Agreements in respect of value units (i.e., not until the “Current Value” is at least two times the “Initial Price” (as such terms are defined in the LLC Agreements), with full participation occurring when the Current Value is four times the Initial Price and pro rata distributions when the Current Value is between two and four times the Initial Price). There is also acatch-up provision with respect to phantom performance points for which no cash payment was made because no distribution pursuant to the LLC Agreements was made with respect to value units.
Other Provisions Relating to the Phantom Points. The boards of directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC may, at any time or from time to time, amend or terminate the Phantom Unit Plans. If a participant’s employment is terminated prior to an “Exit Event” (as such term is defined in the LLC Agreements), all of the participant’s phantom points are forfeited. Phantom points are generally non-transferable (except by will or the laws of descent and distribution). If payment to a participant in respect of his phantom points would result in the application of the excise tax imposed under Section 4999 of the Internal Revenue Code of 1986, as amended, then the payment will be “cut back” only if that reduction would be more beneficial to the participant on an after-tax basis than if there were no reduction.
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Outstanding Equity Awards at 2007 Fiscal Year-End
| | | | | | | | | |
| | | Stock Awards | |
| | | Number of Shares
| | | Market Value of
| |
| | | or Units of Stock
| | | Shares or Units of
| |
| | | That Have Not
| | | Stock That Have Not
| |
Name | | Vested (#)(1)(2) | | | Vested ($)(3) | |
| |
| John J. Lipinski | | | 118,431.7 | (4) | | $ | 6,139,499 | |
| | | | 315,818.5 | (5) | | $ | 16,372,031 | |
| | | | 36,246.0 | (6) | | $ | 1,878,993 | |
| | | | 72,483.0 | (7) | | $ | 2,366,570 | |
| | | | 118,431.7 | (8) | | $ | 6,139,499 | |
| | | | 315,818.5 | (9) | | $ | 16,372,031 | |
| | | | 36,246.0 | (10) | | $ | 1,878,993 | |
| | | | 72,483 | (11) | | $ | 2,366,570 | |
| | | | 1,368,571 | (12) | | $ | 1,241,568 | |
| | | | 1,368,571 | (13) | | $ | 2,483,136 | |
| | | | 1,368,571 | (14) | | $ | 1,241,568 | |
| | | | 1,368,571 | (15) | | $ | 2,483,136 | |
| James T. Rens | | | 26,986.9 | (16) | | $ | 1,399,001 | |
| | | | 71,965.5 | (17) | | $ | 3,730,692 | |
| | | | 26,986.9 | (18) | | $ | 1,399,001 | |
| | | | 71,965.5 | (19) | | $ | 3,730,692 | |
| | | | 495,238 | (20) | | $ | 449,271 | |
| | | | 495,238 | (21) | | $ | 898,569 | |
| | | | 495,238 | (22) | | $ | 449,271 | |
| | | | 495,238 | (23) | | $ | 898,569 | |
| Stanley A. Riemann | | | 52,569.4 | (24) | | $ | 2,725,198 | |
| | | | 140,185.5 | (25) | | $ | 7,267,216 | |
| | | | 52,569.4 | (26) | | $ | 2,725,198 | |
| | | | 140,185.5 | (27) | | $ | 7,267,216 | |
| | | | 596,133 | (28) | | $ | 540,821 | |
| | | | 596,133 | (29) | | $ | 1,081,616 | |
| | | | 596,133 | (30) | | $ | 540,821 | |
| | | | 596,133 | (31) | | $ | 1,081,616 | |
| Robert W. Haugen | | | 26,986.9 | (32) | | $ | 1,399,001 | |
| | | | 71,965.5 | (33) | | $ | 3,730,692 | |
| | | | 26,986.9 | (34) | | $ | 1,399,001 | |
| | | | 71,965.5 | (35) | | $ | 3,730,692 | |
| | | | 495,238 | (36) | | $ | 449,271 | |
| | | | 495,238 | (37) | | $ | 898,569 | |
| | | | 495,238 | (38) | | $ | 449,271 | |
| | | | 495,238 | (39) | | $ | 898,569 | |
| Daniel J. Daly, Jr. | | | 19,462.9 | (40) | | $ | 1,008,957 | |
| | | | 51,900.5 | (41) | | $ | 2,690,522 | |
| | | | 19,462.9 | (42) | | $ | 1,008,957 | |
| | | | 51,900.5 | (43) | | $ | 2,690,522 | |
| | | | 552,381 | (44) | | $ | 501,111 | |
| | | | 552,381 | (45) | | $ | 1,002,249 | |
| | | | 552,381 | (46) | | $ | 501,111 | |
| | | | 552,381 | (47) | | $ | 1,002,249 | |
200
| | |
| (1) | | The profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC generally vest as follows: operating units generally become non-forfeitable in 25% annual increments beginning on the second anniversary of the date of grant, and value units are generally forfeitable upon termination of employment. The profits interests are more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC”. |
|
| (2) | | The phantom points granted pursuant to the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) are generally forfeitable upon termination of employment. The phantom points are more fully described above under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. |
|
| (3) | | The dollar amount shown reflects the fair value as of December 31, 2007, based upon an independent third-party valuation performed as of December 31, 2007 using the December 31, 2007 CVR Energy common stock closing price on the NYSE to determine the equity value of CVR Energy. Assumptions used in the calculation of these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. |
|
| (4) | | Represents 118,431.7 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (5) | | Represents 315,818.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (6) | | Represents 36,246.0 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (7) | | Represents 72,483.0 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (8) | | Represents 118,431.7 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (9) | | Represents 315,818.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (10) | | Represents 36,246.0 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (11) | | Represents 72,483 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on December 29, 2006. These value units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (12) | | Represents 1,368,571 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (13) | | Represents 1,368,571 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (14) | | Represents 1,368,571 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (15) | | Represents 1,368,571 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
201
| | |
| (16) | | Represents 26,986.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (17) | | Represents 71,965.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (18) | | Represents 26,986.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (19) | | Represents 71,965.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (20) | | Represents 495,238 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (21) | | Represents 495,238 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (22) | | Represents 495,238 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (23) | | Represents 495,238 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (24) | | Represents 52,569.4 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (25) | | Represents 140,185.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (26) | | Represents 52,569.4 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (27) | | Represents 140,185.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (28) | | Represents 596,133 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (29) | | Represents 596,133 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (30) | | Represents 596,133 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (31) | | Represents 596,133 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (32) | | Represents 26,986.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (33) | | Represents 71,965.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (34) | | Represents 26,986.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (35) | | Represents 71,965.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (36) | | Represents 495,238 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (37) | | Represents 495,238 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (38) | | Represents 495,238 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
202
| | |
| (39) | | Represents 495,238 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (40) | | Represents 19,462.9 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (41) | | Represents 51,900.5 value units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (42) | | Represents 19,462.9 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (43) | | Represents 51,900.5 value units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (44) | | Represents 552,381 phantom service points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (45) | | Represents 552,381 phantom performance points under the Phantom Unit Plan I granted to the executive on December 11, 2006. |
|
| (46) | | Represents 552,381 phantom service points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
|
| (47) | | Represents 552,381 phantom performance points under the Phantom Unit Plan II granted to the executive on December 11, 2006. |
Equity Awards at 2007 Fiscal Year-End That Have Vested
| | | | | | | | | |
| | | Stock Awards | |
| | | Number of
| | | | |
| | | Shares Acquired
| | | Value Realized
| |
| | | on Vesting
| | | on Vesting
| |
Name | | (#)(1)(2)(3) | | | ($)(4) | |
| |
| John J. Lipinski | | | 39,477.3 | (5) | | $ | 1,516,323 | |
| | | | 39,477.3 | (6) | | $ | 1,516,323 | |
| | | | 53,921 | (7) | | $ | 1,078 | |
| James T. Rens | | | 8,995.6 | (8) | | $ | 345,521 | |
| | | | 8,995.6 | (9) | | $ | 345,521 | |
| | | | 10,066 | (10) | | $ | 201 | |
| Stanley A. Riemann | | | 17,523.1 | (11) | | $ | 673,062 | |
| | | | 17,523.1 | (12) | | $ | 673,062 | |
| | | | 19,650 | (13) | | $ | 393 | |
| Robert W. Haugen | | | 8,995.6 | (14) | | $ | 345,521 | |
| | | | 8,995.6 | (15) | | $ | 345,521 | |
| | | | 10,066 | (16) | | $ | 201 | |
| Daniel J. Daly, Jr. | | | 6,487.6 | (17) | | $ | 249,189 | |
| | | | 6,487.6 | (18) | | $ | 249,189 | |
| | | | 7,190 | (19) | | $ | 144 | |
| | |
| (1) | | The profits interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC generally vest as follows: operating units generally become non-forfeitable in 25% annual increments beginning on the second anniversary of the date of grant, and value units are generally forfeitable upon termination of employment. The profits interests are more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC”. |
|
| (2) | | The profits interests in Coffeyville Acquisition III LLC described in this table were granted on October 24, 2007 and automatically vested on the date of grant, as more fully described above under “— Executive Officers’ Interests in Coffeyville Acquisition III LLC”. |
203
| | |
| (3) | | The phantom points granted pursuant to the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) are generally forfeitable upon termination of employment. The phantom points are more fully described above under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. |
|
| (4) | | The dollar amounts shown are based on a valuation determined for purposes of SFAS 123(R) at the relevant vesting date of the respective override units. |
|
| (5) | | Represents 39,477.3 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (6) | | Represents 39,477.3 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. These operating units have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. |
|
| (7) | | Represents profits interests in Coffeyville Acquisition III LLC (53,921 override units) granted to the executive on October 24, 2007. |
|
| (8) | | Represents 8,995.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (9) | | Represents 8,995.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (10) | | Represents profits interests in Coffeyville Acquisition III LLC (10,066 override units) granted to the executive on October 24, 2007. |
|
| (11) | | Represents 17,523.1 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (12) | | Represents 17,523.1 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (13) | | Represents profits interests in Coffeyville Acquisition III LLC (19,650 override units) granted to the executive on October 24, 2007. |
|
| (14) | | Represents 8,995.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (15) | | Represents 8,995.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (16) | | Represents profits interests in Coffeyville Acquisition III LLC (10,066 override units) granted to the executive on October 24, 2007. |
|
| (17) | | Represents 6,487.6 operating units in Coffeyville Acquisition LLC deemed to be granted to the executive on June 24, 2005. |
|
| (18) | | Represents 6,487.6 operating units in Coffeyville Acquisition II LLC deemed to be granted to the executive on June 24, 2005. |
|
| (19) | | Represents profits interests in Coffeyville Acquisition III LLC (7,190 override units) granted to the executive on October 24, 2007. |
Potential Payments Upon Termination or Change of Control
Under the terms of their respective employment agreements, the named executive officers may be entitled to severance and other benefits following the termination of their employment. These benefits are summarized below. The amounts of potential post-employment payments assume that the triggering event took place on December 31, 2007.
If Mr. Lipinski’s employment is terminated either by CVR Energy without cause and other than for disability or by Mr. Lipinski for good reason (as these terms are defined in Mr. Lipinski’s
204
employment agreement), then Mr. Lipinski is entitled to receive as severance (a) salary continuation for 36 months and (b) the continuation of medical benefits for thirty-six months at active-employee rates or until such time as Mr. Lipinski becomes eligible for medical benefits from a subsequent employer. The estimated total amounts of these payments are set forth in the table below. As a condition to receiving the salary continuation and continuation of medical benefits, Mr. Lipinski must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. If Mr. Lipinski’s employment is terminated as a result of his disability, then in addition to any payments to be made to Mr. Lipinski under disability plan(s), Mr. Lipinski is entitled to supplemental disability payments equal to, in the aggregate, Mr. Lipinski’s base salary as in effect immediately before his disability (the estimated total amount of this payment is set forth in the table below). Such supplemental disability payments will be made in installments for a period of 36 months from the date of disability. If Mr. Lipinski’s employment is terminated at any time by reason of his death, then Mr. Lipinski’s beneficiary (or his estate) will be paid the base salary Mr. Lipinski would have received had he remained employed through the remaining term of his contract. Notwithstanding the foregoing, CVR Energy may, at its option, purchase insurance to cover the obligations with respect to either Mr. Lipinski’s supplemental disability payments or the payments due to Mr. Lipinski’s beneficiary or estate by reason of his death. Mr. Lipinski will be required to cooperate in obtaining such insurance. If any payments or distributions due to Mr. Lipinski would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code of 1986, as amended, then such payments or distributions will be “cut back” only if that reduction would be more beneficial to him on an after-tax basis than if there were no reduction.
The agreement requires Mr. Lipinski to abide by a perpetual restrictive covenant relating to non-disclosure. The agreement also includes covenants relating to non-solicitation and non-competition during Mr. Lipinski’s employment term and, following the end of term, for as long as he is receiving severance or supplemental disability payments or one year if he is receiving none.
If the employment of Mr. Riemann, Mr. Rens, Mr. Haugen or Mr. Daly is terminated either by CVR Energy without cause and other than for disability or by the executive officer for good reason (as such terms are defined in the respective employment agreements), then the executive officer is entitled to receive as severance (a) salary continuation for 12 months (18 months for Mr. Riemann) and (b) the continuation of medical benefits for 12 months (18 months for Mr. Riemann) at active-employee rates or until such time as the executive officer becomes eligible for medical benefits from a subsequent employer. The amount of these payments is set forth in the table below. As a condition to receiving the salary, the executives must (a) execute, deliver and not revoke a general release of claims and (b) abide by restrictive covenants as detailed below. The agreements provide that if any payments or distributions due to an executive officer would be subject to the excise tax imposed under Section 4999 of the Internal Revenue Code, as amended, then such payments or distributions will be cut back only if that reduction would be more beneficial to the executive officer on an after-tax basis than if there were no reduction.
The agreements require each of the executive officers to abide by a perpetual restrictive covenant relating to non-disclosure. The agreements also include covenants relating to non-solicitation and non-competition during their employment and, following termination of employment, for one year (for Mr. Riemann, the applicable period is during his employment and, following termination of employment, for as long as he is receiving severance, or one year if he is receiving none).
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Below is a table setting forth the estimated aggregate amount of the payments discussed above assuming a December 31, 2007 termination date (and, where applicable, no offset due to eligibility to receive medical benefits from a subsequent employer). The table assumes that the executive officers’ termination was by CVR Energy without cause or by the executive officers for good reason, and in the case of Mr. Lipinski also provides information assuming his termination was due to his disability.
| | | | | | | | | |
| | | | | | Estimated Dollar
| |
| | | Total Severance
| | | Value of Medical
| |
Name | | Payments | | | Benefits | |
| |
| John J. Lipinski (severance if terminated without cause or resigns for good reason) | | $ | 1,950,000 | | | $ | 25,106 | |
| John J. Lipinski (supplemental disability payments if terminated due to disability) | | $ | 650,000 | | | | — | |
| Stanley A. Riemann (severance if terminated without cause or resigns for good reason) | | $ | 525,000 | | | $ | 12,553 | |
| James T. Rens (severance if terminated without cause or resigns for good reason) | | $ | 250,000 | | | $ | 11,998 | |
| Robert W. Haugen (severance if terminated without cause or resigns for good reason) | | $ | 275,000 | | | $ | 11,998 | |
| Daniel J. Daly, Jr. (severance if terminated without cause or resigns for good reason) | | $ | 215,000 | | | $ | 3,899 | |
Equity Compensation Plan Information
The following table shows the total number of outstanding options and shares available for future issuances under our equity compensation plans as of December 31, 2007.
| | | | | | | | | | | | | |
| | | Number of
| | | | | | Number of Securities
| |
| | | Securities to Be
| | | | | | Remaining Available
| |
| | | Issued Upon
| | | Weighted-Average
| | | for Future Issuance
| |
| | | Exercise of
| | | Exercise Price of
| | | Under Equity
| |
| | | Outstanding
| | | Outstanding
| | | Compensation Plans
| |
| | | Options, Warrants
| | | Options, Warrants
| | | (Excluding Securities
| |
Plan Category | | and Rights | | | and Rights | | | Reflected in Column (a) | |
| |
| Equity Compensation Plans Approved by Security Holders | | | 18,900 | | | $ | 21.61 | | | | 7,463,600 | |
| Equity Compensation Plans Not Approved by Security Holders | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | | 18,900 | | | $ | 21.61 | | | | 7,463,600 | |
| | | | | | | | | | | | | |
206
Director Compensation for 2007
The following table provides compensation information for the year ended December 31, 2007 for each non-management director of our board.
| | | | | | | | | | | | | | | | | | | | | |
| | | Fees
| | | | | | | | | | | | | |
| | | Earned or
| | | Stock
| | | Option
| | | All Other
| | | | |
Name | | Paid in Cash | | | Awards(1)(2) | | | Awards(3)(4)(5) | | | Compensation | | | Total | |
| |
| Wesley K. Clark* | | $ | 60,000 | | | | — | | | | — | | | $ | 449,290 | (6) | | $ | 509,290 | |
| Regis B. Lippert | | $ | 35,000 | | | $ | 11,885 | | | $ | 7,737 | | | | — | | | $ | 54,662 | |
| Mark E. Tomkins | | $ | 75,000 | | | $ | 29,714 | | | $ | 7,737 | | | | — | | | $ | 112,451 | |
| Scott L. Lebovitz, George E. Matelich, Stanley de J. Osborne and Kenneth A. Pontarelli | | | — | | | | — | | | | — | | | | — | | | | — | |
| | |
| * | | Wesley K. Clark, who was first elected to the board of Coffeyville Acquisition LLC in 2006, advised the board that due to his various outside interests and responsibilities he did not want to be nominated for reelection. Steve A. Nordaker replaced Mr. Clark on our board effective June 6, 2008. |
|
| (1) | | Mr. Lippert and Mr. Tomkins were awarded 5,000 and 12,500 shares of restricted stock, respectively, on October 22, 2007. The dollar amounts in the table reflect the dollar amounts recognized for financial statement reporting purposes for the fiscal year ended December 31, 2007 in accordance with SFAS 123(R). Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. |
|
| (2) | | The grant date fair value of stock awards granted during 2007, calculated in accordance with SFAS 123(R), was $104,400 for Mr. Lippert and $261,000 for Mr. Tomkins. Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. |
|
| (3) | | Mr. Lippert and Mr. Tomkins were awarded stock options in respect of (x) 5,150 shares each on October 22, 2007 and (y) 4,300 shares each on December 21, 2007. The amounts in the table reflect the dollar amount recognized for financial statement reporting purposes for the fiscal year ended December 31, 2007, in accordance with SFAS 123(R). Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. |
|
| (4) | | The grant date fair value of Mr. Lippert’s and Mr. Tomkins’ option awards granted during 2007, calculated in accordance with FAS 123(R), was $117,881 for each director. Assumptions used in these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. |
|
| (5) | | The aggregate number of shares subject to option awards outstanding on December 31, 2007 was 9,450 for each of Messrs. Lippert and Tomkins. |
|
| (6) | | Mr. Clark was awarded 244,038 phantom service points and 244,038 phantom performance points under the Coffeyville Resources, LLC Phantom Unit Plan (Plan I) in September 2005 for his services as a director. Collectively, Mr. Clark’s phantom points represent 2.44% of the total phantom points awarded. The value of the interest was $71,234 on the grant date. In accordance with SFAS 123(R), we apply a fair-value-based measurement method in accounting for share-based issuance of the phantom points. An independent third-party valuation was performed as of December 31, 2007 using the December 31, 2007 CVR Energy common stock closing price on the NYSE to determine the equity value of CVR Energy. Assumptions used in the calculation of these amounts are included in footnote 3 to the Company’s audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. The phantom points are |
207
| | |
| | more fully described below under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. |
Non-employee directors who do not work principally for entities affiliated with us were entitled to receive an annual retainer of $60,000 for 2007. In addition, all directors are reimbursed for travel expenses and other out-of-pocket costs incurred in connection with their attendance at meetings. Effective January 1, 2007, Mark Tomkins joined our board of directors. Mr. Tomkins was elected as the chairman of the audit committee and in that role he receives an additional annual retainer of $15,000. Messrs. Lebovitz, Matelich, Osborne and Pontarelli received no compensation in respect of their service as directors in 2007.
In addition to the annual retainer described above, we granted to each of Mr. Tomkins and Mr. Lippert options to purchase 5,150 shares of CVR Energy with an exercise price equal to the initial public offering price ($19.00) on October 22, 2007. These options generally vest in one-third annual increments beginning on the first anniversary of the date of grant. We also granted 12,500 restricted shares of CVR Energy to Mr. Tomkins and 5,000 restricted shares of CVR Energy to Mr. Lippert on October 24, 2007. These shares of restricted stock generally vest in one-third annual increments beginning on the first anniversary of the date of grant, although the holder has the right to vote the shares whether or not they have vested. We also granted to each of Mr. Tomkins and Mr. Lippert options to purchase 4,300 shares of CVR Energy with an exercise price of $24.73 on December 21, 2007.
In connection with his election to our board of directors, we granted Mr. Nordaker options to purchase 4,350 shares of CVR Energy stock with an exercise price of $24.96 on June 10, 2008.
All grants were made pursuant to our 2007 Long Term Incentive Plan.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table presents information regarding beneficial ownership of our common stock as of June 30, 2006, and as adjusted to reflect the sale of common stock in this offering by:
| | |
| | • | each of our directors; |
| |
| | • | each of our named executive officers; |
| |
| | • | each stockholder known by us to beneficially hold five percent or more of our common stock; |
| |
| | • | each selling stockholder who beneficially owns less than five percentall of our common stock;executive officers and directors as a group; and |
| |
| | • | all of our executive officers and directors as a group.selling stockholders. |
Beneficial ownership is determined under the rules of the SEC and generally includes voting or investment power with respect to securities. Unless indicated below, to our knowledge, the persons and entities named in the table have sole voting and sole investment power with respect to all shares beneficially owned, subject to community property laws where applicable. Shares of common stock subject to options that are currently exercisable or exercisable within 60 days of June 30, 2006the date of this prospectus are deemed to be outstanding and to be beneficially owned by the person holding thesuch options for the purpose of computing the percentage ownership of that person but are not treated as outstanding for the purpose of computing the percentage ownership of any other person. Except as otherwise indicated, the business address for each of our beneficial owners isc/o CVR Energy, Inc., 2277 Plaza Drive, Suite 500, Sugar Land, Texas 77479.
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | Shares Beneficially
| |
| | | Shares Beneficially Owned
| | | Number of
| | | Owned
| |
Beneficial Owner
| | prior to the offering | | | Shares
| | | after the offering† | |
Name and Address | | Number | | | Percent | | | Offered† | | | Number | | | Percent | |
| |
| Coffeyville Acquisition LLC(1) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| Kelso Investment Associates VII, L.P.(1) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| KEP Fertilizer, LLC(1) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
320 Park Avenue, 24th Floor
New York, New York 10022 | | | | | | | | | | | | | | | | | | | | |
| Coffeyville Acquisition II LLC(2) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| The Goldman Sachs Group, Inc.(2) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
85 Broad Street
New York, New York 10004 | | | | | | | | | | | | | | | | | | | | |
| John J. Lipinski(3) | | | 247,471 | | | | | * | | | 45,000 | | | | 202,471 | | | | | * |
| Stanley A. Riemann(4) | | | — | | | | — | | | | — | | | | — | | | | — | |
| James T. Rens(5) | | | — | | | | — | | | | — | | | | — | | | | — | |
| Robert W. Haugen(6) | | | 5,000 | | | | | * | | | — | | | | 5,000 | | | | | * |
| Daniel J. Daly, Jr.(7) | | | — | | | | — | | | | — | | | | — | | | | — | |
| Scott L. Lebovitz(2) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| Regis B. Lippert(8) | | | 7,500 | | | | | * | | | — | | | | 7,500 | | | | | * |
| George E. Matelich(1) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| Steve A. Nordaker(9) | | | — | | | | — | | | | — | | | | — | | | | — | |
| Stanley de J. Osborne(1) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| Kenneth A. Pontarelli(2) | | | 31,433,360 | | | | 36.5 | % | | | 4,977,500 | | | | 26,455,860 | | | | 30.7 | % |
| Mark Tomkins(10) | | | 12,500 | | | | | * | | | — | | | | 12,500 | | | | | * |
| All directors and executive officers, as a group (16 persons)(11) | | | 63,145,691 | | | | 73.3 | % | | | 10,000,000 | | | | 53,145,691 | | | | 61.7 | % |
Prior to this offering, Coffeyville Acquisition LLC owned 100% of our outstanding common stock. Following the closing of this offering, Coffeyville Acquisition LLC will own shares of our common stock, or approximately % of our outstanding common stock, and the Goldman Sachs Funds and the Kelso Funds, along with certain members of management, will beneficially own their interests in our common stock set forth below through their ownership of Coffeyville Acquisition LLC. The information in the table below reflects the number of shares of our common stock that correspond to each named holder’s economic interest in common units in Coffeyville Acquisition LLC and does not reflect any economic interest in operating override units and value override units in Coffeyville Acquisition LLC.
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| | | | | | | | | | | | | | | | | | | | | | | | |
| † | | | | | | Shares Beneficially
|
| | Shares Beneficially
| | Owned After this Offering |
| | Owned Prior
| | Assuming the
| | Assuming the
|
| | to this
| | Underwriters’ Option Is
| | Underwriters’ Option Is
|
| | Offering | | Not Exercised(1) | | Exercised(1) |
Name and Address
| | Number | | Percent | | Number | | Percent | | Number | | Percent |
|
Coffeyville Acquisition LLC(2)(3) | | | | | | | | | | | | | | | | | | | | | | | | |
The Goldman Sachs Group, Inc.(2) | | | | | | | | | | | | | | | | | | | | | | | | |
85 Broad Street | | | | | | | | | | | | | | | | | | | | | | | | |
New York, New York 10004 | | | | | | | | | | | | | | | | | | | | | | | | |
Kelso Investment
Associates VII, L.P. | | | | | | | | | | | | | | | | | | | | | | | | |
KEP VI, LLC(3) | | | | | | | | | | | | | | | | | | | | | | | | |
320 Park Avenue, 24th Floor | | | | | | | | | | | | | | | | | | | | | | | | |
New York, New York 10022 | | | | | | | | | | | | | | | | | | | | | | | | |
John J. Lipinski | | | | | | | | | | | | | | | | | | | | | | | | |
Stanley A. Riemann | | | | | | | | | | | | | | | | | | | | | | | | |
James T. Rens | | | | | | | | | | | | | | | | | | | | | | | | |
Edmund S. Gross | | | | | | | | | | | | | | | | | | | | | | | | |
Robert W. Haugan | | | | | | | | | | | | | | | | | | | | | | | | |
Wyatt E. Jernigan | | | | | | | | | | | | | | | | | | | | | | | | |
Kevan A. Vick | | | | | | | | | | | | | | | | | | | | | | | | |
Christopher G. Swanberg | | | | | | | | | | | | | | | | | | | | | | | | |
Wesley Clark | | | | | | | | | | | | | | | | | | | | | | | | |
Scott Lebovitz | | | | | | | | | | | | | | | | | | | | | | | | |
George E. Matelich(3) | | | | | | | | | | | | | | | | | | | | | | | | |
Stanley de J. Osborne | | | | | | | | | | | | | | | | | | | | | | | | |
Kenneth A. Pontarelli | | | | | | | | | | | | | | | | | | | | | | | | |
AllLLC and Coffeyville Acquisition II LLC have granted the underwriters the option to purchase from them, on a pro rata basis, an aggregate of 1,500,000 additional shares. If the option to purchase additional shares were exercised in full, after the offering Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC would each own 25,705,860 shares, or 29.8%, of our common stock, and all of our directors and executive officers, as a group, (13 persons)would own 51,645,691 shares, or 60.0%, of our common stock. | | | | | | | | | | | | | | | | | | | | | | | |
| |
| * | | Less than 1%. |
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| (1) | | The underwriters have an option to purchase up to an additional shares from the selling stockholder in this offering. If the underwriters exercise this option, shares would be sold to the underwriters by Coffeyville Acquisition LLC and Coffeyville Acquisition LLC would distribute the proceeds to its members. |
|
(2) | | The Goldman Sachs Group, Inc., and certain affiliates, including Goldman, Sachs & Co., may be deemed to directly or indirectly own in the aggregateowns 31,433,360 shares of common stock which are owned directly or indirectly by investment partnerships, which we refer to as the Goldman Sachs Funds, of which affiliates of The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. are the general partner, managing limited partner or the managing partner. Goldman, Sachs & Co. is the investment manager for certain of the Goldman Sachs Funds. Goldman, Sachs & Co. is a direct and indirect, wholly owned subsidiary of The Goldman Sachs Group, Inc. The Goldman Sachs Group, Inc., Goldman, Sachs & Co. and the Goldman Sachs Funds share voting power and investment power with certain of their respective affiliates. Shares beneficially owned by the Goldman Sachs Funds consist of: (1) shares of common stock owned by GS Capital Partners V Fund, L.P., (2) shares of common stock owned by GS Capital Partners V |
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| | |
| | Offshore Fund, L.P., (3) shares of common stock owned by GS Capital Partners V Institutional, L.P., and (4) shares of common stock owned by GS Capital Partners V GmbH & Co. KG. Ken Pontarelli is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. each disclaims beneficial ownership of the shares of common stock owned directly or indirectly by the Goldman Sachs Funds, except to the extent of their pecuniary interest therein, if any. If the underwriters exercise their option to purchase additional shares in full, (1) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Fund, L.P., (2) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Offshore Fund, L.P., (3) shares of common stock will be sold in respect of member units owned by GS Capital Partners V Institutional, L.P. and (4) shares of common stock will be sold in respect of member units owned by GS Capital Partners V GmbH & Co. KG. |
|
(3) | | With respect to the total number of shares of common stock beneficially owned prior to this offering, the share amount includes (1) shares of common stock owned bystock. Kelso Investment Associates VII, L.P. (“KIA VII”), a Delaware limited partnership, or KIA VII, and (2)owns a number of common units in Coffeyville Acquisition LLC that corresponds to 24,557,883 shares of common stock, owned byand KEP VI,Fertilizer, LLC (“KEP Fertilizer”), a Delaware limited liability company, owns a number of common units in Coffeyville Acquisition LLC that corresponds to 6,081,000 shares of common stock. The Kelso Funds may be deemed to beneficially own indirectly, in the aggregate, all of the common stock of the Company owned by Coffeyville Acquisition LLC because the Kelso Funds control Coffeyville Acquisition LLC and have the power to vote or KEP VI.dispose of the common stock of the Company owned by Coffeyville Acquisition LLC. KIA VII and KEP VI,Fertilizer, due to their common control, could be deemed to beneficially own each of the other’s shares but each disclaims such beneficial ownership. Messrs. Nickell, Wall, Matelich, Goldberg, Bynum, Wahrhaftig, Bynum, Berney, Loverro, Connors, Osborne and ConnorsMoore may be deemed to share beneficial ownership of shares of common stock owned of record or beneficially owned by KIA VII, KEP Fertilizer and Coffeyville Acquisition LLC by virtue of their status as managing members of KEP VIFertilizer and of Kelso GP VII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of Kelso GP VII, L.P., a Delaware limited partnership, the principal business of which is serving as the general partner of KIA VII. Each of Messrs. Nickell, Wall, Matelich, Goldberg, Bynum, Wahrhaftig, Bynum, Berney, Loverro, Connors, Osborne and ConnorsMoore share investment and voting power with respect to the ownership interests owned by KIA VII, KEP Fertilizer and KEP VICoffeyville Acquisition LLC but disclaim beneficial ownership of such interests. If |
|
| (2) | | Coffeyville Acquisition II LLC directly owns 31,433,360 shares of common stock. GS Capital Partners V Fund, L.P., GS Capital Partners V Offshore Fund, L.P., GS Capital Partners V GmbH & Co. KG and GS Capital Partners V Institutional, L.P. (collectively, the underwriters exercise their option“Goldman Sachs Funds”) are members of Coffeyville Acquisition II LLC and own common units of Coffeyville Acquisition II LLC. The Goldman Sachs Funds’ common units in Coffeyville Acquisition II LLC correspond to purchase additional31,125,918 shares of common stock. The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. may be deemed to beneficially own indirectly, in full,the aggregate, all of the common stock owned by Coffeyville Acquisition II LLC through the Goldman Sachs Funds because (i) affiliates of Goldman, Sachs & Co. and The Goldman Sachs Group, Inc. are the general partner, managing general partner, managing partner, managing member or member of the Goldman Sachs Funds and (ii) the Goldman Sachs Funds control Coffeyville Acquisition II LLC and have the power to vote or dispose of the common stock of the Company owned by Coffeyville Acquisition II LLC. Goldman, Sachs & Co. is a direct and indirect wholly owned subsidiary of The Goldman Sachs Group, Inc. Goldman, Sachs & Co. is the investment manager of certain of the Goldman Sachs Funds. Shares that may be deemed to be beneficially owned by the Goldman Sachs Funds consist of: (1) 16,389,665 shares of common stock willthat may be sold in respect of member unitsdeemed to be beneficially owned by KIA VIIGS Capital Partners V Fund, L.P. and (ii)its general partner, GSCP V Advisors, L.L.C., (2) 8,466,218 shares of common stock willthat may be sold in respect of member unitsdeemed to be beneficially owned by KEP VI.GS Capital Partners V Offshore Fund, L.P. and its general partner, GSCP V Offshore Advisors, L.L.C., (3) 5,620,242 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Institutional, L.P. and its general partner, GSCP V Advisors, L.L.C., and (4) 649,793 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V GmbH & Co. KG and its general partner, Goldman, Sachs Management GP GmbH. Kenneth A. Pontarelli is a partner managing director of Goldman, Sachs & Co. and Scott L. Lebovitz is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, Mr. Lebovitz, The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. each disclaims beneficial ownership of the shares of common stock owned directly or indirectly by the Goldman Sachs Funds, except to the extent of their pecuniary interest therein, if any. |
|
| (3) | | Mr. Lipinski owns 247,471 shares of common stock directly. In addition, Mr. Lipinski owns 158,285 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Lipinski does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Lipinski also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Lipinski beneficial ownership of any |
139210
| | |
| | shares of our common stock because they do not give Mr. Lipinski the power to vote or dispose of any such shares. |
|
| (4) | | Mr. Riemann owns no shares of common stock directly. Mr. Riemann owns 97,408 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Riemann does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Riemann also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year- End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Riemann beneficial ownership of any shares of our common stock because they do not give Mr. Riemann the power to vote or dispose of any such shares. |
|
| (5) | | Mr. Rens owns no shares of common stock directly. Mr. Rens owns 60,879 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Rens does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Rens also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Rens beneficial ownership of any shares of our common stock because they do not give Mr. Rens the power to vote or dispose of any such shares. |
|
| (6) | | Mr. Haugen owns 5,000 shares of common stock directly. Mr. Haugen owns 24,352 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Haugen does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Haugen also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Haugen beneficial ownership of any shares of our common stock because they do not give Mr. Haugen the power to vote or dispose of any such shares. |
|
| (7) | | Mr. Daly owns no shares of common stock directly. Mr. Daly owns 12,176 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Daly does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Daly also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Daly beneficial ownership of any shares of our common stock because they do not give Mr. Daly the power to vote or dispose of any such shares. |
|
| (8) | | In connection with our initial public offering, our board awarded 5,000 shares of non-vested restricted stock to Mr. Lippert. The date of grant for these shares of restricted stock was October 24, 2007. Under the terms of the restricted stock agreement, Mr. Lippert has the right to vote his shares of restricted stock after the date of grant. However, the transfer restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. Because Mr. Lippert has the right to vote his non-vested shares of restricted stock, he is deemed to have beneficial ownership of such shares. In addition, our board awarded Mr. Lippert options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price of our |
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| | common stock, which was $19.00 per share. The date of grant for these options was October 22, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, our board awarded Mr. Lippert options to purchase 4,300 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.73. The date of grant for these options was December 21, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, members of Mr. Lippert’s immediate family own 2,500 shares of our common stock directly. Mr. Lippert disclaims beneficial ownership of shares of our common stock owned by members of his immediate family. |
|
| (9) | | In connection with joining our board in June 2008, our board awarded Mr. Nordaker options to purchase 4,350 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.96. The date of grant for these options was June 10, 2008. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. |
|
| (10) | | In connection with our initial public offering, our board awarded 12,500 shares of non-vested restricted stock to Mark Tomkins. The date of grant for these shares of restricted stock was October 24, 2007. Under the terms of the restricted stock agreement, Mr. Tomkins has the right to vote his shares of restricted stock after the date of grant. However, the transfer restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. Because Mr. Tomkins has the right to vote his non-vested shares of restricted stock, he is deemed to have beneficial ownership of such shares. In addition, our board awarded Mr. Tomkins options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price of our common stock, which was $19.00 per share. The date of grant for these options was October 22, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. Additionally, our board awarded Mr. Tomkins options to purchase 4,300 shares of common stock with an exercise price equal to the closing price of our common stock on the date of grant, which was $24.73. The date of grant for these options was December 21, 2007. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. |
|
| (11) | | The number of shares of common stock owned by all directors and executive officers, as a group, reflects the sum of (1) all shares of common stock directly owned by Coffeyville Acquisition LLC, with respect to which Messrs. George Matelich and Stanley de J. Osborne may be deemed to share beneficial ownership, (2) all shares of common stock directly owned by Coffeyville Acquisition II LLC, with respect to which Messrs. Kenneth A. Pontarelli and Scott L. Lebovitz may be deemed to share beneficial ownership, (3) the 247,471 shares of common stock owned directly by Mr. John J. Lipinski, the 1,000 shares of common stock owned directly by Mr. Gross, the 5,000 shares of common stock owned directly by Mr. Haugen, the 3,500 shares of common stock owned directly by Mr. Jernigan, the 1,000 shares of common stock owned directly by Mr. Vick and the 1,000 shares of common stock owned directly by Mr. Swanberg, (4) the 12,500 shares owned by Mr. Tomkins and (5) the 5,000 shares owned by Mr. Lippert and the 2,500 shares owned by members of Mr. Lippert’s family. |
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Distributions of the Proceeds of this Offering by Coffeyville Acquisition and
Coffeyville Acquisition II
Coffeyville Acquisition and Coffeyville Acquisition II expect to distribute the proceeds of their sale of common stock in this offering to their members pursuant to their respective limited liability company agreements. If all of the shares of common stock of our Company to be sold in this offering by Coffeyville Acquisition and Coffeyville Acquisition II were sold at $24.92 per share, which was the price of our common stock on June 16, 2008, after giving effect to the underwriting discount, each of the entities and individuals named below would receive the following approximate amounts:
| | | | | | | | | |
| | | Distribution if
| | | Distribution if
| |
| | | Underwriters’ Option
| | | Underwriters’ Option
| |
Entity / Individual | | is not Exercised | | | is Exercised in Full | |
| |
| The Goldman Sachs Funds | | $ | 113,675,494 | | | $ | 130,345,080 | |
| The Kelso Funds | | | 111,896,782 | | | | 128,305,534 | |
| John J. Lipinski | | | 3,488,826 | | | | 4,270,538 | |
| Stanley A. Riemann | | | 1,613,338 | | | | 1,974,864 | |
| James T. Rens | | | 871,197 | | | | 1,062,613 | |
| Robert W. Haugen | | | 749,569 | | | | 921,423 | |
| Daniel J. Daly, Jr. | | | 519,703 | | | | 640,758 | |
| All executive officers, as a group | | | 8,912,303 | | | | 10,328,499 | |
| All management members, as a group | | | 10,412,670 | | | | 12,738,798 | |
| All other members, as a group | | | 2,001,050 | | | | 2,294,488 | |
Payment to be made by the Company in respect of Phantom Points held by Our
Named Executive Officers as a result of this Offering by Coffeyville
Acquisition and Coffeyville Acquisition II
If all of the shares of common stock of our Company to be sold in this offering by Coffeyville Acquisition and Coffeyville Acquisition II were sold at $24.92 per share, which was the price of our common stock on June 16, 2008, after giving effect to the underwriting discount, each of the individuals named below would receive the following approximate amounts from the Company pursuant to the Phantom Unit Plans:
| | | | | | | | | |
| | | Distribution if
| | | Distribution if
| |
| | | Underwriters’ Option
| | | Underwriters’ Option
| |
Individual | | is not Exercised | | | is Exercised in Full | |
| |
| John J. Lipinski | | $ | 485,111 | | | $ | 590,816 | |
| Stanley A. Riemann | | | 211,312 | | | | 257,356 | |
| James T. Rens | | | 175,541 | | | | 213,792 | |
| Robert W. Haugen | | | 175,541 | | | | 213,792 | |
| Daniel J. Daly, Jr. | | | 195,796 | | | | 238,461 | |
| All executive officers, as a group | | | 2,181,226 | | | | 2,656,515 | |
| All management members, as a group | | | 3,488,382 | | | | 4,248,501 | |
| All other members, as a group | | | 56,228 | | | | 68,480 | |
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
This section describes related party transactions between CVR Energy (and its predecessors) and its directors, executive officers and 5% stockholders. For a description of transactions between CVR Energy and the Partnership, whose managing general partner is owned by our controlling stockholders and senior management, see “The Nitrogen Fertilizer Limited Partnership.”
Transactions with the Goldman Sachs Funds and the Kelso Funds
Investments in Coffeyville Acquisition LLC
Prior to our initial public offering in October 2007, GS Capital Partners V Fund, L.P. and related entities, or the Goldman Sachs Funds, and Kelso Investment Associates VII, L.P. and related entity, or the Kelso Funds, arewere the majority owners of Coffeyville Acquisition LLC.
Investments in Other members of Coffeyville Acquisition LLC were John J. Lipinski, Stanley A. Riemann, James T. Rens, Edmund Gross, Robert W. Haugen, Wyatt E. Jernigan, Kevan A. Vick, Christopher Swanberg, Wesley Clark, Magnetite Asset Investors III L.L.C. and other members of our management team.
On June 24, 2005, pursuant to a stock purchase agreement dated May 15, 2005, between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC, Coffeyville Acquisition LLC acquired all of the subsidiaries of Coffeyville Group Holdings, LLC. The Goldman Sachs Funds made capital contributions of $112,817,500 to Coffeyville Acquisition LLC and the Kelso Funds made capital contributions of $110,817,500 to Coffeyville Acquisition LLC in connection with the acquisition. The total proceeds received by Pegasus Partners II, L.P. and the other unit holders of Coffeyville Group Holdings, LLC, including then current management, in connection with the Subsequent Acquisition was $526,185,017, after repayment of Immediate Predecessor’s credit facility.
Coffeyville Acquisition LLC paid companies related to the Goldman Sachs Funds and the Kelso Funds each equal amounts totaling $6.0 million for the transaction fees related to the Subsequent Acquisition, as well as an additional $0.7 million paid to the Goldman Sachs Funds for reimbursed expenses related to the Subsequent Acquisition.
On July 25, 2005, the following executive officers and directors made the following capital contributions to Coffeyville Acquisition LLC: John J. Lipinski, $650,000; Stanley A. Riemann, $400,000; James T. Rens, $250,000; Kevan A. Vick, $250,000; Robert W. Haugan,Haugen, $100,000; Wyatt E. Jernigan, $100,000; Chris Swanberg, $25,000. On September 12, 2005, Edmund Gross made a $30,000 capital contribution to Coffeyville Acquisition LLC. On September 20, 2005, Wesley Clark made a $250,000 capital contribution to Coffeyville Acquisition LLC. All but two of the executive officers received common units, operating units and value units of Coffeyville Acquisition LLC and the director received common units of Coffeyville Acquisition LLC.
On September 14, 2005, the Goldman Sachs Funds and the Kelso Funds each invested an additional $5.0 million in Coffeyville Acquisition LLC. On May 23, 2006, the Goldman Sachs Funds and the Kelso Funds each invested an additional $10.0 million in Coffeyville Acquisition LLC. In each case they received additional common units of Coffeyville Acquisition LLC.
On December 28, 2006, the directors of Coffeyville Acquisition LLC approved a cash dividend of $244,710,000 to companies related to the Goldman Sachs Funds and the Kelso Funds and $3,360,393 to certain members of our management team, including John J. Lipinski ($914,844), Stanley A. Riemann ($548,070), James T. Rens ($321,180), Kevan A. Vick ($321,180), Robert W. Haugen ($164,680) and Wyatt E. Jernigan ($164,680), as well as Wesley Clark ($241,205).
Split of Coffeyville Acquisition LLC
As part of the restructuring transactions that occurred immediately prior to our initial public offering, Coffeyville Acquisition LLC redeemed all of its outstanding common units held by the Goldman Sachs Funds in exchange for the same number of common units in Coffeyville Acquisition II LLC, a newly formed limited liability company to which Coffeyville Acquisition LLC transferred half of its interests in each of Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy. In addition, half of the common units and override units in Coffeyville Acquisition
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LLC held by each executive officer and Wesley Clark were redeemed in exchange for an equal number of common units and override units in Coffeyville Acquisition II LLC. As a result of these restructuring transactions, the Kelso Funds became the majority owner of Coffeyville Acquisition LLC and the Goldman Sachs Funds became the majority owner of Coffeyville Acquisition II LLC, and management and Wesley Clark retained an equivalent interest in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.
Stockholders Agreement
In October 2007, we entered into a stockholders agreement with Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Pursuant to the agreement, for so long as Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC collectively beneficially own in the aggregate an amount of our common stock that represents at least 40% of our outstanding common stock, Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC each have the right to designate two directors to our board of directors so long as that party holds an amount of our common stock that represents 20% or more of our outstanding common stock and one director to our board of directors so long as that party holds an amount of our common stock that represents less than 20% but more than 5% of our outstanding common stock. If Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC cease to collectively beneficially own in the aggregate an amount of our common stock that represents at least 40% of our outstanding common stock, the foregoing rights become a nomination right and the parties to the stockholders agreement are not obligated to vote for each other’s nominee. In addition, the stockholders agreement contains certain tag-along rights with respect to certain transfers (other than underwritten offerings to the public) of shares of common stock by the parties to the stockholders agreement. For so long as Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC beneficially own in the aggregate at least 40% of our common stock, (i) each such stockholder that has the right to designate at least two directors will have the right to have at least one of its designated directors on any committee (other than the audit committee and conflicts committee), to the extent permitted by SEC or NYSE rules, (ii) directors designated by the stockholders will be a majority of each such committee (at least 50% in the case of the compensation committee and the nominating committee), and (iii) the chairman of each such committee will be a director designated by such stockholder.
Registration Rights Agreements
In October 2007 we entered into a registration rights agreement with Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC pursuant to which we may be required to register the sale of our shares held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and permitted transferees. Under the registration rights agreement, the Goldman Sachs Funds and the Kelso Funds each have the right to request that we register the sale of shares held by Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, as applicable, on their behalf on three occasions including requiring us to make available shelf registration statements permitting sales of shares into the market from time to time over an extended period. In addition, the Goldman Sachs Funds and the Kelso Funds have the ability to exercise certain piggyback registration rights with respect to their own securities if we elect to register any of our equity securities. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of our shares held by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC are entitled to these registration rights.
Dividend
In connection with our initial public offering in October 2007, the directors of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively, approved a special dividend of approximately $10.6 million to their members, including $5,227,584 to the Goldman Sachs Funds, $5,145,787 to the Kelso Funds, $81,798 to Magnetite Asset Investors III L.L.C. and $103,269 to certain members of our senior management team and Wesley K. Clark. The common unitholders receiving this special dividend then contributed approximately $10.6 million collectively to Coffeyville
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Acquisition III LLC, which used such amounts to acquire CVR GP, LLC, the managing general partner of the Partnership, from us.
J. Aron & Company
In June 2005 Coffeyville Acquisition LLC entered into commodity derivative contracts in the form of three swap agreements for the period from July 1, 2005 through June 30, 2010 with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. The swap agreements were originally entered into by Coffeyville Acquisition LLC on June 16, 2005 in conjunction with the acquisition of Immediate Predecessor and were required under the terms of our long-term debt agreements. The swap agreements were executed at the prevailing market rate at the time of execution and management believes the swap agreements provide an economic hedge on future transactions.(the “Cash Flow Swap”). These agreements were assigned to Coffeyville Resources, LLC, a subsidiary of the Company, on June 24, 2005. The economically hedged volumes totalBased on crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 70%58% and 14% of their forecasted production fromcrude oil capacity for the periods July 20051, 2008 through June 30, 2009 and approximately 17% from July 1, 2009 through June 2010. At30, 2010, respectively. Under the terms of our credit facility (the “Credit Facility”), upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, so long as at the time of reduction or termination, we pay the amount of unrealized losses associated with the amount reduced or terminated. The Cash Flow Swap has resulted in unrealized gains (losses) of approximately $(235.9) million, $126.8 million and $(103.2) million for the years ended December 31, 2005, these positions resulted in unrealized losses of approximately $236.0 million2006 and $98.0 million for the six months ended June 30, 2006.2007, respectively. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — LiquidityCritical Accounting Policies — Derivative Instruments and Capital ResourcesFair Value of Financial Instruments” and “Description of Our Indebtedness and the Cash Flow Swap — Cash Flow Swap.”Swap”.
Effective DecemberAs a result of the flood and the temporary cessation of our Company’s operations on June 30, 2005,2007, Coffeyville AcquisitionResources, LLC enteredwas required to enter into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to August 31, 2008 the payment of approximately $123.7 million (plus accrued interest) which we owed to J. Aron. We are required to use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts.
During 2007 we were party to a crude oil supply agreement with J. Aron. Other than locally producedOn December 31, 2007, we entered into an amended and restated crude we gather ourselves, we purchase crude
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oil from third parties using a credit intermediation agreement.supply agreement with J. Aron. The terms of thisthe agreement provide that we will obtain all of the crude oil for our refinery through J. Aron, other than crude oil that we acquire in Kansas, Missouri, Oklahoma, Wyoming and all states adjacent thereto. Pursuant to the crude we obtain through our own gathering system, through J. Aron. Onceagreement, we identify cargos of crude oil and pricing terms that meet our requirements weand from time to time notify J. Aron andof sourcing opportunities that we deem acceptable. Weand/or J. Aron thennegotiate the cost of each barrel of crude oil that is purchased from third party crude oil suppliers. J. Aron executes all third party sourcing transactions and provides credit, transportation and other logistical services for the crude oil it delivers to us. We generally pay J. Aron a fixed supply service fee per barrel over the negotiated cost of each barrel of crude oil purchased. In some cases, J. Aron will sell crude oil directly to us forwithout having executed a fee. This agreement significantly reduces the investment that we are required to maintain in petroleum inventories relative to our competitors and reduces the time we are exposed to market fluctuations before the inventory is priced to a customer. The initial term of our agreement with J. Aron is to December 31, 2006 and it continues one additional year unless eitherspecific third party terminates it effective December 31, 2006and/or we may renegotiate the agreement with J. Aron, seek a similar arrangement with another party, or choose to obtain our crude supply directly without the use of an intermediary.sourcing transaction.
Coffeyville Acquisition LLC also entered into certain crude oil, heating oil and gasoline option agreements with J. Aron as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as a gain (loss) on derivatives for the 233 days ended December 31, 2005.
As a result of the refinery turnaround in early 2007, we needed to delay the processing of quantities of crude oil that we purchased from various small independent producers. In order to facilitate this anticipated delay, we entered into a purchase, storage and sale agreement for gathered crude oil, dated March 20, 2007, with J. Aron. Pursuant to the terms of the agreement, J. Aron agreed to purchase gathered crude oil from us, store the gathered crude oil and sell us the gathered crude oil on a forward basis. This agreement is no longer in effect.
Consulting and Advisory Agreements
Under the terms of separate consulting and advisory agreements, dated June 24, 2005, between Coffeyville Acquisition LLC and each of Goldman, Sachs & Co. and Kelso & Company, L.P., Coffeyville
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Acquisition LLC was required to pay an advisory fee of $1,000,000 per year, payable quarterly in advance, to each of Goldman Sachs and Kelso for consulting and advisory services provided by Goldman Sachs and Kelso. The advisory agreements provide that Coffeyville Acquisition LLC will indemnify Goldman Sachs and Kelso and their respective affiliates, designees, officers, directors, partners, employees, agents and control persons (as such term is used in the Securities Act and the rules and regulations thereunder), to the extent lawful, against claims, losses and expenses as incurred in connection with the services rendered to Coffeyville Acquisition LLC under the consulting and advisory agreements or arising out of any such person being a controlling person of Coffeyville Acquisition LLC. The agreements also provide that Coffeyville Acquisition LLC will reimburse expenses incurred by Goldman Sachs and Kelso in connection with their investment in Coffeyville Acquisition and with respect to services provided to Coffeyville Acquisition LLC pursuant to the consulting and advisory agreements. The consulting and advisory agreements also provide for the payment of certain fees, as may be determined by mutual agreement, payable by Coffeyville Acquisition LLC to Goldman Sachs and Kelso in connection with transaction services and for the reimbursement of expenses incurred in connection with such services. Payments relating to the consulting and advisory agreements include $1,310,416, $2,315,937 and $1,703,990 which was expensed in selling, general, and administrative expenses for the 233 days ended December 31, 2005. In addition, $1,046,575 was included in other current liabilities and approximately $78,671 was included in accounts payable at2005, the year ended December 31, 2005.
On , 2006 Coffeyville Acquisition LLC entered into terminationand the year ended December 31, 2007, respectively. These agreements were terminated in connection with Goldman Sachsour initial public offering in October 2007 and Kelso under which Coffeyville Acquisition LLC agreed to pay each of Goldman, Sachs & Co. and Kelso & Company, L.P. received a one-time fee of $5 million payable uponby reason of such termination in conjunction with the consummation of this offering. Pursuant to the terms of the termination letter, in return for the $5 million fee, the annual advisory fee and any obligations with respect to certain other fees will terminate. In addition, pursuant to the termination letter, the obligations of Goldman Sachs and Kelso with respect to consulting and other services will terminate after Goldman Sachs or Kelso no longer have beneficial ownership of our common stock in excess of % of our outstanding common stock. Coffeyville Acquisition LLC’s obligations with respect to the indemnification of Goldman Sachs and Kelso and reimbursement of expenses will survive the termination of the obligations of the parties described above.
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Credit Facilities
Goldman Sachs Credit Partners L.P., an affiliate of Goldman, Sachs & Co., or Goldman Sachs, is one of the lenders under the First Lien Credit Facility and the Second Lien Credit Facility which were entered into in connection with the financing of the Subsequent Acquisition.Facility. Goldman Sachs Credit Partners is also a joint lead arranger and bookrunner under the Credit Facility. In addition, Goldman Sachs Credit Partners L.P. was the sole arranger and sole bookrunner of the $25.0 million secured facility, the $25.0 million unsecured facility, and the $75.0 million unsecured facility, each of which was terminated in connection with the consummation of our initial public offering in October 2007. Goldman Sachs Credit Partners was also a lender, sole lead arranger, sole bookrunner and syndication agent under the First Lien Credit Facilityour first lien credit agreement and thea lender and joint lead arranger, joint bookrunner and syndication agent under our second lien credit agreement. The first lien credit agreement and second lien credit agreement were entered into in connection with the Second Lien Credit Facility. Successoracquisition of Coffeyville Group Holdings, LLC and its subsidiaries by Coffeyville Acquisition LLC in June 2005. At that time, we paid this Goldman Sachs affiliate a $22.1 million fee included in deferred financing costs. In conjunction with the financing that occurred on December 28, 2006, we paid approximately $8.1 million to a Goldman Sachs affiliate. Additionally, in conjunction with entering into the $25.0 million secured facility, the $25.0 million unsecured facility, and the $75.0 million unsecured facility on August 23, 2007, we paid approximately $1.3 million in fees and associated expense reimbursement to a Goldman Sachs affiliate. For the 233 days ended December 31, 2005, Successor made interest payments to this Goldman Sachs affiliate of $1.8 million recorded in interest expense and paid letter of credit fees of approximately $155,000 which were recorded in selling, general, and administrative expenses. See “Description of Our Indebtedness and the Cash Flow Swap.”Swap”.
Guarantees
During 2007 one of the Goldman Sachs Funds and one of the Kelso Funds each guaranteed 50% of our payment obligations under the Cash Flow Swap in the amount of $123.7 million, plus accrued interest. These guarantees remain in effect as of the date of this prospectus.
In addition, in August 2007 these funds also guaranteed our obligations under the $25.0 million secured facility, the $25.0 million unsecured facility and the $75.0 million unsecured facility. These guarantees were terminated when the credit facilities were repaid and terminated in connection with the consummation of our initial public offering in October 2007.
Initial Public Offering and Convertible Senior Notes Offering
Goldman, Sachs & Co. was the lead underwriter of our initial public offering in October 2007. Goldman, Sachs & Co. was paid a customary underwriting discount for serving as underwriter. Goldman, Sachs & Co. is also the lead underwriter for our concurrent offering of $125 million aggregate principal amount of Convertible Senior Notes due 2013.
Secondary Offering
Coffeyville Acquisition and Coffeyville Acquisition II expect to distribute the proceeds of their sale of common stock in this offering to their members pursuant to their respective limited liability company agreements. The Kelso Funds are the principal owners of Coffeyville Acquisition, and the Goldman Sachs Funds are the principal owners of Coffeyville Acquisition II. Members of our senior management team own interests in both Coffeyville Acquisition and Coffeyville Acquisition II and will receive
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proceeds from the sale of shares of our common stock by Coffeyville Acquisition and Coffeyville Acquisition II. See “Principal and Selling Stockholders”.
Transactions with John J. LipinskiDirectors and Senior Management
On June 30, 2005, Coffeyville Acquisition LLC loaned $500,000 to John J. Lipinski, CEO of Successor. This loan accrued interest at the rate of 7% per year. The loan was made in conjunction with Mr. Lipinski’s purchase of 50,000 common units of Coffeyville Acquisition LLC. Mr. Lipinski repaid $150,000 of principal and paid $17,643.84 in interest on January 13, 2006. The unpaid loan balance as of June 30, 2006 was $350,000. The loan,$350,000, together with accrued and unpaid interest of $17,989, was forgiven in full in September 2006.
On December 28, 2006, the directors of Coffeyville Nitrogen Fertilizers, Inc. approved the issuance of shares of common stock of Coffeyville Nitrogen Fertilizers, Inc., par value $0.01 per share, to John J. Lipinski in exchange for $10.00 pursuant to a Subscription Agreement. Mr. Lipinski also entered into a Stockholders Agreement with Coffeyville Nitrogen Fertilizers, Inc. and Coffeyville Acquisition LLC Operatingat the same time he entered into the Subscription Agreement. Pursuant to the Stockholders Agreement,
The Goldman Sachs Funds, the Kelso Funds, and John J. Lipinski, Stanley A. Riemann, James T. Rens, Edmund Gross, Robert W. Haugan, Wyatt E. Jernigan, Kevan A. Vick, Christopher Swanberg, Wesley Clark, Magnetite Asset Investors III L.L.C. and among other members of management beneficially own capital stock in our company through Coffeyville Acquisition LLC. The LLC Agreement includes (1) restrictions on the ability of members to transfer their interests inthings, Coffeyville Acquisition LLC (2) ahad the right to exchange all shares of first offercommon stock in the eventCoffeyville Nitrogen Fertilizers, Inc. held by Mr. Lipinski for such number of proposed sales by the Goldman Sachs Fundsand/or the Kelso Funds, and (3) tag along and drag along rights in connection with transfers by the Goldman Sachs Fundsand/or the Kelso Funds.
The LLC Agreement provides that the business and affairscommon units of Coffeyville Acquisition LLC is managed byor equity interests of a board of directors. The number of directorswholly-owned subsidiary of Coffeyville Acquisition LLC, is established by mutual consentin each case having a fair market value equal to the fair market value of the Goldman Sachs Fundscommon stock in Coffeyville Nitrogen Fertilizers, Inc. held by Mr. Lipinski.
On December 28, 2006, the directors of Coffeyville Refining & Marketing, Inc. approved the issuance of shares of common stock of Coffeyville Refining & Marketing, Inc., par value $0.01 per share, to John J. Lipinski in exchange for $10.00 pursuant to a Subscription Agreement. Mr. Lipinski entered into a stockholders agreement with Coffeyville Refining & Marketing, Inc. similar to the agreement he entered into with Coffeyville Nitrogen Fertilizers, Inc.
In August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. Mr. Lipinski also entered into a Stockholders Agreement with Coffeyville Refining & Marketing Holdings, Inc. and Coffeyville Acquisition LLC at the Kelso Funds. Thetime of the exchange. Pursuant to the Stockholders Agreement, among other things, Coffeyville Acquisition LLC Agreement provides thathad the boardright to exchange all shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. held by Mr. Lipinski for such number of common units of Coffeyville Acquisition LLC shall consistor equity interests of at least five members, including Mr. Lipinski, two directors designated by the Goldman Sachs Funds and two directors designated by the Kelso Funds. The board currently has six members. Of the current directors, Messrs. Lebovitz and Pontarelli were appointed by the Goldman Sachs Funds and Messrs. Matelich and Osborne were appointed by the Kelso Funds.
The Goldman Sachs Funds and the Kelso Funds each have the right to designate two directors to the boarda wholly-owned subsidiary of Coffeyville Acquisition LLC, so long as that party holds common units that represent both at least 20%in each case having a fair market value equal to the fair market value of the common units thenstock in Coffeyville Refining & Marketing Holdings, Inc. held by all membersMr. Lipinski.
In October 2007, prior to our initial public offering, we entered into a subscription agreement with Mr. Lipinski pursuant to which Mr. Lipinski agreed to exchange his shares of common stock of Coffeyville Nitrogen Fertilizers, Inc. and at least 50%Coffeyville Refining & Marketing Holdings, Inc. for shares of our common stock. In accordance with this agreement, we issued 247,471 shares of common stock to Mr. Lipinski. Prior to that stock issuance, Mr. Lipinski owned approximately 0.3128% of Coffeyville Refining and Marketing Holdings, Inc. and approximately 0.6401% of Coffeyville Nitrogen Fertilizer, Inc. These two companies owned all of the common units heldinterests which became owned by such party on June 24, 2005. The Goldman Sachs Funds andCVR Energy upon the Kelso Funds each have the right to designate one director for so long as such party continues to hold common units that represent at least 5%completion of the common units then held by all members. In addition, for so long as John Lipinski is President and Chief Executive Officer, he will be appointed to the board of Coffeyville Acquisition LLC. To the extent that the Goldman Funds or the Kelso Funds have no director designation rights, that party will have the right to designate a board observer to attend board meetings.
Most significant decisions involving Coffeyville Acquisition LLC and (prior to anits initial public offering) itsoffering. The allocation of value as of September 30, 2007 between Coffeyville Refining and Marketing Holdings, Inc. and Coffeyville Nitrogen Fertilizer, Inc. was 75.7717% and 24.2283%, respectively. The allocation of value was based on the two entities respective ownership interest in their subsidiaries requiretaking into effect liabilities and receivables existing between the approvaltwo companies. The number of shares issued to Mr. Lipinski was determined by grossing up the Goldman Sachs Funds or at least one Goldman Sachs Funds appointed director (for so long asshares after our stock split by the Goldman Sachs Funds have the right to appointweighted average percentage ownership of Mr. Lipinski in
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the two directors)entities and multiplying the Kelso Funds or at least one Kelso Funds appointed director (for so long asresult by Mr. Lipinski’s weighted average percentage ownership. The table below illustrates the Kelso Funds havecalculations of the rightshares issued to appoint two directors).Mr. Lipinski.
| | | | | | |
| | Relative ownership in all interests contributed to CVR Energy | | | | |
| A | | Coffeyville Refining and Marketing Holdings, Inc. | | | 75.7717 | % |
| B | | Coffeyville Nitrogen Fertilizer, Inc. | | | 24.2283 | % |
| | Mr. Lipinski’s Interests in the subsidiaries | | | | |
| D | | Coffeyville Refining and Marketing Holdings, Inc. | | | 0.3128 | % |
| E | | Coffeyville Nitrogen Fertilizer, Inc. | | | 0.6401 | % |
| | Weighted average ownership in all assets | | | | |
| F: = A x D | | Coffeyville Refining and Marketing Holdings, Inc. | | | 0.23701 | % |
| G: = B x E | | Coffeyville Nitrogen Fertilizer, Inc. | | | 0.15509 | % |
| H: = F + G | | Mr. Lipinski’s weighted average ownership interest | | | 0.3921 | % |
| I | | Original shares | | | 100.00 | |
| J | | Stock split | | | 628,667.20 | |
| K: = I x J | | Shares to members of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC | | | 62,866,720.00 | |
| L: = H x ( K/(1-H)) | | Mr. Lipinski’s shares | | | 247,471.00 | |
| M: = K + L | | Total shares before director shares, our initial public offering and employee shares | | | 63,114,191 | |
| N: = L/M | | Mr. Lipinski’s percentage of pre-offering shares | | | 0.3921 | % |
The LLC Agreement provides thatAs a record holder of CVR Energy common stock on October 16, 2007, Mr. Lipinski received a dividend of $41,562 as part of a $10.6 million dividend approved by CVR Energy’s board of directors in October 2007.
All decisions concerning Mr. Lipinski’s compensation were approved by the event that the Goldman Sachs Funds and the Kelso Funds elect to complete an initial public offering through a subsidiarycompensation committee of Coffeyville Acquisition LLC (1) Coffeyville Acquisition LLC will not vote any shares in favor of any action without the prior written consent of the Goldman Sachs Funds or at least one Goldman Sachs Funds appointed director (for so long as the Goldman Sachs Funds have the right to appoint two directors) and the Kelso Funds or at least one Kelso Funds appointed director (for so long as the Kelso Funds have the right to appoint two directors), (2) the transfer restrictions, right of first offer, tag along rights and drag along rights contained in the LLCMr. Lipinski’s participation.
Registration Rights Agreement will cease to apply, and (3) Coffeyville Acquisition LLC will enter
In October 2007, we entered into a registration rights agreement with the initial public offering issuer.
For a summary of the material terms of the LLC Agreement as they relate to the limited liability interests granted to our executive officers, see “Management — Employment Agreements andChange-in-Control Arrangements — Executives’ Interests in Coffeyville Acquisition LLC.”
Registration Rights Agreement
We intend to enter into a registration rights agreement immediately prior to the completion of this offering with Coffeyville Acquisition LLC pursuant to which we may be required to register the sale of our shares held by Coffeyville Acquisition LLC and permitted transferees.John J. Lipinski. Under the registration rights agreement, the Goldman Sachs Funds and the Kelso Funds will have the right to request that we register the sale of shares held by Coffeyville Acquisition LLC on their behalf and may require us to make available shelf registration statements permitting sales of shares into the market from time to time over an extended period. In addition, the members of Coffeyville Acquisition LLC (including members of management)Mr. Lipinski will have the ability to exercise certain piggyback registration rights if we electwith respect to registerhis own securities if any of our equity securities.securities are offered to the public pursuant to a registration statement. The registration rights agreement is also expected to includeincludes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. Immediately after this offering, allAll of the shares in our sharescompany held directly by Coffeyville Acquisition LLC will beJohn J. Lipinski are entitled to these registration rights.
Wesley Clark Consulting Agreement
In connection with his retirement from our board of directors, we entered into a consulting agreement with General Wesley Clark whereby Mr. Clark will provide consulting and advisory services to us for a two year period in exchange for a monthly retainer of $2,000. As a member of the board of directors, Mr. Clark had been granted 244,038 Phantom Performance Points and 244,038 Phantom Services Points (together, the “Points”) under the Coffeyville Resources, LLC Phantom Unit Plan. Upon his leaving the board, Mr. Clark forfeited these Points. As additional compensation for his services as a consultant, Mr. Clark will receive a payment equal to the amounts that would have been distributed to Mr. Clark in respect of 65% of his Points had he continued to hold them during the period beginning on the annual meeting date and ending on the earlier of (i) December 1, 2010 or (ii) the date of the consummation of an Exit Event (as defined in the Coffeyville Acquisition LLC Limited Liability Company Agreement) (but no earlier than January 15, 2009) (the “Payment Date”). In addition, Mr. Clark will receive the amount that would have been distributed in respect of 65% of his Points on the Payment Date assuming that (i) Mr. Clark remained on the board, (ii) all of the common stock of the Company then held by Coffeyville Acquisition LLC and Coffeyville Acquisition LLC II was sold at the closing price of common stock on the New York Stock Exchange on such Payment Date and (iii) the proceeds were distributed to the members of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC on such Payment Date pursuant to the LLC Agreements of each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC.
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Transactions with Pegasus Partners II, L.P.
Pegasus Partners II, L.P., or Pegasus, was a majority owner of Coffeyville Group Holdings, LLC (Immediate Predecessor) during the period March 3, 2004 through June 24, 2005. On March 3, 2004, Coffeyville Group Holdings, LLC, through its wholly owned subsidiary, Coffeyville Resources, LLC, acquired the assets of the former Farmland petroleum division and one facility within Farmland’s nitrogen fertilizer manufacturing and marketing division through a bankruptcy court auction process for approximately $107 million and the assumption of approximately $23 million of liabilities.
On March 3, 2004, Coffeyville Group Holdings, LLC entered into a management services agreement with Pegasus Capital Advisors, L.P., pursuant to which Pegasus Capital Advisors, L.P. provided Coffeyville Group Holdings, LLC with managerial and advisory services. In consideration for these services, Coffeyville Group Holdings, LLC agreed to pay Pegasus Capital Advisors, L.P. an annual fee of up to $1.0 million plus reimbursement for anyout-of-pocket expenses. During the year ended December 31, 2004, Immediate Predecessor paid an aggregate of approximately $545,000 to Pegasus Capital Advisors, L.P. in fees under this agreement. $1,000,000 was expensed to selling, general, and administrative expenses for the 174 days ended June 23, 2005. In addition, Immediate Predecessor paid approximately $455,000 in legal fees on behalf of Pegasus Capital Advisors, L.P. in lieu of the remaining amount owed under the management fee. This management services agreement terminated at the time of the Subsequent Acquisition in June 2005.
Coffeyville Group Holdings, LLC paid Pegasus Capital Advisors, L.P. a $4.0 million transaction fee upon closing of the acquisition on March 3, 2004. The transaction fee related to a $2.5 million merger and acquisition fee and a $1.5 million in deferred financing costs. In addition, in conjunction
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with the refinancing of our senior secured credit facility on May 10, 2004, Coffeyville Group Holdings, LLC paid an additional $1.25 million fee to Pegasus Capital Advisors, L.P. as a deferred financing cost.
On March 3, 2004, Coffeyville Group Holdings, LLC entered into Executive Purchase and Vesting Agreements with the then executive officers listed below providing for the sale by Immediate Predecessor to them of the number of our common units to the right of each executive officer’s name at a purchase price of approximately $0.0056 per unit. Pursuant to the terms of these agreements, as amended, each executive officer’s common units were to vest at a rate of 16.66% every six months with the first 16.66% vesting on November 10, 2004. In connection with their purchase of the common units pursuant to the Executive Purchase and Vesting Agreements, each of the executive officers at that time issued promissory notes in the amounts indicated below. These notes were paid in full on May 10, 2004.
| | | | | | | | | |
| | | Number of
| | | Amount of
| |
| | | Common
| | | Promissory
| |
Executive Officer | | Units | | | Note | |
| |
| Philip L. Rinaldi | | | 3,717,647 | | | $ | 21,000 | |
| Abraham H. Kaplan | | | 2,230,589 | | | $ | 12,600 | |
| George W. Dorsey | | | 2,230,589 | | | $ | 12,600 | |
| Stanley A. Riemann | | | 1,301,176 | | | $ | 7,350 | |
| James T. Rens | | | 371,764 | | | $ | 2,100 | |
| Keith D. Osborn | | | 650,588 | | | $ | 3,675 | |
| Kevan A. Vick | | | 650,588 | | | $ | 3,675 | |
On May 10, 2004, Mr. Rinaldi entered into another Executive Purchase and Vesting Agreement under the same terms as described above providing for the purchase of an additional 500,000 common units of Coffeyville Group Holdings, LLC for an aggregate purchase price of $2,850.
On May 10, 2004, Coffeyville Group Holdings, LLC refinanced its existing long-term debt with a $150 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under Coffeyville Group Holdings, LLC’s previous credit facility. The borrowings were also used to distribute a $99,987,509 dividend, which included a preference payment of $63,200,000 plus a yield of $1,802,956 to the preferred unit holders and a $63,000 payment to the common unit holders for
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undistributed capital per the LLC agreement. The remaining $34,921,553 was distributed to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.
On October 8, 2004, Coffeyville Group Holdings, LLC entered into a joint venture with The Leiber Group, Inc., a company whose majority stockholder was Pegasus Partners II, L.P., the principal stockholder of Immediate Predecessor. In connection with the joint venture, Coffeyville Group Holdings, LLC contributed approximately 68.7% of its membership interests in Coffeyville Resources, LLC to CL JV Holdings, LLC, a Delaware limited liability company, or CL JV Holdings, and The Leiber Group, Inc. contributed the Judith Leiber business to CL JV Holdings. At the time of the Subsequent Acquisition, in June 2005, the joint venture was effectively terminated.
On January 13, 2005, Immediate Predecessor’s board of directors authorized the following bonus payments to the following then executive officers, at that time, in recognition of the importance of retaining their services:
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| | | | | |
Executive Officer | | Bonus Amount | |
| |
| Philip L. Rinaldi | | $ | 1,000,000 | |
| Abraham H. Kaplan | | $ | 600,000 | |
| George W. Dorsey | | $ | 300,000 | |
| Stanley A. Riemann | | $ | 700,000 | |
| James T. Rens | | $ | 150,000 | |
| Keith D. Osborn | | $ | 150,000 | |
| Kevan A. Vick | | $ | 150,000 | |
| Edmund S. Gross | | $ | 200,000 | |
During 2004 and 2005, Immediate Predecessor shared office space with Pegasus in New York, New York for which we paid Pegasus $10,000 per month.
On June 23, 2005, immediately prior to the Subsequent Acquisition, Coffeyville Group Holdings, LLC used available cash balances to distribute a $52,211,493 dividend to its preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.
Other Transactions
We paid INTERCAT, Inc. $525,507 during 2006 for chemical additives. Mr. Regis B. Lippert, a director of our company, is the principal shareholder and chief executive officer of INTERCAT, Inc. Mr. John J. Lipinski, the chief executive officer and president of our company and a member of our board of directors, is a director and member of the compensation committee of INTERCAT, Inc.
Related Party Transaction Policy
Our board of directors has adopted a Related Party Transaction Policy, which is designed to monitor and ensure the proper review, approval, ratification and disclosure of related party transactions involving us. This policy applies to any transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) in which we were, are or will be a participant and the amount involved exceeds $100,000, and in which any related party had, has or will have a direct or indirect material interest. The audit committee of our board of directors must review, approve and ratify a related party transaction if such transaction is consistent with the Related Party Transaction Policy and is on terms, taken as a whole, which the audit committee believes are no less favorable to us than could be obtained in an arms-length transaction with an unrelated third party, unless the audit committee otherwise determines that the transaction is not in our best interests. Any related party transaction or modification of such transaction which our board of directors has approved or ratified by the affirmative vote of a majority of directors, who do not have a direct or indirect material interest in such transaction, does not need to be approved or ratified by our audit committee. In addition, related party transactions involving compensation will be approved by our compensation committee in lieu of our audit committee.
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Conflicts of Interests Policy for Transactions between the Partnership and Us
Our board of directors has also adopted a Conflicts of Interests Policy, which is designed to monitor and ensure the proper review, approval, ratification and disclosure of transactions between the Partnership and us. The policy applies to any transaction, arrangement or relationship (or any series of similar transactions, arrangements or relationships) between us or any of our subsidiaries, on the one hand, and the Partnership, its managing general partner and any subsidiary of the Partnership, on the other hand. According to the policy, all such transactions must be fair and reasonable to us. If such transaction is expected to involve a value, over the life of such transaction, of less than $1 million, no special procedures will be required. If such transaction is expected to involve a value of more than $1 million but less than $5 million, it is deemed to be fair and reasonable to us if (i) such transaction is approved by the conflicts committee of our board of directors, (ii) the terms of such transaction are no less favorable to us than those generally being provided to or available from unrelated third parties or (iii) such transaction, taking into account the totality of any other such transaction being entered into at that time between the parties involved (including other transaction that may be particularly favorable or advantageous to us), is equitable to CVR Energy. If such transaction is expected to involve a value, over the life of such transaction, of $5 million or more, it is deemed to be fair and reasonable to us if it has been approved by the conflicts committee of our board of directors.
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THE NITROGEN FERTILIZER LIMITED PARTNERSHIP
Background
In June 2007, we created a new limited partnership, CVR Partners, LP, or the Partnership. In October 2007, prior to our initial public offering, we transferred our nitrogen fertilizer business to this Partnership. The Partnership initially had three partners: a managing general partner, CVR GP, LLC, which we owned; a special general partner, CVR Special GP, LLC, which we owned; and a limited partner, Coffeyville Resources, LLC. We sold the managing general partner for $10.6 million to Coffeyville Acquisition III LLC, a newly created entity owned by the Goldman Sachs Funds, the Kelso Funds, our executive officers, Mr. Wesley Clark, Magnetite Asset Investors III L.L.C. and other members of our senior management team.
In connection with the creation of the Partnership, CVR GP, LLC, as the managing general partner, Coffeyville Resources, LLC, as the limited partner, and CVR Special GP, LLC, as a general partner, entered into a limited partnership agreement which set forth the various rights and responsibilities of the partners in the Partnership. In addition, we entered into a number of intercompany agreements with the Partnership and the managing general partner which regulate certain business relations among us, the Partnership and the managing general partner.
Contribution, Conveyance and Assumption Agreement
In October 2007, the Partnership entered into a contribution, conveyance and assumption agreement, or the contribution agreement, with the Partnership’s managing general partner, CVR Special GP, LLC (our subsidiary that holds a general partner interest in the Partnership), and Coffeyville Resources, LLC (our subsidiary that holds a limited partner interest in the Partnership). Pursuant to the contribution agreement, Coffeyville Resources, LLC transferred our subsidiary that owns the nitrogen fertilizer business to the Partnership in exchange for (1) the issuance to CVR Special GP, LLC of 30,303,000 special GP units, representing a 99.9% general partner interest in the Partnership, (2) the issuance to Coffeyville Resources, LLC of 30,333 special LP units, representing a 0.1% limited partner interest in the Partnership, (3) the issuance to the managing general partner of the managing general partner interest in the Partnership and (4) the agreement by the Partnership, contingent upon the Partnership consummating an initial public or private offering, to reimburse us for capital expenditures we incurred during the two year period prior to the sale of the managing general partner to Coffeyville Acquisition III LLC, in connection with the operations of the fertilizer plant (currently estimated to be $18.4 million). The Partnership assumed all liabilities arising out of or related to the ownership of the nitrogen fertilizer business to the extent arising or accruing on and after the date of transfer.
Sale of Managing General Partner to Coffeyville Acquisition III LLC
Following formation of the Partnership pursuant to the contribution agreement in October 2007, the following entities and individuals contributed the following amounts in cash to Coffeyville Acquisition III LLC, a newly formed entity owned by our controlling stockholders and executive officers.
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Coffeyville Acquisition III LLC used these contributions to purchase the managing general partner of the Partnership from us:
| | | | | |
Contributing Parties | | Amount Contributed |
| |
| The Goldman Sachs Funds | | $ | 5,227,584 | |
| The Kelso Funds | | | 5,145,787 | |
| John J. Lipinski | | | 68,146 | |
| Stanley A. Riemann | | | 16,359 | |
| James T. Rens | | | 10,225 | |
| Edmund S. Gross | | | 1,227 | |
| Robert W. Haugen | | | 4,090 | |
| Wyatt E. Jernigan | | | 4,090 | |
| Kevan A. Vick | | | 10,225 | |
| Christopher G. Swanberg | | | 1,022 | |
| Daniel J. Daly, Jr. | | | 2,045 | |
| Wesley Clark | | | 10,225 | |
| Others | | | 98,975 | |
Total Contribution | | $ | 10,600,000 | |
Coffeyville Acquisition III purchased the managing general partner from us for $10.6 million, which our board of directors determined, after consultation with management, represented the fair market value of the managing general partner of the Partnership at that time. The valuation of the managing general partner interest was based on a discounted cash flow analysis, using a discount rate commensurate with the risk profile of the managing general partner interest. The key assumptions underlying the analysis were commodity price projections, which were used to estimate the Partnership’s raw material costs and output revenues. Other business expenses of the Partnership were estimated based on management’s projections. The Partnership’s cash distributions were assumed to be flat at expected forward fertilizer prices, with cash reserves developed in periods of high prices and cash reserves reduced in periods of lower prices. The Partnership’s projected cash distributions to the managing general partner under the terms of the Partnership’s partnership agreement used for the valuation were modeled based on the structure of the Partnership, the managing general partner’s incentive distribution rights (“IDRs”) and management’s expectations of the Partnership’s operations, including production volumes and operating costs, which were developed by management based on historical experience. As commodity price curve projections were key assumptions in the discounted cash flow analysis, alternative price curve projections were considered in order to test the reasonableness of these assumptions, which gave management an added level of assurance as to such reasonableness. Price projections were based on information received from Blue Johnson and Associates, a fertilizer industry consultant in the United States which we routinely use for fertilizer market analysis. There can be no assurance that the value of the managing general partner will not differ in the future from the amount initially paid for it.
February 2008 Filing ofForm S-1 by CVR Partners, LP
On February 28, 2008, the Partnership filed aForm S-1 registration statement (the “PartnershipS-1”) with the SEC for an initial public offering (the “Partnership Offering”) of common units representing limited partner interests in the Partnership. On June 13, 2008, the Company announced that the managing general partner of the Partnership had decided that it would postpone indefinitely the Partnership’s initial public offering. The Partnership may elect to move forward with a public or private offering in the future.
Description of Partnership Interests Initially Following Formation
The partnership agreement provides that initially the Partnership has three types of partnership interests: (1) special GP units, representing special general partner interests, which are owned by the special general partner, (2) special LP units, representing a limited partner interest, which are owned
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by Coffeyville Resources, LLC, and (3) a managing general partner interest which has associated IDRs which are held by the managing general partner.
Special Units. The special units include special GP units and special LP units. We indirectly own all 30,303,000 special GP units and all 30,333 special LP units. The special GP units are special general partner interests giving the holder thereof specified joint management rights (which we refer to as special GP rights), including rights with respect to the appointment, termination and compensation of the chief executive officer and the chief financial officer of the managing general partner, and entitling the holder to participate in Partnership distributions and allocations of income and loss. Special LP units have identical voting and distribution rights as the special GP units, but represent limited partner interests in the Partnership and do not give the holder thereof the special GP rights.
In accordance with the partnership agreement, the special units are entitled to payment of a set target distribution of $0.4313 per unit ($13.1 million in the aggregate for all our special units each quarter), or $1.7252 per unit on an annualized basis ($52.3 million in the aggregate for all our special units annually), prior to the payment of any quarterly distribution in respect of the IDRs. For more information on cash distributions to the special units and the IDRs please see “— Cash Distributions by the Partnership”. We are permitted to sell the special units at any time without the consent of the managing general partner, subject to compliance with applicable securities laws, but upon any sale of special GP units to an unrelated third party the special GP rights will no longer apply to such units.
Managing General Partner Interest. The managing general partner interest, which is held solely by the managing general partner, entitles the holder to manage (subject to our special GP rights) the business and operations of the Partnership, but does not entitle the holder to participate in Partnership distributions or allocations except in respect of associated IDRs. IDRs represent the right to receive an increasing percentage of quarterly distributions of available cash from operating surplus after the target distribution ($0.4313 per unit per quarter) has been paid and following distribution of the aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 to the special unitsand/or the common and subordinated units (if issued). In addition, there can be no distributions paid on the managing general partner’s IDRs for so long as the Partnership or its subsidiaries are guarantors under our Credit Facility. The IDRs are not transferable apart from the general partner interest. The managing general partner can be sold without the consent of other partners in the Partnership.
Provisions Regarding an Initial Offering by the Partnership
Under the partnership agreement, the managing general partner has the sole discretion to cause the Partnership to undertake an initial private or public offering, subject to our joint management rights (as holder of the special GP rights, described below) if the offering involves the issuance of more than $200 million of the Partnership’s interests (exclusive of the underwriters’ option, if any). There is no assurance that the Partnership will undertake or consummate a public or private offering.
Under the contribution agreement, if Fertilizer GP elects to cause the Partnership to undertake an initial private or public offering (in either case, the Partnership’s “initial offering”), Fertilizer GP must give prompt notice to us of such election and the proposed terms of the offering. We have agreed to use our commercially reasonable efforts to take such actions as Fertilizer GP reasonably requests in order to effectuate and permit the consummation of the offering. We have agreed that Fertilizer GP may structure the initial offering to include (1) a secondary offering of interests by us or (2) a primary offering of interests by the Partnership, possibly together with an incurrence of indebtedness by the Partnership, where a use of proceeds is to redeem units from us (with aper-unit redemption price equal to the price at which each unit is purchased from the Partnership, net of sales commissions or underwriting discounts) (a “special GP offering”), provided that in either case the number of units associated with the special GP offering is reasonably expected by Fertilizer GP to generate no more than $100 million in net proceeds to us (exclusive of the underwriters’ option, if any). The special GP offering may not be consummated without our consent if the net proceeds to us are less than $10 per unit. If the initial public offering includes a special GP offering, unless we otherwise agree with the
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Partnership, the special GP offering will be increased to cover our pro rata portion of any exercise of the underwriters’ option, if any.
Under the contribution agreement, if Fertilizer GP reasonably determines that, in order to consummate the initial offering, it is necessary or appropriate for the Partnership and its subsidiaries to be released from their obligations under our Credit Facility and our swap arrangements with J. Aron, then Fertilizer GP must give prompt written notice to us describing the requested amendments. The notice must be given 90 days prior to the anticipated closing date of the initial offering. We will be required to use our commercially reasonable efforts to effect the releases or amendments. We will not be considered to have made “commercially reasonable efforts” if we do not effect such requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions; provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested modifications, we may require that (1) the initial offering include a special GP offering generating at least $140 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering.
If the Partnership consummates an initial public or private offering and we sell units, or our units are redeemed, in a special GP offering, or the Partnership makes a distribution to us of proceeds of the offering or debt financing, such sale, redemption or distribution would likely result in taxable gain to us and such taxable gain could be significant. If the Partnership consummates an initial public or private offering, regardless of whether we sell units, the distributions that we receive from the Partnership could decrease because the Partnership’s distributions will be shared with the new limited partners. Additionally, when the Partnership issues units or engages in certain other transactions, the Partnership will determine the fair market value of its assets and allocate any unrealized gain or loss attributable to those assets to the capital accounts of the existing partners. As a result of this revaluation and the Partnership’s adoption of the remedial allocation method under Section 704(c) of the Internal Revenue Code (i) new unitholders will be allocated deductions as if the tax basis of the Partnership’s property were equal to the fair market value thereof at the time of the offering, and (ii) we will be allocated “reverse Section 704(c) allocations” of income or loss over time consistent with our allocation of unrealized gain or loss.
If the Partnership consummates an initial offering as either a primary or secondary offering, our special units, other than those sold or redeemed in a special GP offering, if any, will be converted into a combination of (1) common units and (2) subordinated units. The special units will be converted into common units and subordinated units, on a one-for-one basis, such that the lesser of (1) 40% of all outstanding units after the initial offering (prior to the exercise of the underwriters’ option, if any) and (2) all of the units owned by us, will be subordinated. For a description of the common units and subordinated units please see “— Description of Partnership Interests Following Initial Offering”. The special GP units will convert into common GP units or subordinated GP units and the special LP units will convert into common LP units or subordinated LP units.
The following table sets forth the number of special GP units and special LP units that are currently outstanding and illustrates the number of common GP units, subordinated GP units, common LP units and subordinated LP units we will own, as well as the number of common LP units that public unitholders will own, assuming the Partnership’s initial offering involves a total of 10 million common LP units, 7 million of which are our special units (converted into common LP units immediately prior to sale directly in the initial offering, or redeemed using the proceeds from the issuance of common LP units by the Partnership) and 3 million of which are new common LP units. The following table assumes that the 7 million of our special units sold or redeemed reduce our special LP units and special GP units pro rata (i.e., 99.9% from our special GP units and 0.1% from our special LP units).
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This information is presented for illustrative purposes only. There can be no assurance the Partnership will undertake an initial offering consistent with these assumptions or at all.
| | | | | | | |
| | | Initial
| | Following Partnership Initial Offering |
| | | Special Units | | Common Units | | Subordinated Units |
| |
| Owned by us | | 30,303,000 | | 9,990,000 | | 13,320,000 |
| | | special GP | | common GP | | subordinated GP |
| | | units | | units | | units |
| | | 30,333 | | 10,000 | | 13,333 |
| | | special LP | | common LP | | subordinated LP |
| | | units | | units | | units |
| Owned by public | | — | | 10,000,000 | | — |
| | | | | common LP
units | | |
The partnership agreement prohibits Fertilizer GP from causing the Partnership to undertake or consummate an initial offering unless the board of directors of Fertilizer GP determines, after consultation with us, that the Partnership will likely be able to earn and pay the minimum quarterly distribution (which is currently set at $0.375 per unit) on all units for each of the two consecutive, nonoverlapping four-quarter periods following the initial offering. As an illustration, the Partnership would need to earn and pay $50 million during each of the two consecutive, nonoverlapping four-quarter periods based upon the number of units (i.e., 33,333,333 total units) in the hypothetical illustrated in the table above. If Fertilizer GP determines that the Partnership is not likely to be able to earn and pay the minimum quarterly distribution for such periods, Fertilizer GP may, in its sole discretion and effective upon closing of the initial offering, reduce the minimum quarterly distribution to an amount it determines to be appropriate and likely to be earned and paid during such periods.
The contribution agreement also provides that if the initial offering is not consummated by October 24, 2009, Fertilizer GP can require us to purchase the managing general partner interest. This put right expires on the earlier of (1) October 24, 2012 and (2) the closing of the Partnership’s initial offering. If the Partnership’s initial offering is not consummated by October 24, 2012, we have the right to require Fertilizer GP to sell the managing general partner interest to us. This call right expires on the closing of the Partnership’s initial offering. In the event of an exercise of a put right or a call right, the purchase price will be the fair market value of the managing general partner interest at the time of purchase. The fair market value will be determined by an independent investment banking firm selected by us and Fertilizer GP. The independent investment banking firm may consider the value of the Partnership’s assets, the rights and obligations of Fertilizer GP and other factors it may deem relevant but the fair market value shall not include any control premium. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — If the Partnership does not consummate an initial offering by October 24, 2009, Fertilizer GP can require us to purchase its managing general partner interest in the Partnership. We may not have requisite funds to do so”.
Description of Partnership Interests Following Initial Offering
Common Units. The common units, if issued, will be comprised of common GP units and common LP units. The common GP units will be special general partner interests giving the holder special GP rights (described above), including rights with respect to the appointment, termination and compensation of the chief executive officer and the chief financial officer of the managing general partner, and entitling the holder to participate in Partnership distributions and allocations on a pro rata basis with common LP units. Common LP units will have identical voting and distribution rights as the common GP units, but will represent limited partner interests in the Partnership and will not give the holder thereof special GP rights. The common units will be entitled to payment of the minimum quarterly distribution prior to the payment of any quarterly distribution on the subordinated units or the IDRs. For more information of the rights and preferences of holders of the common units,
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subordinated units and IDRs in the Partnership’s distributions, please see “— Cash Distributions by the Partnership.”
We will be permitted to sell the common units we own at any time without the consent of the managing general partner, subject to compliance with applicable securities laws. The common GP units will automatically convert to common LP units immediately prior to sale thereof to an unrelated third party. The common GP units will automatically convert into common LP units (with no special GP rights) immediately if the holder of the common GP units, together with all of its affiliates, ceases to own 15% or more of all units of the Partnership (not including the managing general partner interest).
Subordinated Units. The subordinated units, if issued, will be comprised of subordinated GP units and subordinated LP units. The subordinated GP units will be special general partner interests giving the holder special GP rights. Subordinated LP units will have identical voting and distribution rights as the subordinated GP units, but will represent limited partner interests in the Partnership and will not give the holder thereof special GP rights. The subordinated units will entitle the holder to participate in Partnership distributions and allocations on a subordinated basis to the common units (as described in “— Cash Distributions by the Partnership”). During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the set minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. As a result, if the Partnership consummates an initial offering, the portion of our special units that are converted into subordinated units will be subordinated to the common units and may not receive distributions unless and until the common units have received the minimum quarterly distribution, plus any accrued and unpaid arrearages in the minimum quarterly distribution from prior quarters. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest In the Nitrogen Fertilizer Business — Our rights to receive distributions from the Partnership may be limited over time” and “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest In the Nitrogen Fertilizer Business — If the Partnership completes a public offering or private placement of limited partner interests, our voting power in the Partnership would be reduced and our rights to distributions from the Partnership could be materially adversely affected.”
We will be permitted to sell the subordinated units we own at any time without the consent of the managing general partner, subject to compliance with applicable securities laws. The subordinated units will automatically convert into common units on the second day after the distribution of cash in respect of the last quarter in the subordination period (which will end no earlier than five years after the initial offering), although up to 50% may convert earlier. The subordinated GP units will automatically convert to subordinated LP units immediately prior to sale thereof to an unrelated third party. The subordinated GP units will automatically convert into subordinated LP units immediately if the holder of the subordinated GP units, together with all of its affiliates, ceases to own 15% or more of all units of the Partnership.
Managing General Partner Interest. The managing general partner interest will continue to be outstanding following the initial offering.
Management of the Partnership
The managing general partner manages the Partnership’s operations and activities, subject to our joint management rights, as specified in the partnership agreement. Among other things, the managing general partner has sole authority to effect an initial public or private offering of the Partnership, including the right to determine the timing, size (subject to our consent rights for any initial offering in excess of $200 million, exclusive of the underwriters’ option, if any) and underwriters or initial purchasers, if any, for any initial offering. The Partnership’s managing general partner is wholly-owned by an entity controlled by the Goldman Sachs Funds, the Kelso Funds and certain members of our senior management team. The operations of the managing general partner, in its capacity as the managing general partner of the Partnership, are managed by its board of directors. As of the date of this prospectus, the board of directors of the managing general partner consisted of Donna R. Ecton, John J. Lipinski, Scott L. Lebovitz, George E. Matelich, Frank M. Muller, Jr., Stanley
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de J. Osborne and Kenneth A. Pontarelli. Actions by the managing general partner that are made in its individual capacity will be made by the sole member of the managing general partner and not by its board of directors. The managing general partner is not elected by the unitholders or us and is not subject to re-election on a regular basis in the future. The officers of the managing general partner manage the day-to-day affairs of the Partnership’s business.
The special general partner, which we own, has special management rights. The special management rights will terminate if we cease to own 15% of more of all units of the Partnership. Our management rights include:
| | |
| • | appointment rights and consent rights for the termination of employment and compensation of the chief executive officer and chief financial officer of the managing general partner, not to be exercised unreasonably (our approval for appointment of an officer is deemed given if the officer is an executive officer of CVR Energy); |
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| • | the right to appoint two directors to the board of directors of the managing general partner and one such director to any committee thereof (subject to certain exceptions); |
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| • | consent rights over any merger by the Partnership into another entity where: |
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| • | for so long as we own 50% or more of all units of the Partnership immediately prior to the merger, less than 60% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; |
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| • | for so long as we own 25% or more of all units of the Partnership immediately prior to the merger, less than 50% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; and |
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| • | for so long as we own more than 15% of all of the units of the Partnership immediately prior to the merger, less than 40% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; |
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| • | consent rights over any purchase or sale, exchange or other transfer of assets or entities with a purchase/sale price equal to 50% or more of the Partnership’s asset value; and |
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| • | consent rights over any incurrence of indebtedness or issuance of Partnership interests with rights to distribution or in liquidation ranking prior or senior to the common units, in either case in excess of $125 million ($200 million in the case of the Partnership’s initial public or private offering, exclusive of the underwriters’ option, if any), increased by 80% of the purchase price for assets or entities whose purchase was approved by us as described in the immediately preceding bullet point. |
As of the date of this prospectus, the board of directors of the managing general partner consists of seven directors, including two representatives of the Goldman Sachs Funds, two representatives of the Kelso Funds, Donna R. Ecton and Frank M. Muller, Jr., who are independent directors and John J. Lipinksi, chief executive officer and president of the managing general partner and CVR Energy. If the Partnership effects an initial public offering in the future, the board of directors of the managing general partner will be required, subject to phase-in requirements of any national securities exchange upon which the Partnership’s common units are listed for trading, to have at least three members who are not officers or employees, and are otherwise independent, of the entity which owns the managing general partner, and its affiliates, including CVR Energy and the Partnership’s general partners. In addition, if an initial public offering of the Partnership occurs, the board of directors of the managing general partner will be required to maintain an audit committee comprised of at least three independent directors.
The partnership agreement permits the board of directors of the managing general partner to establish a conflicts committee, comprised of at least one independent director, that may determine if the resolution of a conflict of interest with the Partnership’s general partners or their affiliates is fair and reasonable to the Partnership. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to the Partnership, approved by all of the Partnership’s
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partners and not a breach by the general partners of any duties they may owe the Partnership or the unitholders of the Partnership.
Cash Distributions by the Partnership
Available Cash. The partnership agreement requires the Partnership to make quarterly distributions of 100% of its “available cash.” Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter
| | |
| • | less the amount of cash reserves established by the managing general partner to: |
| | |
| • | provide for the proper conduct of the Partnership’s business (including the satisfaction of obligations in respect of pre-paid fertilizer contracts, future capital expenditures, anticipated future credit needs and the payment of expenses and fees, including payments to the managing general partner); |
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| • | comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Partnership or any of its subsidiaries is a party or by which the Partnership is bound or its assets are subject; and |
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| • | provide funds for distributions in respect of any one or more of the next eight quarters, provided, however, that following an initial public offering of the Partnership, the managing general partner may not establish cash reserves pursuant to this clause if the effect of such reserves would be that the Partnership would be unable to distribute the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon with respect to any such quarter; |
| | |
| • | plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are used solely for working capital purposes or to make distributions to partners. |
Cash distributions will be made within 45 days after the end of each quarter. The amount of distributions paid by the Partnership and the decision to make any distribution will be determined by the managing general partner, taking into consideration the terms of the partnership agreement.
Prior to the earlier to occur of (i) such time as the limitations described below in “— Non-IDR surplus amount” no longer apply, after which time available cash from operating surplus could be distributed in respect of the IDRs, assuming each unit has received at least the first target distribution, as described below, and (ii) an initial offering by the Partnership, after which there will be limited partners to whom available cash could be distributed, all available cash is distributed to us, as holder of the special units. Because all available cash is currently distributed to us, the board of directors of Fertilizer GP has not adopted a formal distribution policy.
Operating Surplus and Capital Surplus. All cash distributed by the Partnership will be characterized either as operating surplus or capital surplus. The Partnership will distribute available cash from operating surplus differently than available cash from capital surplus.
Definition of Operating Surplus. Operating surplus for any period generally consists of:
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| • | $60 million (as described below); plus |
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| • | all of the Partnership’s cash receipts after formation (reset to the date of the Partnership’s initial offering if an initial offering occurs), excluding cash from “interim capital transactions” (as described below); plus |
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| • | working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus |
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| • | cash distributions paid on equity interests issued by the Partnership to finance all or any portion of the construction, expansion or improvement of the Partnership’s facilities during the period from such financing until the earlier to occur of the date the capital asset is put into service or the date it is abandoned or disposed of; plus |
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| • | cash distributions paid on equity interests issued by the Partnership to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the construction, expansion and improvement projects referred to above; less |
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| • | all of the Partnership’s “operating expenditures” (as defined below) after formation (reset to the date of closing of the Partnership’s initial offering if an initial offering occurs); less |
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| • | the amount of cash reserves established by the managing general partner to provide funds for future operating expenditures (which does not include expansion capital expenditures). |
If a working capital borrowing, which increases operating surplus, is not repaid during the twelve-month period following the borrowing, it will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowing is in fact repaid, it will not be treated as a reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.
As described above, operating surplus does not reflect actual cash on hand that is available for distribution to unitholders. For example, it includes a provision that will enable the Partnership, if it chooses, to distribute as operating surplus up to $60 million of cash from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus would be to increase operating surplus by the amount of any such cash distributions.
“Operating expenditures” generally means all of the Partnership’s expenditures, including its expenses, taxes, reimbursements or payments of expenses to its managing general partner, repayment of working capital borrowings, debt service payments and capital expenditures, provided that operating expenditures will not include:
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| • | repayments of working capital borrowings, if such working capital borrowings were outstanding for twelve months, not repaid, but deemed repaid, thus decreasing operating surplus at such time; |
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| • | payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings; |
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| • | expansion capital expenditures; |
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| • | investment capital expenditures; |
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| • | payment of transaction expenses relating to “interim capital transactions”; or |
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| • | distributions to partners. |
Where capital expenditures are made in part for expansion and in part for other purposes, the managing general partner shall determine the allocation between the amounts paid for each.
“Interim capital transactions” means the following transactions if they occur prior to liquidation of the Partnership: (a) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and other than for items purchased on open account or for a deferred purchase price in the ordinary course of business); (b) sales of equity interests and debt securities; and (c) sales or other voluntary or involuntary dispositions of any assets other than (i) sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business, and (ii) sales or other dispositions of assets as part of normal retirements or replacements of assets.
Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures and investment capital expenditures do not. Maintenance capital expenditures represent capital expenditures to replace partially or fully depreciated assets to maintain the Partnership’s operating capacity (or productivity) or capital base. Maintenance capital expenditures include expenditures required to maintain equipment reliability, plant integrity and safety and to address environmental laws and regulations. Maintenance capital expenditures also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction,
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improvement or development of a replacement asset that is paid during the period that begins when the Partnership enters into a binding commitment or commences constructing or developing a replacement asset and ending on the earlier to occur of the date any such replacement asset commences commercial service or the date it is abandoned or disposed of.
Expansion capital expenditures include expenditures to acquire or construct assets to grow the Partnership’s business and to expand fertilizer production capacity. Expansion capital expenditures also include interest (and related fees) on debt incurred and distributions on equity issued to finance all or any portion of the construction of such a capital improvement during the period that commences when the Partnership enters into a binding obligation to commence construction of a capital improvement and ending on the date such capital improvement commences commercial service or the date that it is abandoned or disposed of.
Investment capital expenditures are those capital expenditures that are neither maintenance capital expenditures nor expansion capital expenditures. Investment capital expenditures largely consist of capital expenditures made for investment purposes. Examples of investment capital expenditures include traditional capital expenditures for investment purposes, such as purchases of securities, as well as other capital expenditures that might be made in lieu of such traditional investment capital expenditures, such as the acquisition of a capital asset for investment purposes or development of facilities that are in excess of the maintenance of the Partnership’s existing operating capacity or productivity, but which are not expected to expand for the long-term the Partnership’s operating capacity or asset base.
As described above, none of the Partnership’s investment capital expenditures or expansion capital expenditures are subtracted from operating surplus. Because investment capital expenditures and expansion capital expenditures include interest payments (and related fees) on debt incurred and distributions on equity issued to finance all of the portion of the construction, replacement or improvement of a capital asset during the period that begins when the Partnership enters into a binding obligation to commence construction of a capital improvement and ending on the earlier to occur of the date any such capital asset commences commercial service or the date that it is abandoned or disposed of, such interest payments and equity distributions are also not subtracted from operating surplus.
The officers and directors of the managing general partner determine how to allocate a capital expenditure for the acquisition or expansion of the Partnership’s assets between maintenance capital expenditures and expansion capital expenditures.
Definition of Capital Surplus. “Capital surplus” is generally generated only by:
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| • | borrowings other than working capital borrowings; |
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| • | sales of debt securities and equity interests; and |
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| • | sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of the normal retirement or replacement of assets. |
Distributions from Operating Surplus.
The Partnership’s distribution structure with respect to operating surplus will change based upon the occurrence of three events: (1) distribution by the Partnership of the non-IDR surplus amount (as defined below), together with a release of the guarantees by the Partnership and its subsidiaries of our Credit Facility, (2) occurrence of an initial offering by the Partnership (following which all or a portion of our interest will be converted into subordinated units and the minimum quarterly distribution could be reduced) and (3) expiration (or early termination) of the subordination period.
Minimum Quarterly Distributions. The minimum quarterly distribution, or MQD, represents the set quarterly distribution amount that the common units, if issued, will be entitled to prior to the payment of any quarterly distribution on the subordinated units. The amount of the MQD is set in Partnership’s partnership agreement at $0.375 per unit, or $1.50 per unit on an annualized basis. The
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partnership agreement prohibits the managing general partner from causing the Partnership to undertake or consummate an initial offering unless the board of directors of the managing general partner, after consultation with us, concludes that the Partnership will be likely to be able to earn and pay the MQD on all units for each of the two consecutive, nonoverlapping four-quarter periods following the initial offering. If the managing general partner determines that the Partnership is not likely to be able to earn and pay the MQD for such periods, the managing general partner may, in its sole discretion and effective upon closing of the initial offering, reduce the MQD to an amount it determines to be appropriate and likely to be earned and paid during such periods. If the Partnership were to distribute $0.375 per unit on the number of units we own, we would receive a quarterly distribution of $11.4 million in the aggregate. The MQD for any period of less than a full calendar quarter (e.g., the periods before and after the closing of an initial offering by the Partnership) will be adjusted based on the actual length of the periods. To the extent we receive such amounts from the Partnership in the form of quarterly distributions, we will generally not be able to distribute such amounts to our stockholders due to restrictions contained in our Credit Facility. See “Dividend Policy.”
Target Distributions. The Partnership’s partnership agreement provides for “target distribution levels.” After the limitations described below in “— Non-IDR surplus amount” no longer apply, the managing general partner’s IDRs will entitle it to receive increasing percentages of any incremental quarterly cash distributed by the Partnership as the target distribution levels for each quarter are exceeded. There are three target distribution levels set in the partnership agreement: $0.4313, $0.4688 and $0.5625, representing 115%, 125% and 150%, respectively, of the initial MQD amount. The target distribution levels for any period of less than a full calendar quarter (e.g., the periods before and after the closing of an initial offering by the Partnership) will be adjusted based on the actual length of the periods. The target distribution levels will not be adjusted in connection with any reduction of the MQD in connection with the Partnership’s initial offering unless we otherwise agree with the managing general partner.
The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and the Partnership’s managing general partner up to and above the various target distribution levels. The amounts set forth under “marginal percentage interest in distributions” are the percentage interests of the Partnership’s managing general partner and the unitholders in any available cash from operating surplus the Partnership distributes up to and including the corresponding amount in the column “Total Quarterly Distribution — Target Amount,” until the available cash from operating surplus the Partnership distributes reaches the next target distribution level, if any. The percentage interests shown for the unitholders and managing general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for the managing general partner represent distributions in respect of the IDRs.
Marginal Percentage Interest in Distributions
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| | | Total Quarterly
| | | | |
| | | Distribution — Target
| | | | Managing General
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| | | Amount | | Special Units | | Partner |
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| Minimum Quarterly Distribution | | $0.375 | | | 100 | % | | | 0 | % |
| First Target Distribution | | Up to $0.4313 | | | 100 | % | | | 0 | % |
| Second Target Distribution | | Above $0.4313 | | | 87 | % | | | 13 | % |
| | | and up to $0.4688 | | | | | | | | |
| Third Target Distribution | | Above $0.4688 | | | 77 | % | | | 23 | % |
| | | and up to $0.5625 | | | | | | | | |
| Thereafter | | Above $0.5625 | | | 52 | % | | | 48 | % |
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If legislation is enacted or if existing law is modified or interpreted by a court of competent jurisdiction so that the Partnership or any of its subsidiaries becomes taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, the managing general partner may, in its sole discretion, reduce the minimum quarterly distribution and the target distribution levels for each quarter by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (after deducting the managing general partner’s estimate of the Partnership’s aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter plus the managing general partner’s estimate of the Partnership’s aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference will be accounted for in subsequent quarters.
Non-IDR Surplus Amount. There will be no distributions paid on the IDRs until the aggregate “adjusted operating surplus” (as described below) generated by the Partnership during the period from October 24, 2007 through December 31, 2009, or the non-IDR surplus amount, has been distributed in respect of the special units, or, following an initial public offering of the Partnership, the common and subordinated units (if any are issued). In addition, there will be no distributions paid on the IDRs for so long as the Partnership or its subsidiaries are guarantors under our Credit Facility.
Definition of Adjusted Operating Surplus. Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes the $60 million “basket” included as a component of operating surplus, net increases in working capital borrowings and net drawdowns of reserves of cash generated in prior periods. Adjusted operating surplus for any period generally means:
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| • | operating surplus generated with respect to that period (which does not include the $60 million basket described in the first bullet point of the definition of operating surplus above); less |
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| • | any net increase in working capital borrowings with respect to that period; less |
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| • | any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus |
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| • | any net decrease in working capital borrowings with respect to that period; plus |
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| • | any net increase in cash reserves for operating expenditures with respect to that period to the extent required by any debt instrument for the repayment of principal, interest or premium. |
If the Partnership consummates an initial offering, cash received by the Partnership or its subsidiaries in respect of accounts receivable existing as of the closing of such an offering will be deemed to not be operating surplus and thus will be disregarded when calculating adjusted operating surplus.
Distributions Prior to the Partnership’s Initial Offering (if any). Prior to the Partnership’s initial offering (if any), quarterly distributions of available cash from operating surplus (as described below) will be paid solely in respect of the special units until the non-IDR surplus amount has been distributed. After the limitations described in “— Non-IDR surplus amount” no longer apply and prior to the Partnership’s initial offering (if any), quarterly distributions of available cash from operating surplus will be paid in the following manner: (1) First, to the special units, until each special unit has received a total quarterly distribution equal to $0.4313 (the first target distribution), (2) Second,(i) 13% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to the special units until each special unit has received a total quarterly amount equal to $0.4688 (the second target distribution), (3) Third, (i) 23% to the managing general partner interest (in respect of the IDRs) and (ii) 77% to the special units, until each special unit has received a total quarterly amount equal to $0.5625 (the third target distribution), and (4) Thereafter, (i) 48% to the managing general partner interest (in respect of the IDRs) and (ii) 52% to the special units.
Distributions from Capital Surplus. Capital surplus is generally generated only by borrowings other than working capital borrowings, sales of debt securities and equity interests, and sales or other
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dispositions of assets for cash, other than inventory, accounts receivable and the other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.
The Partnership will make distributions of available cash from capital surplus, if any, in the following manner: (1) First, to all unitholders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below, (2) Second, to the common unitholders, if any, pro rata, until the Partnership distributes for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units, and (3) Thereafter, the Partnership will make all distributions of available cash from capital surplus as if they were from operating surplus. The preceding discussion is based on the assumptions that the Partnership does not issue additional classes of equity interests.
The partnership agreement will treat a distribution of capital surplus as the repayment of the consideration for the issuance of a unit by the Partnership, which is a return of capital. Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the distribution had in relation to the fair market value of the common units prior to the announcement of the distribution. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the managing general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the minimum quarterly distribution is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.
Once the Partnership reduces the minimum quarterly distribution and the target distribution levels to zero, the Partnership will then make all future distributions from operating surplus, with 52% being paid to the unitholders, pro rata, and 48% to the Partnership’s managing general partner.
Distributions of Cash Upon Liquidation. If the Partnership dissolves in accordance with the partnership agreement, the Partnership will sell or otherwise dispose of its assets in a process called liquidation. The Partnership will first apply the proceeds of liquidation to the payment of its creditors. The Partnership will distribute any remaining proceeds to the unitholders and the managing general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of the Partnership’s assets in liquidation.
The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of units to a repayment of the initial value contributed by the unitholder to the Partnership for its units, which we refer to as the “initial unit price” for each unit. With respect to our special units, the initial unit price will be the value of the nitrogen fertilizer business we contribute to the Partnership, divided by the number of special units we receive. The initial unit price for the common units issued by the Partnership in the initial offering, if any, will be the price paid for the common units. If there are common units and subordinated units outstanding, the allocation is intended, to the extent possible, to entitle the holders of common units to a preference over the holders of subordinated units upon the Partnership’s liquidation, to the extent required to permit common unitholders to receive their initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon the Partnership’s liquidation to enable the holders of units, including us, to fully recover all of the initial unit price. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the managing general partner.
The manner of the adjustment for gain is set forth in the partnership agreement. If the Partnership’s liquidation occurs after the Partnership’s initial offering, if any, and before the end of the subordination period, the Partnership will allocate any gain to the partners in the following manner: (1) First, to the managing general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances, (2) Second, to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of (i) the initial unit price, (ii) the amount of the minimum quarterly distribution for the quarter during
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which the liquidation occurs, and (iii) any unpaid arrearages in payment of the minimum quarterly distribution, (3) Third, to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of (i) the initial unit price and (ii) the amount of the minimum quarterly distribution for the quarter during which the liquidation occurs, (4) Fourth, to all unitholders, pro rata, until the Partnership allocates under this paragraph an amount per unit equal to (i) the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of the Partnership’s existence, less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that the Partnership distributed to the unitholders, pro rata, for each quarter of the Partnership’s existence, (5) Fifth, 87% to all unitholders, pro rata, and 13% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to (i) the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of the Partnership’s existence; less the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that the Partnership distributed 87% to the unitholders, pro rata, and 13% to the managing general partner for each quarter of the Partnership’s existence, (6) Sixth, 77% to all unitholders, pro rata, and 23% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to: (i) the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of the Partnership’s existence, less (ii) the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that the Partnership distributed 77% to the unitholders, pro rata, and 23% to the managing general partner for each quarter of the Partnership’s existence, and (7) Thereafter, 52% to all unitholders, pro rata, and 48% to the managing general partner. The percentages set forth above are based on the assumption that the Partnership has not issued additional classes of equity interests.
If the liquidation occurs before the Partnership’s initial offering, the special units will receive allocations of gain in the same manner as described above for the common units, except that the distinction between common units and subordinated units will not be relevant, so that subclause (iii) of clause (2) above and all of clause (3) above will not be applicable. If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that subclause (iii) of clause (2) above and all of the third bullet point above will no longer be applicable.
If the Partnership’s liquidation occurs after the Partnership’s initial offering, if any, and before the end of the subordination period, the Partnership will generally allocate any loss to the managing general partner and the unitholders in the following manner: (1) First, to holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the subordinated unitholders have been reduced to zero, (2) Second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unitholders have been reduced to zero, and (3) Thereafter,100% to the managing general partner.
If the liquidation occurs before the Partnership’s initial offering, the special units will receive allocations of loss in the same manner as described above for the common units, except that the distinction between common units and subordinated units will not be relevant, so that all of clause (1) above will not be applicable. If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of clause (1) will no longer be applicable.
Adjustments to Capital Accounts. The Partnership will make adjustments to capital accounts upon the issuance of additional units. In doing so, the Partnership will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the managing general partner in the same manner as the Partnership allocates gain or loss upon liquidation. In the event that the Partnership makes positive adjustments to the capital accounts upon the issuance of additional units, the Partnership will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon the Partnership’s liquidation in a manner which results, to the extent possible, in the managing general partner’s capital account
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balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.
Withdrawal or Removal of the Managing General Partner
Except as described below, the managing general partner has agreed not to withdraw voluntarily as the Partnership’s managing general partner prior to June 30, 2017 without obtaining the approval of the holders of at least a majority of the outstanding units, excluding units held by the managing general partner and its affiliates (including us), and furnishing an opinion of counsel regarding limited liability and tax matters. On or after June 30, 2017, the managing general partner may withdraw as managing general partner without first obtaining approval of any unitholder by giving 90 days written notice, and that withdrawal will not constitute a violation of the partnership agreement. Notwithstanding the information above, the managing general partner may withdraw without unitholder approval upon 90 days notice to the unitholders if at least 50% of the outstanding units are held or controlled by one person and its affiliates other than the managing general partner and its affiliates. In addition, the partnership agreement permits the managing general partner in some instances to sell or otherwise transfer all of its managing general partner interest without the approval of the unitholders. See “— Transfer of Managing General Partner Interest.”
Upon withdrawal of the managing general partner under any circumstances, other than as a result of a transfer by the managing general partner of all or a part of its general partner interest in the Partnership, the holders of a majority of the outstanding classes of units voting as a single class may select a successor to that withdrawing managing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, the Partnership will be dissolved, wound up and liquidated, unless within a specified period of time after that withdrawal, the holders of a unit majority agree in writing to continue the business of the Partnership and to appoint a successor managing general partner. See “— Termination and Dissolution.”
The managing general partner may not be removed unless that removal is approved by the vote of the holders of not less than 80% of the outstanding units, voting together as a single class, including units held by the managing general partner and its affiliates, and the Partnership receives an opinion of counsel regarding limited liability and tax matters. Prior to October 26, 2012, the managing general partner can only be removed for “cause.” Any removal of the managing general partner is also subject to the approval of a successor managing general partner by the vote of the unitholders holding a majority of each class of outstanding units, voting as separate classes.
The partnership agreement also provides that if the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by us, including our subsidiary that holds the subordinated units (if any) and our other affiliates, are voted in favor of that removal, the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis, and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished.
If the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by the managing general partner and its affiliates (which will include us until such time as we cease to be an affiliate of the managing general partner) are voted in favor of that removal, the managing general partner will have the right to convert its managing general partner interest, including the incentive distribution rights, into common units or to receive cash in exchange for those interests based on the fair market value of the interests at the time.
In the event of removal of the managing general partner under circumstances where cause exists or withdrawal of the managing general partner where that withdrawal violates the partnership agreement, a successor managing general partner will have the option to purchase the managing general partner interest, including the IDRs, of the departing managing general partner for a cash payment equal to the fair market value of the managing general partner interest. Under all other circumstances where the managing general partner withdraws or is removed, the departing managing
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general partner will have the option to require the successor managing general partner to purchase the managing general partner interest of the departing managing general partner for its fair market value. In each case, this fair market value will be determined by agreement between the departing managing general partner and the successor managing general partner. If no agreement is reached, an independent investment banking firm or other independent expert selected by the departing managing general partner and the successor managing general partner will determine the fair market value. If the departing managing general partner and the successor managing general partner cannot agree upon an expert, then an expert chosen by agreement of the experts selected by each of them will determine the fair market value.
If the option described above is not exercised by either the departing managing general partner or the successor managing general partner, the departing managing general partner’s general partner interest, including its IDRs, will automatically convert into common units equal to the fair market value of those interests as determined by an investment banking firm or other independent expert selected in the manner described in the preceding paragraph.
In addition, the Partnership will be required to reimburse the departing managing general partner for all amounts due to it, including, without limitation, all employee-related liabilities, including severance liabilities, incurred for the termination of any employees employed by the departing managing general partner or its affiliates for the Partnership’s benefit.
Voting Rights
The partnership agreement provides that various matters require the approval of a “unit majority.” A unit majority requires (1) prior to the initial offering, the approval of a majority of the special units; (2) during the subordination period, the approval of a majority of the common units, excluding those common units held by the managing general partner and its affiliates (which will include us until such time as we cease to be an affiliate of the managing general partner), and a majority of the subordinated units, voting as separate classes; and (3) after the subordination period, the approval of a majority of the common units. In voting their units, the Partnership’s general partners and their affiliates will have no fiduciary duty or obligation whatsoever to the Partnership or the other partners, including any duty to act in good faith or in the best interests of the Partnership and its other partners.
The following is a summary of the vote requirements specified for certain matters under the partnership agreement:
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| • | Issuance of Additional Units: no approval right. |
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| • | Amendment of the Partnership Agreement: certain amendments may be made by the managing general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. |
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| • | Merger of the Partnership or the Sale of all or Substantially all of the Partnership’s Assets: unit majority in certain circumstances. In addition, the holder of special GP rights has joint management rights with respect to some mergers. |
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| • | Dissolution of the Partnership: unit majority. |
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| • | Continuation of the Partnership upon Dissolution: unit majority. |
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| • | Withdrawal of the Managing General Partner: under most circumstances, a unit majority is required for the withdrawal of the managing general partner prior to June 30, 2017 in a manner which would cause a dissolution of the Partnership. |
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| • | Removal of the Managing General Partner: not less than 80% of the outstanding units, voting as a single class, including units held by the managing general partner and its affiliates (i) for cause prior to October 26, 2012 or (ii) with or without cause (as defined in the partnership agreement) on or after October 26, 2012. |
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| • | Transfer of the Managing General Partner’s General Partner Interest: the managing general partner may transfer all, but not less than all, of its managing general partner interest |
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| | |
| | in the Partnership without a vote of any unitholders and without our approval, to an affiliate or to another person (other than an individual) in connection with its merger or consolidation with or into, or sale of all or substantially all of its assets to, such person. The approval of a majority of the outstanding units, excluding units held by the managing general partner and its affiliates, voting as a class, and our approval, is required in other circumstances for a transfer of the managing general partner interest to a third party prior to October 26, 2017. |
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| • | Transfer of Ownership Interests in the Managing General Partner: no approval required at any time. |
Issuance of Additional Partnership Interests
The partnership agreement authorizes the Partnership to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by the managing general partner without the approval of the unitholders, subject to the special GP rights with respect to the issuance of equity with rights to distribution or in liquidation ranking prior to or senior to the common units.
Upon issuance of additional partnership interests, the Partnership’s managing general partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase common units, subordinated units or other partnership interests whenever, and on the same terms that, the Partnership issues those interests to persons other than the managing general partner and its affiliates, to the extent necessary to maintain its and its affiliates’ percentage interest, including such interest represented by common units and subordinated units, that existed immediately prior to each issuance. We will have similar rights to purchase common units, subordinated units or other partnership interests from the Partnership, except that our rights will not apply to any issuance of interests by the Partnership in its initial offering. For the purpose of these rights, we and the managing general partner shall be deemed not to be affiliates of one another, unless we otherwise agree. Other holders of units will not have preemptive rights to acquire additional common units or other partnership interests unless they are granted those rights in connection with the issuance of their units by the Partnership.
Amendment of the Partnership Agreement
General. Amendments to the partnership agreement may be proposed only by the managing general partner. However, the managing general partner has no duty or obligation to propose any amendment and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or any partner, including any duty to act in good faith or in the best interests of the Partnership or the limited partners. In order to adopt a proposed amendment, other than the amendments discussed below, the managing general partner is required to seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as described below, an amendment must be approved by a unit majority.
Prohibited Amendments. No amendment may be made that would: (1) enlarge the obligations of any limited partner or us, as a general partner, without its consent, unless approved by at least a majority of the type or class of partner interests so affected or (2) enlarge the obligations of, or restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable by the Partnership to any general partner or any of its affiliates without its consent, which may be given or withheld in its sole discretion. The provision of the partnership agreement preventing the amendments having the effects described in any of the clauses above can be amended upon the approval of the holders of at least 90% of the outstanding units, voting together as a single class (including units owned by the managing general partner and its affiliates). As of December 31, 2007, we own all of the outstanding units.
No Unitholder Approval. The managing general partner may generally make amendments to the partnership agreement without the approval of any unitholders to reflect (1) a change in the Partnership’s name, the location of its principal place of business, its registered agent or its registered
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office, (2) the admission, substitution, withdrawal or removal of partners in accordance with the partnership agreement, (3) a change that the managing general partner determines to be necessary or appropriate for the Partnership to qualify or to continue its qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that neither the Partnership nor any of its subsidiaries will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed), (4) an amendment that is necessary, in the opinion of the Partnership’s counsel, to prevent the Partnership or its general partners or their directors, officers, agents, or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed, (5) an amendment that the managing general partner determines to be necessary or appropriate for the authorization of additional partnership interests or rights to acquire partnership interests, as otherwise permitted by the partnership agreement, (6) any amendment expressly permitted in our partnership agreement to be made by the Partnership’s managing general partner acting alone, (7) an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement, (8) any amendment that the Partnership’s managing general partner determines to be necessary or appropriate for the formation by the Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by the partnership agreement, (9) a change in the Partnership’s fiscal year or taxable year and related changes, (10) mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance or (11) any other amendments substantially similar to any of the matters described above.
In addition, the managing general partner may make amendments to the partnership agreement without the approval of any partner if the managing general partner determines that those amendments (1) do not adversely affect in any material respect the partners (considered as a whole or any particular class of partners), (2) are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, (3) are necessary or appropriate to facilitate the trading of limited partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the limited partner interests are or will be listed for trading, (4) are necessary or appropriate for any action taken by the managing general partner relating to splits or combinations of units under the provisions of the partnership agreement or (5) are required to effect the intent of the provisions of the partnership agreement or are otherwise contemplated by the partnership agreement.
Opinion of Counsel and Unitholder Approval. For amendments of the type not requiring unitholder approval, the managing general partner will not be required to obtain an opinion of counsel that an amendment will not result in a loss of limited liability to the limited partners or result in the Partnership being treated as an entity for federal income tax purposes in connection with any of the amendments. No other amendments to the partnership agreement will become effective without the approval of holders of at least 90% of the outstanding units voting as a single class unless the managing general partner first obtains an opinion of counsel to the effect that the amendment will not affect the limited liability under Delaware law of any of the Partnership’s limited partners. Finally, the managing general partner may consummate any merger without the prior approval of the Partnership’s unitholders if the Partnership is the surviving entity in the transaction, the transaction would not result in any amendment to the partnership agreement (other than an amendment that the managing general partner could adopt without the consent of other partners), each of the units outstanding immediately prior to the merger will be an identical unit of the Partnership following the transaction, the units to be issued do not exceed 20% of the outstanding units immediately prior to the transaction and the managing general partner has received an opinion of counsel regarding certain limited liability and tax matters.
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In addition to the above restrictions, any amendment that would have a material adverse effect on the rights or preferences of any type or class of outstanding units in relation to other classes of units will require the approval of at least a majority of the type or class of units so affected. Any amendment that reduces the voting percentage required to take any action must be approved by the affirmative vote of partners whose aggregate outstanding units constitute not less than the voting requirement sought to be reduced.
Merger, Sale or Other Disposition of Assets
A merger or consolidation of the Partnership requires the prior consent of the managing general partner. However, the managing general partner will have no duty or obligation to consent to any merger or consolidation and may decline to do so free of any fiduciary duty or obligation whatsoever to the Partnership or other partners, including any duty to act in good faith or in the best interest of the Partnership or the other partners. We also have joint management rights with respect to certain mergers. Mergers and consolidations generally also require the affirmative vote or consent of the holders of a unit majority, unless the merger agreement contains any provision that, if contained in an amendment to the partnership agreement, would require for its approval the vote or consent of a greater percentage of the outstanding units or of any class of partners, in which case such greater percentage vote or consent shall be required.
In addition, the partnership agreement generally prohibits the managing general partner, without the prior approval of the holders of units representing a unit majority, from causing the Partnership to, among other things, sell, exchange or otherwise dispose of all or substantially all of the Partnership’s assets in a single transaction or a series of related transactions, including by way of merger, consolidation or other combination, or approving on the Partnership’s behalf the sale, exchange or other disposition of all or substantially all of the assets of the Partnership’s subsidiaries. The managing general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of the Partnership’s assets without that approval. The managing general partner may also sell all or substantially all of the Partnership’s assets under a foreclosure or other realization upon those encumbrances without that approval.
If the conditions specified in the partnership agreement are satisfied, the managing general partner may, without other partner approval, convert the Partnership or any of its subsidiaries into a new limited liability entity or merge the Partnership or any of its subsidiaries into, or convey some or all of its assets to, a newly formed entity if the sole purpose of that merger or conveyance is to effect a mere change in its legal form into another limited liability entity, the governing instruments of the new entity provide the limited partners and general partners with the same rights and obligations as contained in the partnership agreement and the Partnership receives an opinion of counsel regarding certain limited liability and tax matters. The unitholders are not entitled to dissenters’ rights of appraisal under the partnership agreement or applicable Delaware law in the event of a conversion, merger or consolidation, a sale of substantially all of the Partnership’s assets or any other transaction or event.
Termination and Dissolution
The Partnership will continue as a limited partnership until terminated under the partnership agreement. The Partnership will dissolve upon: (1) the election of the managing general partner to dissolve the Partnership, if approved by the holders of units representing a unit majority; (2) there being no limited partners, unless the Partnership continues without dissolution in accordance with applicable Delaware law; (3) the entry of a decree of judicial dissolution of the Partnership or (4) the withdrawal or removal of the managing general partner or any other event that results in its ceasing to be the Partnership’s managing general partner other than by reason of a transfer of its managing general partner interest in accordance with the partnership agreement or withdrawal or removal following approval and admission of a successor.
Upon a dissolution under clause (4) above, the holders of a unit majority may also elect, within specific time limitations, to continue the Partnership’s business on the same terms and conditions described in the partnership agreement by appointing as a successor managing general partner an
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entity approved by the holders of units representing a unit majority, subject to receipt of an opinion of counsel to the effect that (1) the action would not result in the loss of limited liability under Delaware law of any limited partner and (2) neither the Partnership nor any of its subsidiaries would be treated as an association taxable as a corporation or otherwise be taxable as an entity for federal income tax purposes upon the exercise of that right to continue (to the extent not already so treated or taxed).
Upon dissolution of the Partnership, unless the business of the Partnership is continued, the liquidator authorized to wind up the Partnership’s affairs will, acting with all of the powers of the managing general partner that are necessary or appropriate, liquidate the Partnership’s assets and apply the proceeds of the liquidation as described in the partnership agreement. The liquidator may defer liquidation or distribution of the Partnership’s assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to the partners.
Transfer of Managing General Partner Interest
Except for the transfer by the managing general partner of all, but not less than all, of its managing general partner interest in the Partnership to (1) an affiliate of the managing general partner (other than an individual) or (2) another entity as part of the merger or consolidation of the managing general partner with or into another entity or the transfer by the managing general partner of all or substantially all of its assets to another entity, the managing general partner may not transfer all or any part of its managing general partner interest in the Partnership to another person prior to October 26, 2017 without the approval of both (1) the holders of at least a majority of the outstanding units (excluding units held by the managing general partner and its affiliates) and (2) us. On or after October 26, 2017, the managing general partner interest will be freely transferable. As a condition of any transfer, the transferee must, among other things, assume the rights and duties of the managing general partner, agree to be bound by the provisions of the partnership agreement and furnish an opinion of counsel regarding limited liability and tax matters. The Partnership’s general partners and their affiliates may at any time transfer units to one or more persons, without unitholder approval, except that they may not transfer subordinated units to the Partnership.
Transfer of Ownership Interests in the Managing General Partner
At any time, the owners of the managing general partner may sell or transfer all or part of their ownership interests in the managing general partner to an affiliate or a third party without the approval of the Partnership’s unitholders.
Change of Management Provisions
The partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove the managing general partner as the managing general partner of the Partnership or otherwise change the Partnership’s management. If any person or group other than the managing general partner and its affiliates (including us) acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to any person or group that acquires the units from the managing general partner or its affiliates and any transferees of that person or group approved by the managing general partner or to any person or group who acquires the units with the prior approval of the board of directors of the managing general partner.
The partnership agreement also provides that if the Partnership’s managing general partner is removed without cause and no units held by us, our subsidiary that holds the subordinated units (if any) and our other affiliates are voted in favor of that removal, the subordination period will end and all outstanding subordinated units will immediately convert into common units on a one-for-one basis; and any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished.
If the managing general partner is removed as managing general partner under circumstances where cause does not exist and no units held by the managing general partner and its affiliates (which
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will include us until such time as we cease to be an affiliate of the managing general partner) are voted in favor of that removal, the managing general partner will have the right to convert its managing general partner interest, including its incentive distribution rights, into common units or to receive cash in exchange for the managing general partner interest.
Limited Call Right
If at any time the managing general partner and its affiliates own more than 80% of the then-issued and outstanding limited partner interests of any class, the managing general partner will have the right, which it may assign in whole or in part to any of its affiliates or to the Partnership, to acquire all, but not less than all, of the limited partner interests of the class held by unaffiliated persons, as of a record date to be selected by the managing general partner, on at least 10 but not more than 60 days’ notice. The purchase price in the event of such an acquisition will be the greater of (1) the highest price paid by the managing general partner or any of its affiliates for any limited partner interests of the class purchased within the 90 days preceding the date on which the managing general partner first mails notice of its election to purchase those limited partner interests, and (2) the average of the daily closing prices of the limited partner interests over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed. At any time following the Partnership’s initial offering, if any, if we fail to hold at least 20% of the units of the Partnership our common GP units will be deemed to be part of the same class of partnership interests as the common LP units for purposes of this provision. This provision will make it easier for the managing general partner to take the Partnership private in its discretion.
Indemnification
Under the partnership agreement, the Partnership will indemnify the following persons in most circumstances, to the fullest extent permitted by law, from and against all losses, claims, damages, liabilities, joint or several, expenses (including legal fees and expenses), judgments, fines, penalties, interest, settlements or other amounts arising from any and all threatened, pending or completed claims, demands, actions suits or proceedings: (1) the Partnership’s general partners; (2) any departing general partner; (3) any person who is or was a director, officer, fiduciary, trustee, manager or managing member of the Partnership or any of the Partnership’s subsidiaries, its general partners or any departing general partner; (4) any person who is or was serving as a director, officer, fiduciary, trustee, manager or managing member of another person owing a fiduciary duty to the Partnership or any of its subsidiaries at the request of a general partner or any departing general partner; (5) any person who controls a general partner; or (6) any person designated by the Partnership’s managing general partner. Any indemnification under these provisions will only be out of the Partnership’s assets. Unless they otherwise agree, the Partnership’s general partners will not be personally liable for, or have any obligation to contribute or loan funds or assets to the Partnership to enable the Partnership to effectuate, indemnification. The Partnership may purchase insurance against liabilities asserted against and expenses incurred by persons for its activities, regardless of whether it would have the power to indemnify the person against liabilities under the partnership agreement.
Reimbursement of Expenses
The partnership agreement requires the Partnership to reimburse the Partnership’s managing general partner for (1) all direct and indirect expenses it incurs or payments it makes on behalf of the Partnership (including salary, bonus, incentive compensation and other amounts paid to any person, including affiliates of the managing general partner, to perform services for the Partnership or for the managing general partner in the discharge of its duties to the Partnership) and (2) all other expenses allocable to the Partnership or otherwise incurred by the managing general partner in connection with operating the Partnership’s business (including expenses allocated to the managing general partner by its affiliates). The managing general partner is entitled to determine the expenses that are allocable to the Partnership.
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Conflicts of Interest
Conflicts of interest exist and may arise in the future as a result of (1) the overlap of directors and officers between us and the Partnership’s managing general partner, which may result in conflicting obligations by our directors and officers, (2) duties of the Partnership’s managing general partner to act for the benefit of its owners, which may conflict with our interests and the interests of our stockholders, and (3) our duties as a general partner of the Partnership to act for the benefit of all unit holders, including future unaffiliated partners, which may conflict with our interests and the interests of our stockholders. The directors and officers of the Partnership’s managing general partner, Fertilizer GP, have fiduciary duties to manage Fertilizer GP in a manner beneficial to its owners, but at the same time, Fertilizer GP has a fiduciary duty to manage the Partnership in a manner beneficial to its unit holders, including us. In addition, because we are a general partner of the Partnership, we have a legal duty to exercise our special GP rights in a manner beneficial to the Partnership’s unit holders, who may in the future include unaffiliated partners, but at the same time our directors and officers have a fiduciary duty to act in a manner beneficial to us and our stockholders.
With respect to conflicts of interest between the Partnership and Fertilizer GP, Fertilizer GP will resolve that conflict. The partnership agreement will permit the board of directors of the managing general partner to establish a conflicts committee. See “— Management of the Partnership”. The partnership agreement contains provisions that modify and limit the fiduciary duties of Fertilizer GP and us to the unit holders. The partnership agreement also restricts the remedies available to unit holders (including us) for actions taken that, without those limitations, might constitute breaches of fiduciary duty.
Fertilizer GP, as the managing general partner, will not be in breach of its obligations under the partnership agreement or its duties to the Partnership or its unit holders (including us) if the resolution of the conflict is:
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| • | approved by Fertilizer GP’s conflicts committee, although Fertilizer GP is not obligated to seek such approval; |
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| • | approved by the vote of a majority of the outstanding common units, excluding any common units owned by Fertilizer GP and its affiliates (including us so long as we remain an affiliate); |
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| • | on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or |
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| • | fair and reasonable to the Partnership, taking into account the totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to the Partnership. |
Fertilizer GP may, but is not required to, seek approval from the conflicts committee of its board of directors or from the common unit holders. If Fertilizer GP does not seek approval from the conflicts committee and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the third and fourth bullet points above, then it will be presumed that, in making its decision, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any partner or the Partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Unless the resolution of a conflict is specifically provided for in the partnership agreement, Fertilizer GP or the conflicts committee may consider any factors it determines in good faith to consider when resolving a conflict. When the partnership agreement requires someone to act in good faith, it requires that person to reasonably believe that he is acting in the best interests of the Partnership, unless the context otherwise requires.
Conflicts of interest could arise in the situations described below, among others.
Fertilizer GP Holds all of the Incentive Distribution Rights in the Partnership.
Fertilizer GP, as managing general partner of the Partnership, holds all of the incentive distribution rights in the Partnership. Incentive distribution rights will give Fertilizer GP a right to
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increasing percentages of the Partnership’s quarterly distributions from operating surplus after the aggregate adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009 has been distributed in respect of the special unitsand/or the common and subordinated units. Fertilizer GP may have an incentive to manage the Partnership in a manner which increases these future cash flows rather than in a manner which increases current cash flows. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our stockholders”.
Officers and Directors of Fertilizer GP also Serve as Officers and Directors of us and have Obligations to Both the Partnership and our Business.
All of the executive officers and five of the seven directors of Fertilizer GP also serve as directors and executive officers of CVR Energy. We have entered into a services agreement with Fertilizer GP and the Partnership pursuant to which our executive officers and other employees provide services to the Partnership. The executive officers who work for both us and Fertilizer GP, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, will divide their time between our business and the business of the Partnership. These directors and executive officers will face conflicts of interests from time to time in making decisions that may benefit either our company or the Partnership. When making decisions on behalf of Fertilizer GP they will have to take into account the interests of the Partnership and not of us.
The Owners of the Partnership’s Managing General Partner may Compete with us or the Partnership or own Businesses that Compete with us or the Partnership.
The owners of Fertilizer GP, which are our controlling stockholders and senior management, are permitted to compete with us or the Partnership or to own businesses that compete with us or the Partnership. In addition, the owners of Fertilizer GP are not required to share business opportunities with us or the Partnership. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our stockholders”.
Fertilizer GP is Allowed to take Into Account the Interests of Parties other than the Partnership in Resolving Conflicts.
The partnership agreement contains provisions that reduce the standards to which its general partners would otherwise be held by state fiduciary duty law. For example, the partnership agreement permits Fertilizer GP to make a number of decisions in its individual capacity, as opposed to its capacity as managing general partner. This entitles Fertilizer GP to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, the Partnership, the Partnership’s affiliates or any partner. Examples include the exercise of Fertilizer GP’s call right and the determination of whether to consent to any merger or consolidation of the Partnership.
Fertilizer GP has Limited its Liability and Reduced its Fiduciary Duties, and has also Restricted the Remedies Available to the Partnership’s unit Holders (Including us) for Actions that, without the Limitations, might Constitute Breaches of Fiduciary Duty.
In addition to the provisions described above, the partnership agreement contains provisions that restrict the remedies available to the Partnership’s unit holders for actions that might otherwise constitute breaches of fiduciary duty. For example:
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| • | The partnership agreement provides that Fertilizer GP shall not have any liability to the Partnership or its unit holders (including us) for decisions made in its capacity as managing |
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| | general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of the Partnership. |
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| • | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unit holders must be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to the Partnership, as determined by Fertilizer GP in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable”, Fertilizer GP may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership. |
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| • | The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership or its partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct. |
Actions taken by Fertilizer GP may Affect the Amount of Cash Distributions to Unit Holders.
The amount of cash that is available for distribution to unit holders, including us, is affected by decisions of Fertilizer GP regarding such matters as:
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| • | amount and timing of asset purchases and sales; |
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| • | cash expenditures; |
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| • | borrowings; |
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| • | issuance of additional units; and |
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| • | the creation, reduction, or increase of reserves in any quarter. |
In addition, borrowings by the Partnership and its affiliates do not constitute a breach of any duty owed by Fertilizer GP to the Partnership’s unit holders, including us, including borrowings that have the purpose or effect of enabling Fertilizer GP to receive distributions on the incentive distribution rights.
Contracts between the Partnership, on the one Hand, and Fertilizer GP, on the other, will not be the Result of Arm’s-Length Negotiations.
The partnership agreement allows the Partnership’s managing general partner to determine, in good faith, any amounts to pay itself for any services rendered to the Partnership. Neither the partnership agreement nor any of the other agreements, contracts and arrangements between the Partnership and the managing general partner are or will be the result of arm’s-length negotiations.
The partnership agreement generally provides that any affiliated transaction, such as an agreement, contract or arrangement among the Partnership and its general partners and their affiliates, must be:
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| • | on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or |
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| • | “fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). |
Fertilizer GP Intends to Limit the Liability of the Partnership’s General Partners Regarding the Partnership’s Obligations.
Fertilizer GP intends to limit the liability of the Partnership’s general partners under contractual arrangements so that the contract counterparties have recourse only to the Partnership’s assets and not against the Partnership’s general partners or their assets. The partnership agreement provides
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that any action taken by Fertilizer GP to limit the general partners’ liability or the Partnership’s liability is not a breach of Fertilizer GP’s fiduciary duties, even if the Partnership could have obtained terms that are more favorable without the limitation on liability.
The Partnership may Choose not to Retain Separate Counsel for Itself.
The attorneys, independent accountants and others who perform services for the Partnership will be retained by Fertilizer GP or its affiliates. Attorneys, independent accountants and others who perform services for the Partnership are selected by Fertilizer GP or the conflicts committee and may perform services for Fertilizer GP and its affiliates. Fertilizer GP may cause the Partnership to retain separate counsel for itself in the event of a conflict of interest between a general partner and its affiliates, on the one hand, and the Partnership or the holders of common units, on the other, depending on the nature of the conflict, although it does not intend to do so in most cases.
Fertilizer GP, as Managing General Partner, has the Power and Authority to Conduct the Partnership’s Business (Subject to our Specified Joint Management Rights).
Under the partnership agreement, Fertilizer GP, as managing general partner, has full power and authority to do all things, other than those items that require unit holder approval or our approval or with respect to which it has sought conflicts committee approval, on such terms as it determines to be necessary or appropriate to conduct the Partnership’s business including, but not limited to, the following (subject to our specified joint management rights):
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| • | the making of any expenditures, the lending or borrowing of money, the assumption or guarantee of, or other contracting for, indebtedness and other liabilities, the issuance of evidences of indebtedness, including indebtedness that is convertible into securities of the Partnership, and the incurring of any other obligations; |
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| • | the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the Partnership’s business or assets; |
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| • | the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the Partnership’s assets or the merger or other combination of the Partnership with or into another person; |
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| • | the negotiation, execution and performance of any contracts, conveyances or other instruments; |
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| • | the distribution of Partnership cash; |
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| • | the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; |
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| • | the maintenance of insurance for the Partnership’s benefit and the benefit of its partners; |
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| • | the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships; |
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| • | the control of any matters affecting the Partnership’s rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; |
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| • | the indemnification of any person against liabilities and contingencies to the extent permitted by law; |
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| • | the purchase, sale or other acquisition or disposition of Partnership interests, or the issuance of additional options, rights, warrants and appreciation rights relating to Partnership interests; and |
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| • | the entering into of agreements with any affiliates to render services to the Partnership or to itself in the discharge of its duties as the Partnership’s managing general partner. |
The Partnership Agreement Limits the Fiduciary Duties of the Managing General Partner to the Partnership and to other Unit Holders.
The Partnership’s general partners are accountable to the Partnership and its unit holders as a fiduciary. Fiduciary duties owed to unit holders by the general partners are prescribed by law and the partnership agreement. The Delaware Limited Partnership Act provides that Delaware limited partnerships may, in their partnership agreements, restrict or expand the fiduciary duties owed by the general partner to other partners and the partnership.
The partnership agreement contains various provisions restricting the fiduciary duties that might otherwise be owed by Fertilizer GP. The Partnership has adopted these provisions to allow the Partnership’s general partners or their affiliates to engage in transactions with the Partnership that would otherwise be prohibited by state law fiduciary standards and to take into account the interests of other parties in addition to the Partnership’s interests when resolving conflicts of interest. Without such modifications, such transactions could result in violations of the Partnership’s general partners’ state law fiduciary duty standards. We believe this is appropriate and necessary because (1) the board of directors of Fertilizer GP, the Partnership’s managing general partner, has both fiduciary duties to manage the Partnership’s managing general partner in a manner beneficial to its owners and fiduciary duties to manage the Partnership in a manner beneficial to unit holders (including CVR Energy) and (2) we, in our capacity of general partner, have both duties to exercise our special GP rights in a manner beneficial to our stockholders and fiduciary duties to exercise such rights in a manner beneficial to all of the Partnership’s unit holders. Without these modifications, the Partnership’s general partners’ ability to make decisions involving conflicts of interest would be restricted. The modifications to the fiduciary standards enable the Partnership’s general partners to take into consideration all parties involved in the proposed action. These modifications disadvantage the unit holders because they restrict the rights and remedies that would otherwise be available to unit holders for actions that, without those limitations, might constitute breaches of fiduciary duty, as described below, and permit the Partnership’s general partners to take into account the interests of third parties in addition to the Partnership’s interests when resolving conflicts of interest.
The following is a summary of the material restrictions of the fiduciary duties owed by the general partners:
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| • | State law fiduciary duty standards are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where the general partner has a conflict of interest. |
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| • | The partnership agreement contains provisions that waive or consent to conduct by the Partnership’s general partners and their affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, the partnership agreement provides that when either of the general partners is acting in its capacity as a general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when either of the general partners is acting in its individual capacity, as opposed to in its capacity as a general partner, it may act without any fiduciary obligation to the Partnership or the unit holders whatsoever. These standards reduce the obligations to which the Partnership’s general partners would otherwise be held. |
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| • | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unit holders and that are not approved by the conflicts committee of the board of directors of the Partnership’s managing general partner |
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| • | If the Partnership’s managing general partner does not seek approval from the conflicts committee or the common unit holders and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet point above, then it will be presumed that, in making its decision, the board of directors of the managing general partner, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which the Partnership’s managing general partner would otherwise be held. |
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| • | In addition to the other more specific provisions limiting the obligations of the Partnership’s general partners, the partnership agreement further provides that the Partnership’s general partners and their officers and directors will not be liable for monetary damages to the Partnership or its partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct. |
Under the partnership agreement, the Partnership will indemnify its general partners and their respective officers, directors and managers, to the fullest extent permitted by law, against liabilities, costs and expenses incurred by such general partners or these other persons. The Partnership must provide this indemnification unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that these persons acted in bad faith or engaged in fraud or willful misconduct. The Partnership also must provide this indemnification for criminal proceedings unless the general partner or these other persons acted with knowledge that their conduct was unlawful. Thus, the Partnership’s general partners could be indemnified for their negligent acts if they meet the requirements set forth above. To the extent that these provisions purport to include indemnification for liabilities arising under the Securities Act, in the opinion of the SEC such indemnification is contrary to public policy and therefore unenforceable. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The partnership agreement limits the fiduciary duties of the managing general partner and restricts the remedies available to us for actions taken by the managing general partner that might otherwise constitute breaches of fiduciary duty”.
Intercompany Agreements
In connection with the formation of the Partnership, we entered into several other agreements with the Partnership which govern the business relations among us, the Partnership and the managing general partner.
Feedstock and Shared Services Agreement
In October 2007, we entered into a feedstock and shared services agreement with the Partnership under which we and the Partnership agreed to provide feedstock and other services to each other. These feedstocks and services are utilized in the respective production processes of our refinery and the nitrogen fertilizer plant. Feedstocks provided under the agreement include, among others, hydrogen, high-pressure steam, nitrogen, instrument air, oxygen and natural gas.
The Partnership is obligated to provide us with hydrogen from time to time. The agreement provides hydrogen supply and pricing terms for circumstances where the refinery requires more hydrogen than it can generate. Although we expect that the Partnership will continue to provide hydrogen to us for at least the rest of 2008 as it has done in prior years, we believe that the
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Partnership’s provision of hydrogen to our petroleum operations will decrease, to some extent, during 2008 because our new continuous catalytic reformer will produce hydrogen for us. Also, we expect that a project under consideration will further reduce the Partnership’s hydrogen sales to our refinery.
The agreement provides that both parties must deliver high-pressure steam to one another under certain circumstances. The Partnership must make available to us any high-pressure steam produced by the nitrogen fertilizer plant that is not required for the operation of the nitrogen fertilizer plant. We must use commercially reasonable efforts to provide high-pressure steam to the Partnership for purposes of allowing the Partnership to commence and recommence operation of the nitrogen fertilizer plant from time to time, and also for use at the Linde air separation plant adjacent to our own facility. We are not required to provide such high-pressure steam if doing so would have a material adverse effect on the refinery’s operations. The price for such high pressure steam is calculated using a formula that is based on steam flow and the price of natural gas as published in “Inside F.E.R.C.’s Gas Market Report” under the heading “Prices of Spot Gas delivered to Pipelines” for Southern Star Central Gas Pipeline, Inc. for Texas, Oklahoma and Kansas.
The Partnership is also obligated to make available to us any nitrogen produced by the Linde air separation plant that is not required for the operation of the nitrogen fertilizer plant, as determined by the Partnership in a commercially reasonable manner. The price for the nitrogen is based on a cost of $0.035 cents per kilowatt hour, as adjusted to reflect changes in the Partnership’s electric bill.
The agreement also provides that both we and the Partnership must deliver instrument air to one another in some circumstances. The Partnership must make instrument air available for purchase by us at a minimum flow rate, to the extent produced by the Linde air separation plant and available to the Partnership. The price for such instrument air is $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in the Partnership’s electric bill. To the extent that instrument air is not available from the Linde air separation plant and is available from us, we are required to make instrument air available to the Partnership for purchase at a price of $18,000 per month, prorated according to the number of days of use per month, subject to certain adjustments, including adjustments to reflect changes in our electric bill.
With respect to oxygen requirements, the Partnership is obligated to provide us with oxygen produced by the Linde air separation plant and made available to the Partnership to the extent that such oxygen is not required for operation of the nitrogen fertilizer plant. The oxygen is required to meet certain specifications and is to be sold at a fixed price.
The agreement also addresses the means by which we and the Partnership obtain natural gas. Currently, natural gas is delivered to both the nitrogen fertilizer plant and our refinery pursuant to a contract between us and Atmos Energy Corp., or Atmos. Under the feedstock and shared services agreement, the Partnership reimburses us for natural gas transportation and natural gas supplies purchased on behalf of the Partnership. At our request or at the request of the Partnership, in order to supply the Partnership with natural gas directly, both parties will be required to use their commercially reasonable efforts to (i) add the Partnership as a party to the current contract with Atmos or reach some other mutually acceptable accommodation with Atmos whereby both we and the Partnership would each be able to receive, on an individual basis, natural gas transportation service from Atmos on similar terms and conditions as set forth in the current contract, and (ii) purchase natural gas supplies on their own account.
The agreement also addresses the allocation of various other feedstocks, services and related costs between the parties. Sour water, water for use in fire emergencies and costs associated with security services are all allocated between the two parties by the terms of the agreement. The agreement also requires the Partnership to reimburse us for utility costs related to a sulfur processing agreement between Tessenderlo Kerley, Inc. and us. The Partnership has a similar agreement with Tessenderlo Kerley. Otherwise, costs relating to both our and the Partnership’s existing agreements with Tessenderlo Kerley are allocated equally between the two parties except in certain circumstances.
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The parties may temporarily suspend the provision of feedstocks or services pursuant to the terms of the agreement if repairs or maintenance are necessary on applicable facilities. Additionally, the agreement imposes minimum insurance requirements on the parties and their affiliates.
The agreement has an initial term of 20 years, which will be automatically extended for successive five-year renewal periods. Either party may terminate the agreement, effective upon the last day of a term, by giving notice no later than three years prior to a renewal date. The agreement will also be terminable by mutual consent of the parties or if one party breaches the agreement and does not cure within applicable cure periods and the breach materially and adversely affects the ability of the terminating party to operate its facility. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or the refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding, or otherwise becomes insolvent.
Either party is entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
Coke Supply Agreement
We entered into a coke supply agreement with the Partnership in October 2007 pursuant to which we supply pet coke to the Partnership. This agreement provides that we must deliver to the Partnership during each calendar year an annual required amount of pet coke equal to the lesser of (i) 100 percent of the pet coke produced at our petroleum refinery or (ii) 500,000 tons of pet coke. The Partnership is also obligated to purchase this annual required amount. If during a calendar month we produce more than 41,667 tons of pet coke, then the Partnership has the option to purchase the excess at the purchase price provided for in the agreement. If the Partnership declines to exercise this option, we may sell the excess to a third party.
The price which the Partnership pays for the pet coke is based on the lesser of a coke price derived from the price received by the Partnership for UAN (subject to a UAN-based price ceiling and floor) and a coke index price but in no event will the pet coke price be less than zero. The Partnership also pays any taxes associated with the sale, purchase, transportation, delivery, storage or consumption of the pet coke. The Partnership is entitled to offset any amount payable for the pet coke against any amount due from us under the feedstock and shared services agreement between the parties. If the Partnership fails to pay an invoice on time, the Partnership will pay interest on the outstanding amount payable at a rate of three percent above the prime rate.
In the event we deliver pet coke to the Partnership on a short term basis and such pet coke is off-specification on more than 20 days in any calendar year, there will be a price adjustment to compensate the Partnershipand/or capital contributions will be made to the Partnership to allow it to modify its equipment to process the pet coke received. If we determine that there will be a change in pet coke quality on a long term basis, then we will be required to notify the Partnership of such change with at least three years’ notice. The Partnership will then determine the appropriate changes necessary to its nitrogen fertilizer plant in order to process such off-specification coke. We will compensate the Partnership for the cost of making such modificationsand/or adjust the price of pet coke on a mutually agreeable commercially reasonable basis.
The terms of the coke supply agreement provide benefits both to our petroleum business and the Partnership. In return for receiving a potentially lower price for coke in periods when the coke price
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is impacted by lower UAN prices, we enjoy the following benefits associated with the disposition of a low value by-product of the refining process: avoiding the capital cost and operating expenses associated with coke handling; enjoying flexibility in our crude slate and operations as a result of not being required to meet a specific coke quality; avoiding the administration, credit risk and marketing fees associated with selling coke; and obtaining a contractual right of first refusal to a secure and reliable long-term source of hydrogen from the Partnership to back up our refinery’s own internal hydrogen production. We require hydrogen in order to remove sulfur from diesel fuel and gasoline.
The cost of the pet coke supplied by us to the Partnership in most cases is lower than the price which the Partnership otherwise would pay to third parties. The cost to the Partnership is lower both because the actual price paid is lower and because the Partnership pays significantly reduced transportation costs (since the pet coke is supplied by an adjacent facility which involves no freight or tariff costs). In addition, because the cost the Partnership pays is formulaically related to the price received for UAN (subject to a UAN based price floor and ceiling), the Partnership enjoys lower pet coke costs during periods of lower revenues regardless of the prevailing pet coke market.
The Partnership may be obligated to provide security for its payment obligations under the agreement if in our sole judgment there is a material adverse change in the Partnership’s financial condition or liquidity position or in the Partnership’s ability to make payments. This security shall not exceed an amount equal to 21 times the average daily dollar value of pet coke purchased by the Partnership for the90-day period preceding the date on which we give notice to the Partnership that we have deemed that a material adverse change has occurred. Unless otherwise agreed by us and the Partnership, the Partnership can provide such security by means of a standby or documentary letter of credit, prepayment, a surety instrument, or a combination of the foregoing. If such security is not provided by the Partnership, we may require the Partnership to pay for future deliveries of pet coke on acash-on-delivery basis, failing which we may suspend delivery of pet coke until such security is provided and terminate the agreement upon 30 days’ prior written notice. Additionally, the Partnership may terminate the agreement within 60 days of providing security, so long as the Partnership provides five days prior written notice.
The agreement has an initial term of 20 years, which will be automatically extended for successive five year renewal periods. Either party may terminate the agreement by giving notice no later than three years prior to a renewal date. The agreement is also terminable by mutual consent of the parties or if a party breaches the agreement and does not cure within applicable cure periods. Additionally, the agreement may be terminated in some circumstances if substantially all of the operations at the nitrogen fertilizer plant or our refinery are permanently terminated, or if either party is subject to a bankruptcy proceeding or otherwise becomes insolvent.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements.
The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
Raw Water and Facilities Sharing Agreement
We entered into a raw water and facilities sharing agreement with the Partnership in October 2007 which (i) provides for the allocation of raw water resources between our refinery and the nitrogen fertilizer plant and (ii) provides for the management of the water intake system (consisting primarily of a water intake structure, water pumps, meters, and a short run of piping between the intake structure and the origin of the separate pipes that transport the water to each facility) which draws raw water
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from the Verdigris River for both our facility and the nitrogen fertilizer plant. This agreement provides that a water management team consisting of one representative from each party to the agreement will manage the Verdigris River water intake system. The water intake system is owned and operated by us. The agreement provides that both companies have an undivided one-half interest in the water rights which will allow the water to be removed from the Verdigris River for use at our refinery and the nitrogen fertilizer plant.
The agreement provides that both the nitrogen fertilizer plant and our refinery are entitled to receive sufficient amounts of water from the Verdigris River each day to enable them to conduct their businesses at their appropriate operational levels. However, if the amount of water available from the Verdigris River is insufficient to satisfy the operational requirements of both facilities, then such water shall be allocated between the two facilities on a prorated basis. This prorated basis will be determined by calculating the percentage of water used by each facility over the two calendar years prior to the shortage, making appropriate adjustments for any operational outages involving either of the two facilities.
Costs associated with operation of the water intake system and administration of water rights will be allocated on a prorated basis, calculated by us based on the percentage of water used by each facility during the calendar year in which such costs are incurred. However, in certain circumstances, such as where one party bears direct responsibility for the modification or repair of the water pumps, one party will bear all costs associated with such activity. Additionally, the Partnership must reimburse us for electricity required to operate the water pumps on a prorated basis that is calculated monthly.
Either we or the Partnership are entitled to terminate the agreement by giving at least three years’ prior written notice. Between the time that notice is given and the termination date, we must cooperate with the Partnership to allow the Partnership to build its own water intake system on the Verdigris River to be used for supplying water to its nitrogen fertilizer plant. We will be required to grant easements and access over our property so that the Partnership can construct and utilize such new water intake system, provided that no such easements or access over our property shall have a material adverse affect on our business or operations at the refinery. The Partnership will bear all costs and expenses for such construction if it is the party that terminated the original water sharing agreement. If we terminate the original water sharing agreement, the Partnership may either install a new water intake system at its own expense, or require us to sell the existing water intake system to the Partnership for a price equal to the depreciated book value of the water intake system as of the date of transfer.
Either party may assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The parties may obtain injunctive relief to enforce their rights under the agreement. The agreement contains an obligation to indemnify the other party and its affiliates against liability arising from breach of the agreement, negligence, or willful misconduct by the indemnifying party or its affiliates. The indemnification obligation will be reduced, as applicable, by amounts actually recovered by the indemnified party from third parties or insurance coverage. The agreement also contains a provision that prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain affiliates.
The term of the agreement is perpetual unless (1) the agreement is terminated by either party upon three years’ prior written notice in the manner described above or (2) the agreement is otherwise terminated by the mutual written consent of the parties.
Real Estate Transactions
Land Transfer. We have transferred certain parcels of land to the Partnership, including land where the Partnership expects to expand the nitrogen fertilizer facility.
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Cross-Easement Agreement. We entered into a cross-easement agreement with the Partnership in October 2007 so that both we and the Partnership can access and utilize each other’s land in certain circumstances in order to operate our respective businesses. The agreement grants easements for the benefit of both parties and establishes easements for operational facilities, pipelines, equipment, access, and water rights, among other easements. The intent of the agreement is to structure easements which provides flexibility for both parties to develop their respective properties, without depriving either party of the benefits associated with the continuous reasonable use of the other party’s property.
The agreement provides that facilities located on each party’s property will generally be owned and maintained by the property-owning party; provided, however, that in certain specified cases where a facility that benefits one party is located on the other party’s property, the benefited party will have the right to use, and will be responsible for operating and maintaining, the overlapping facility.
The easements granted under the agreement are non-exclusive to the extent that future grants of easements do not interfere with easements granted under the agreement. The duration of the easements granted under the agreement varies, and some are perpetual. Easements pertaining to certain facilities that are required to carry out the terms of our other agreements with the Partnership terminate upon the termination of such related agreements. We also granted a water rights easement to the Partnership which is perpetual in duration. See “— Raw Water and Facilities Sharing Agreement”.
The agreement contains an obligation to indemnify, defend and hold harmless the other party against liability arising from negligence or willful misconduct by the indemnifying party. The agreement also requires the parties to carry minimum amounts of employer’s liability insurance, commercial general liability insurance, and other types of insurance. If either party transfers its fee simple ownership interest in the real property governed by the agreement, the new owner of the real property will be deemed to have assumed all of the obligations of the transferring party under the agreement, except that the transferring party will retain liability for all obligations under the agreement which arose prior to the date of transfer.
Lease Agreement. We have entered into a five-year lease agreement with the Partnership under which we lease certain office and laboratory space to the Partnership. This agreement expires in October 2012.
Environmental Agreement
We entered into an environmental agreement with the Partnership in October 2007 which provides for certain indemnification and access rights in connection with environmental matters affecting our refinery and the nitrogen fertilizer plant. Generally, both we and the Partnership agreed to indemnify and defend each other and each other’s affiliates against liabilities associated with certain hazardous materials and violations of environmental laws that are a result of or caused by the indemnifying party’s actions or business operations. This obligation extends to indemnification for liabilities arising out of off-site disposal of certain hazardous materials. Indemnification obligations of the parties will be reduced by applicable amounts recovered by an indemnified party from third parties or from insurance coverage.
To the extent that one party’s property experiences environmental contamination due to the activities of the other party and the contamination is known at the time the agreement was entered into, the contaminating party is required to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for expenses incurred in connection with implementing such measures.
To the extent that liability arises from environmental contamination that is caused by us but is also commingled with environmental contamination caused by the Partnership, we may elect in our sole discretion and at our own cost and expense to perform government-mandated environmental activities relating to such liability, subject to certain conditions and provided that we will not waive any rights to indemnification or compensation otherwise provided for in the agreement.
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The agreement also addresses situations in which a party’s responsibility to implement such government-mandated environmental activities as described above may be hindered by the property-owning party’s creation of capital improvements on the property. If a contaminating party bears such responsibility but the property-owning party desires to implement a planned and approved capital improvement project on its property, the parties must meet and attempt to develop a soil management plan together. If the parties are unable to agree on a soil management plan 30 days after receiving notice, the property-owning party may proceed with its own commercially reasonable soil management plan. The contaminating party is responsible for the costs of disposing of hazardous materials pursuant to such plan.
If the property-owning party needs to do work that is not a planned and approved capital improvement project but is necessary to protect the environment, health, or the integrity of the property, other procedures will be implemented. If the contaminating party still bears responsibility to implement government-mandated environmental activities relating to the property and the property-owning party discovers contamination caused by the other party during work on the capital improvement project, the property-owning party will give the contaminating party prompt notice after discovery of the contamination, and will allow the contaminating party to inspect the property. If the contaminating party accepts responsibility for the contamination, it may proceed with government-mandated environmental activities relating to the contamination, and it will be responsible for the costs of disposing of hazardous materials relating to the contamination. If the contaminating party does not accept responsibility for such contamination or fails to diligently proceed with government-mandated environmental activities related to the contamination, then the contaminating party must indemnify and reimburse the property-owning party upon the property-owning party’s demand for costs and expenses incurred by the property-owning party in proceeding with such government-mandated environmental activities.
The agreement also provides for indemnification in the case of contamination or releases of hazardous materials that are present but unknown at the time the agreement is entered into to the extent such contamination or releases are identified in reasonable detail during the period ending five years after the date of the agreement. The agreement further provides for indemnification in the case of contamination or releases which occur subsequent to the date the agreement is entered into. If one party causes such contamination or release on the other party’s property, the latter party must notify the contaminating party, and the contaminating party must take steps to implement all government-mandated environmental activities relating to the contamination, or else indemnify the property-owning party for the costs associated with doing such work.
The agreement also grants each party reasonable access to the other party’s property for the purpose of carrying out obligations under the agreement. However, both parties must keep certain information relating to the environmental conditions on the properties confidential. Furthermore, both parties are prohibited from investigating soil or groundwater conditions except as required for government-mandated environmental activities, in responding to an accidental or sudden contamination of certain hazardous materials, or in connection with implementation of a comprehensive coke management plan as discussed below.
In accordance with the agreement, the parties developed a comprehensive coke management plan after the execution of the environmental agreement. The plan established procedures for the management of pet coke and the identification of significant pet coke-related contamination. Also, the parties agreed to indemnify and defend one another and each other’s affiliates against liabilities arising under the coke management plan or relating to a failure to comply with or implement the coke management plan.
Either party will be entitled to assign its rights and obligations under the agreement to an affiliate of the assigning party, to a party’s lenders for collateral security purposes, or to an entity that acquires all or substantially all of the equity or assets of the assigning party related to the refinery or fertilizer plant, as applicable, in each case subject to applicable consent requirements. The term of the agreement is for at least 20 years, or for so long as the feedstock and shared services agreement is in force, whichever is longer. The agreement also contains a provision that prohibits recovery of lost
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profits or revenue, or special, incidental, exemplary, punitive or consequential damages from either party or certain of its affiliates.
We have entered into a supplement to the environmental agreement confirming that we remain responsible for existing environmental conditions on land that we transferred to the Partnership.
Omnibus Agreement
We entered into an omnibus agreement with the managing general partner and the Partnership in October 2007. The following discussion describes the material terms of the omnibus agreement.
Under the omnibus agreement the Partnership has agreed not to, and will cause its controlled affiliates not to, engage in, whether by acquisition or otherwise, (i) the ownership or operation within the United States of any refinery with processing capacity greater than 20,000 barrels per day whose primary business is producing transportation fuels or (ii) the ownership or operation outside the United States of any refinery, regardless of its processing capacity or primary business, or a refinery restricted business, in either case, for so long as we continue to own at least 50% of the Partnership’s outstanding units. The restrictions will not apply to:
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| • | any refinery restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a refinery restricted business, as determined in good faith by the managing general partner’s board of directors; however, if at any time the Partnership completes such an acquisition, the Partnership must, within 365 days of the closing of the transaction, offer to sell the refinery-related assets to us for their fair market value plus any additional tax or other similar costs that would be required to transfer the refinery-related assets to us separately from the acquired business or package of assets; |
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| • | engaging in any refinery restricted business subject to the offer to us described in the immediately preceding bullet point pending our determination whether to accept such offer and pending the closing of any offers we accept; |
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| • | engaging in any refinery restricted business if we have previously advised the Partnership that our board of directors has elected not to cause us to acquire or seek to acquire such business; or |
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| • | acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any refinery restricted business. |
Under the omnibus agreement, we have agreed not to, and will cause our controlled affiliates other than the Partnership not to, engage in, whether by acquisition or otherwise, the production, transportation or distribution, on a wholesale basis, of fertilizer in the contiguous United States, or a fertilizer restricted business, for so long as we and certain of our affiliates continue to own at least 50% of the Partnership’s outstanding units. The restrictions do not apply to:
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| • | any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by our board of directors, as applicable; however, if at any time we complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to the Partnership for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to the Partnership separately from the acquired business or package of assets; |
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| • | engaging in any fertilizer restricted business subject to the offer to the Partnership described in the immediately preceding bullet point pending the Partnership’s determination whether to accept such offer and pending the closing of any offers the Partnership accepts; |
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| • | engaging in any fertilizer restricted business if the Partnership has previously advised us that it has elected not to acquire such business; or |
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| • | acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any fertilizer restricted business. |
Under the omnibus agreement we have also agreed that the Partnership has a preferential right to acquire any assets or group of assets that do not constitute (i) assets used in a refinery restricted business or (ii) assets used in a fertilizer restricted business. In determining whether to cause the Partnership to exercise any preferential right under the omnibus agreement, the managing general partner will be permitted to act in its sole discretion, without any fiduciary obligation to the Partnership or the unitholders whatsoever (including us). These obligations will continue until such time as we and certain of our affiliates cease to own at least 50% of the Partnership’s outstanding units.
Services Agreement
We entered into a services agreement with the Partnership and the managing general partner of the Partnership in October 2007 pursuant to which we provide certain management and other services to the Partnership and the managing general partner of the Partnership. Under this agreement, the managing general partner of the Partnership engaged us to conduct the day-to-day business operations of the Partnership. We provide the Partnership with the following services under the agreement, among others:
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| • | services by our employees as the Partnership’s corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve the Partnership on a shared, part-time basis only, unless we and the Partnership agree otherwise; |
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| • | administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; |
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| • | management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; |
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| • | recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions; |
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| • | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice; |
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| • | recommending the payment of distributions; and |
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| • | managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time. |
As payment for services provided under the agreement, the Partnership, the managing general partner of the Partnership, or Coffeyville Resources Nitrogen Fertilizers, LLC, the Partnership’s operating subsidiary, must pay us (i) all costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a full-time basis, but excluding share-based compensation; (ii) a prorated share of costs incurred by us in connection with the employment of our employees, other than administrative personnel, who provide services to the Partnership under the agreement on a part-time basis, but excluding share-based compensation, and such prorated share shall be determined by us on a commercially reasonable basis, based on the percent of total working time that such shared personnel are engaged in performing services for the Partnership; (iii) a prorated share of certain administrative costs, including payroll, office costs, services by outside vendors, other sales, general and administrative costs and depreciation and amortization; and (iv) various other administrative costs in accordance with the terms of the agreement, including travel, insurance, legal and audit services, government and public relations and bank charges. The Partnership must pay us within 15 days for invoices we submit under the agreement.
The Partnership and its managing general partner are not required to pay any compensation, salaries, bonuses or benefits to any of our employees who provide services to the Partnership or its
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managing general partner on a full-time or part-time basis; we will continue to pay their compensation. However, personnel performing the actual day-to-day business and operations at the nitrogen fertilizer plant level will be employed directly by the Partnership and its subsidiaries, and the Partnership will bear all personnel costs for these employees.
Either we or the managing general partner of the Partnership may temporarily or permanently exclude any particular service from the scope of the agreement upon 90 days notice. We also have the right to delegate the performance of some or all of the services to be provided pursuant to the agreement to one of our affiliates or any other person or entity, though such delegation does not relieve us from our obligations under the agreement. Either we or the managing general partner of the Partnership may terminate the agreement upon at least 90 days’ notice, but not more than one year’s notice. Furthermore, the managing general partner of the Partnership may terminate the agreement immediately if we become bankrupt, or dissolve and commence liquidation orwinding-up.
In order to facilitate the carrying out of services under the agreement, we and our affiliates, on the one hand, and the Partnership, on the other, have granted one another certain royalty-free, non-exclusive and non-transferable rights to use one another’s intellectual property under certain circumstances.
The agreement also contains an indemnity provision whereby the Partnership, its managing general partner, and Coffeyville Resources Nitrogen Fertilizers, LLC, as indemnifying parties, agree to indemnify us and our affiliates (other than the indemnifying parties themselves) against losses and liabilities incurred in connection with the performance of services under the agreement or any breach of the agreement, unless such losses or liabilities arise from a breach of the agreement by us or other misconduct on our part, as provided in the agreement. The agreement also contains a provision stating that we are an independent contractor under the agreement and nothing in the agreement may be construed to impose an implied or express fiduciary duty owed by us, on the one hand, to the recipients of services under the agreement, on the other hand. The agreement prohibits recovery of lost profits or revenue, or special, incidental, exemplary, punitive or consequential damages from us or certain affiliates, except in cases of gross negligence, willful misconduct, bad faith, reckless disregard in performance of services under the agreement, or fraudulent or dishonest acts on our part.
For the year ended December 31, 2007, the total amount paid or payable to us pursuant to the services agreement was $1.8 million.
Registration Rights Agreement
We entered into a registration rights agreement with the Partnership in October 2007 pursuant to which the Partnership may be required to register the sale of our units (as well as any common units issuable upon conversion of units held by us). Under the registration rights agreement, following any initial offering, we will have the right to request that the Partnership register the sale of units held by us (and the common units issuable upon conversion of units held by us) on our behalf on three occasions including requiring the Partnership to make available shelf registration statements permitting sales of common units into the market from time to time over an extended period. In addition, we have the ability to exercise certain piggyback registration rights with respect to our own securities if the Partnership elects to register any of its equity interests. The registration rights agreement also includes provisions dealing with holdback agreements, indemnification and contribution, and allocation of expenses. All of the Partnership’s units held by us will be entitled to these registration rights.
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DESCRIPTION OF OUR INDEBTEDNESS AND THE CASH FLOW SWAP
First LienSecond Amended and Restated Credit Facility and Second Lien Credit FacilityGuaranty Agreement
In connection with the acquisition of all of the subsidiaries of Coffeyville Group Holdings, LLC on June 24, 2005 by the Goldman Sachs Funds and the Kelso Funds,On December 28, 2006, Coffeyville Resources, LLC, as the borrower, and Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Pipeline, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC, which we refer to collectively as Holdings, and certain of their subsidiaries as guarantors entered into a first lien credit agreement, dated as of June 24, 2005, as amended on July 8, 2005Second Amended and December 16, 2005,Restated Credit and as further amended and restated as of June 29, 2006 (which we refer to as the First Lien Credit Facility)Guaranty Agreement with Goldman Sachs Credit Partners L.P., as sole lead arranger, sole bookrunner and syndication agent, Credit Suisse, Cayman Islands Branch, as Funded LC issuing bank, Wachovia Bank, National Association, as administrative agent, collateral agent, co-documentation agent and revolving issuing bank and Sumitomo Mitsui Banking Corporation, as a co-documentation agent, and a second lien credit facility, dated as of June 24, 2005 and amended as of July 8, 2005, which we refer to as the Second Lien Credit Facility, with Goldman Sachs Credit Partners, L.P., as joint lead arranger, joint bookrunner and syndication agent and Credit Suisse Cayman Islands Branch,Securities (USA) LLC, as joint lead arrangerJoint Lead Arrangers and joint bookrunner, administrative agentJoint Bookrunners, Credit Suisse, as Administrative Agent, Collateral Agent, Funded LC Issuing Bank and collateral agent.Revolving Issuing Bank, Deutsche Bank Trust Company Americas, as Syndication Agent, and ABN Amro Bank N.V., as Documentation Agent.
If the managing general partner of the Partnership elects to pursue a public or private offering of limited partner interests in the Partnership, we expect that any such transaction would require amendments to our Credit Facility, as well as to the Cash Flow Swap, in order to remove the Partnership and its subsidiaries as obligors under such instruments. Any such amendments could result in changes to the Credit Facility’s pricing, mandatory prepayment provisions, covenants and other terms and could result in increased interest costs and require payment by us of additional fees. We have agreed to use our commercially reasonable efforts to obtain such amendments if the managing general partner elects to cause the Partnership to pursue a public or private offering and gives us at least 90 days written notice. However, we cannot assure you that we will be able to obtain any such amendment on terms acceptable to us or at all. If we are not able to amend the Credit Facility on terms satisfactory to us, we may need to refinance it with other facilities. We will not be considered to have used our “commercially reasonable efforts” to obtain such amendments if we do not effect the requested modifications due to (i) payment of fees to the lenders or the swap counterparty, (ii) the costs of this type of amendment, (iii) an increase in applicable margins or spreads or (iv) changes to the terms required by the lenders including covenants, events of default and repayment and prepayment provisions provided that (i), (ii), (iii) and (iv) in the aggregate are not likely to have a material adverse effect on us. In order to effect the requested amendments, we may require that (1) the Partnership’s initial public or private offering generate at least $140 million in net proceeds to us and (2) the Partnership raise an amount of cash (from the issuance of equity or incurrence of indebtedness) equal to $75.0 million minus the amount of capital expenditures for which it will reimburse us from the proceeds of its initial public or private offering and distribute that cash to us prior to, or concurrently with, the closing of its initial public or private offering.
The following summary of the material terms of the First Lien Credit Facility and the Second Lien Credit Facility is only a general description and is not complete and, as such, is subject to and is qualified in its entirety by reference to the provisions of the First Lien Credit Facility and the Second Lien Credit Facility.
The First Lien Credit Facility provides financing of up to $523.3 million,$1.075 billion, consisting of $223.3$775.0 million of tranche CD term loans, $50.0 million of delayed draw term loans available through December 2006 and subject to accelerated payment terms, a $100.0$150.0 million revolving loancredit facility, and a funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. The Second Lien Credit Facility includes a $275.0 million term loan.
The revolving loan facility of $100.0$150.0 million provides for direct cash borrowings for general corporate purposes on a short-term basis. Letters of credit issued under the revolving loan facility are subject to a $50.0$75.0 million sub-limit. The revolving loan commitment maturesexpires on June 24, 2011.December 28, 2012. We have an option to extend this maturity upon written notice to our lenders; however, the revolving loan maturity cannot be extended beyond the final maturity of the term loans, which is June 24, 2012.December 28, 2013.
The $150.0 million funded letter of credit facility provides credit support for our obligations under the Cash Flow Swap. The funded letter of credit facility is fully cash collateralized by the funding by the lenders of cash into the credit linked deposit account. This account is held by the funded letter of credit issuing bank. Contingent upon the requirements of the Cash Flow Swap, we have the ability to reduce the funded letter of credit at any time upon written notice to the lenders.
The First Lien Credit Facilityfunded letter of credit facility expires on December 28, 2010.
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Coffeyville Resources, LLC initially entered into a first lien credit facility and a second lien credit facility on June 24, 2005 in connection with the acquisition of all of the subsidiaries of Coffeyville Group Holdings, LLC by the Goldman Sachs Funds and the Kelso Funds. The first lien credit facility consisted of $225.0 million of term loans, $50.0 million of delayed draw term loans, a $100.0 million revolving loan facility and a funded letter of credit facility of $150.0 million, and the second lien credit facility included a $275.0 million term loan. The first lien credit facility was subsequently amended and restated on June 29, 2006 underon substantially the same terms as the original agreement, as amended. The tranche B term loans were refinanced into tranche C term loans. The primary reason for the June 2006 amendment and restatement was to reduce the applicable margin spreads for borrowings on the first lien term loans and the funded letter of credit facility and to make the capital expenditure covenant less restrictive. On December 28, 2006, Coffeyville Resources, LLC repaid all indebtedness then outstanding under the first lien credit facility and second lien credit facility and entered into the Credit Facility.
Interest Rate and Fees.
The First Lien Credit Facility. The tranche C term loans and delayed drawD term loans bear interest at either LIBOR(a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s election, prime rateoption, (b) LIBOR plus 1.25%3.25% (with step-downs to the prime rate/federal funds effective rate plus 1.75% or 1.50% or LIBOR plus 2.00% and prime rate plus 1%2.75% or 2.50%, respectively, upon achievement of certain rating conditions). The revolving loan facility borrowings bear interest at either LIBOR(a) the greater of the prime rate and the Federal funds effective rate plus 2.50%0.5%, plus in either case 2.25% or, at the
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borrower’s election, prime rateoption, (b) LIBOR plus 1.50%3.25% (with step-downs to the prime rate/federal funds effective rate plus 1.75% or 1.50% or LIBOR plus 2.25% and prime rate plus 1.25%, respectively, and then to LIBOR plus 2.00% and prime rate plus 1%2.75% or 2.50%, respectively, upon certain amounts of prepayments of the term loans and substantial completionachievement of certain capital expenditure projects)rating conditions). Letters of credit issued under the $50.0$75.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per annum owing to the issuing lender. Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owing to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linkedcredit linked deposit account backstopping funded letters of credit. In addition to the fees stated above, the First Lien Credit Facility requires the borrower to pay 0.50% in commitment fees on the unused portion of the revolving loan facility and 1.00% in commitment fees on the unused portion of the delayed draw term loan commitment.facility. The average weighted interest rate on borrowingsthe term loans under the First Lien Credit Facility on June 30,December 31, 2006 and December 31, 2007 was 7.70%.
The Second Lien Credit Facility. The Second Lien Credit Facility borrowings bear interest at LIBOR plus 6.75%8.36% and 7.98%, or at the borrower’s option, prime rate plus 5.75%.respectively.
Prepayments. The First Lien Credit Facility and the Second Lien Credit Facility requirerequires the borrower to prepay outstanding loans, subject to certain exceptions, with:
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| | • | 100% of the net asset sale proceeds received by Holdings or any of its subsidiaries from specified asset sales and net insurance/condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or to make other certain permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or to make other certain permitted investments within 18 months of receipt, each subject to certain limitations; |
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| | • | 100% of the cash proceeds from the incurrence of specified debt obligations by Holdings or any of its subsidiaries; and |
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| | • | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that this percentage will be reduced to 50% whenif the term loan repayment amounttotal leverage ratio at the end of such fiscal year is at least $150.0 million.less than 1.50:1.00 and 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00; |
Mandatory prepayments will be applied first to the term loan, second to the swing line loans, third to the revolving loans, fourth to outstanding reimbursement obligations with respect to revolving letters of credit and funded letters of credit, and fifth to cash collateralize revolving letters of credit and funded letters of credit and sixth to the second lien terms loan under the Second Lien Credit Facility.credit.
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Voluntary prepayments of loans under the First Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, without premium or penalty.
Voluntary prepayments of loans under the Second Lien Credit Facility are permitted, in whole or in part, at the borrower’s option, so long as no amounts are outstanding under the First Lien Credit Facility or unless the lenders under the First Lien Credit Facility provide the requisite consent. Similarly, mandatory prepayments of loans under the Second Lien Credit Facility apply only after no amounts are outstanding under the First Lien Credit Facility. Any voluntary prepayments as well as prepayments out of the cash proceeds from the incurrence of specified debt obligations made to the Second Lien Credit Facility after July 8, 2006 but before July 8, 2007 are subject to a 2.0% prepayment premium and any voluntary prepayments made after July 8, 2007 but before July 8, 2008 are subject to a 1.0% prepayment premium.
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Amortization.
The First Lien Credit Facility. The tranche CD term loans are repayable in quarterly installments in a principal amount equal to the principal amount of the tranche CD term loans outstanding on the quarterly installment date multiplied by 0.25% for each quarterly installment made prior to OctoberApril 1, 20112013 and 23.5% for each quarterly installment made during the period commencing on OctoberApril 1, 20112013 through maturity on June 24, 2012. The delayed draw term loan is subject to quarterly principal amortization payments of 0.25% of the outstanding balance commencing on the last date of the first quarter following the delayed draw term loan termination date or the date on which the delayed draw term loans have been fully funded through the sixth anniversary of the closing date or June 24, 2011. Thereafter, the delayed draw term loans are amortized in equal quarterly installments until June 24, 2012.
The Second Lien Credit Facility. The Second Lien Credit Facility is not subject to scheduled principal amortization; however, the principal outstanding is due and payable upon final maturity on June 24,December 28, 2013.
Collateral and Guarantors. All obligations under the First Lien Credit Facility and the Second Lien Credit Facility are guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries.subsidiaries, including the Partnership and CVR Special GP, LLC. Indebtedness under the First Lien Credit Facility is secured by a first priority security interest in substantially all of Coffeyville Resources, LLC’s assets, including a pledge of all of the capital stock of its domestic subsidiaries and 65% of all the capital stock of each of its foreign subsidiaries on a first lien priority basis. The Second Lien Credit Facility is similarly secured but on a second lien priority basis.
Certain Covenants and Events of Default. Both the First LienThe Credit Facility and the Second Lien Credit Facility containcontains customary covenants and events of default.covenants. These agreements, among other things, restrict, subject to certain exceptions, the ability of Coffeyville Resources, LLC and its subsidiaries to incur additional indebtedness, create liens on assets, make restricted junior payments, enter into agreements that restrict subsidiary distributions, make investments, loans or advances, engage in mergers, acquisitions or sales of assets, dispose of subsidiary interests, enter into sale and leaseback transactions, engage in certain transactions with affiliates and shareholders,stockholders, change the business conducted by the credit parties, and enter into hedging agreements. The agreements provideCredit Facility provides that Coffeyville Resources, LLC may not enter into commodity agreements if, after giving effect thereto, the exposure under all such commodity agreements exceeds 75% of Actual Production (the borrower’s estimated future production of refined products based on the actual production for the three prior months) or for a term of longer than six years from June 24,December 28, 2006. In addition, the borrower may not enter into material amendments related to any material rights under the Cash Flow Swap, the Partnership’s partnership agreement or the management agreements with the Goldman, Sachs Funds& Co. and the Kelso Funds, or the May 2005 stock purchase agreement,& Company, L.P. without the prior written approval of the lenders.
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The First Lien Credit Facility requires the borrower to maintain a minimum interest coverage ratio and a maximum total leverage ratio and the Second Lien Credit Facility requires the borrower to maintain a maximum total leverage ratio. These financial covenants are set forth in the table below:
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| | | | Second Lien
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| | | First Lien Credit FacilityMinimum Interest
| | Credit Facility |
| | | Minimum
| | Maximum
| | Maximum
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| | interest
| | leverage
| | leverage
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Fiscal quarter endingQuarter Ending | | coverage ratioCoverage Ratio
| | ratio
| | ratioLeverage Ratio
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June 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
September 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
December 31, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
March 31, 2007 | | | 2.25:1.00 | | | | 4.75:1.00 | | | | 5.00:1.00 | |
June 30, 2007 | | | 2.50:1.00 | | | | 4.50:1.00 | | | | 4.75:1.00 | |
September 30, 2007 | | | 2.75:1.00 | | | | 4.25:1.00 | | | | 4.75:1.00 | |
December 31, 2007 | | | 3.00:1.00 | | | | 3.50:1.00 | | | | 4.00:1.00 | |
March 31, 2008 | | | 3.25:1.00 | | | | 3.50:1.00 | | | | 4.00:1.00 | |
| June 30, 2008 | | | 3.25:1.00 | | | | 3.25:3.00:1.00 | | | | 3.75:1.00 | |
| September 30, 2008 | | | 3.25:1.00 | | | | 3.00:2.75:1.00 | | | | 3.50:1.00 | |
| December 31, 2008 | | | 3.25:1.00 | | | | 2.75:2.50:1.00 | | | | 3.25:1.00 | |
| March 31, 2009 and thereafter | | | 3.50:3.75:1.00 | | | | 2.50:2.25:1.00 | | | | 3.00: to
December 31, 2009,
2.00:1.00 | thereafter |
In addition, the First Lien Credit Facility also requires the borrower to maintain a maximum capital expenditures limitation of $75.0 million from June 24, 2005 through December 31, 2005, $230.0$125.0 million in 2006, $70.02008, $125.0 million in 2007, $40.02009, $80.0 million in 20082010, and $50.0 million in 2011 and thereafter. If the actual amount of capital expenditures made in any fiscal year (excluding those made in connection with the continuous catalytic reformer and fluidized catalytic crack unit projects) is less than the amount permitted to be made in such fiscal year, the amount of such difference may be carried forward and used to make capital expenditures in succeeding fiscal years. The continuous catalytic reformer andcapital expenditures limitation will not apply to any fiscal year commencing with fiscal 2009 if the fluidized catalytic crack unit projects are subjectborrower obtains a total leverage ratio of less than or equal to their own specific1.25:1.00 for any quarter commencing with the quarter ending December 31, 2008. We believe that the limitations on our capital expenditures imposed by the Credit Facility should allow us to meet our current capital expenditure limitationneeds. However if future events require us or make it beneficial for us to make capital expenditures beyond those currently planned we would need to obtain consent from the lenders under our Credit Facility.
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The Credit Facility also contains customary events of $165.0 million.default. The events of default include the failure to pay interest and principal when due, including fees and any other amounts owed under the Credit Facility, a breach of certain covenants under the Credit Facility, a breach of any representation or warranty contained in the Credit Facility, any default under any of the documents entered into in connection with the Credit Facility, the failure to pay principal or interest or any other amount payable under other debt arrangements in an aggregate amount of at least $20 million, a breach or default with respect to material terms under other debt arrangements in an aggregate amount of at least $20 million which results in the debt becoming payable or declared due and payable before its stated maturity, a breach or default under the Cash Flow Swap that would permit the holder or holders to terminate the Cash Flow Swap, events of bankruptcy, judgments and attachments exceeding $20 million, events relating to employee benefit plans resulting in liability in excess of $20 million, the guarantees, collateral documents or the Credit Facility failing to be in full force and effect or being declared null and void, any guarantor repudiating its obligations, the failure of the collateral agent under the Credit Facility to have a lien on any material portion of the collateral, and any party under the Credit Facility (other than the agent or lenders under the Credit Facility) contesting the validity or enforceability of the Credit Facility.
The First Lien Credit Facility and the Second Lien Credit Facility also contain certain customary affirmative covenants and events of default, includingcontains an event of default upon the occurrence of a change of control. Under the First Lien Credit Agreement,Facility, a “change of control” means (1) the Goldman Sachs Funds and the Kelso Funds cease to beneficially own and control, directly or indirectly, on a fully diluted basis at least 35% of the economic and voting interests in the capital stock of Parent (Coffeyville Acquisition LLC or CVR Energy or any entity that owns all of the capital stock of Holdings)Energy), (2) any person or group other than the Goldman Sachs Fundsand/or the Kelso Funds (a) acquires beneficial ownership of 35% or more on a fully diluted basis of the votingand/or economic interest in the capital stock of HoldingsParent and the percentage votingand/or economic interest acquired exceeds the percentage owned by the Goldman Sachs Funds and the Kelso Funds or (b) shall have obtained the power to elect a majority of the board of Parent, (3) Parent shall cease to own and control, directly or indirectly, 100% on a fully diluted basis of the capital stock of the borrower, (4) Holdings ceases to beneficially own and control all of the capital stock of the borrower or (5) the majority of the seats on the board of Parent cease to be occupied by continuing directors approved by the then-existing directors.
Other. The First Lien Credit Facility and the Second Lien Credit Facility areis subject to an intercreditor agreement betweenamong the lenders of both credit agreements and the provider of the Cash Flow Swap, which deal with,relates to, among other things, priority of liens, payments and proceeds of sale of collateral.
August 2007 Credit Facilities
In August 2007, our subsidiaries entered into three new credit facilities.
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| • | $25.0 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior secured term loan (the “$25.0 million secured facility”). The facility was secured by the same collateral that secures our existing Credit Facility. Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $25.0 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. |
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| • | $75.0 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility. |
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All indebtedness outstanding under the $25.0 million secured facility and the $25.0 million unsecured facility was repaid in October 2007 with the proceeds of our initial public offering, and all three facilities were terminated at that time.
Proposed Senior Secured Credit Facility
Concurrently with the closing of this offering, we anticipate that Coffeyville Resources, LLC will enter into a new $25.0 million senior secured term loan (the “proposed senior secured credit facility”). We anticipate that the proposed senior secured credit facility will be secured by the same collateral that secures our existing Credit Facility and will contain covenants substantially similar to the Credit Facility. Although we have begun negotiations on the new credit facility, we have not entered into any agreement regarding the proposed senior secured credit facility, and as such, there is no guarantee that we will be enter into a credit facility on the terms described above or at all.
Cash Flow Swap
In connection with the Subsequent Acquisition and as required under our existingthen-existing credit facilities, Coffeyville Acquisition LLC entered into a crack spread hedging transaction with J. Aron. The agreements underlying the transaction were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. See “Certain Relationships and Related Party Transactions.”Transactions”. The derivative transaction was entered into for the purpose of managing our exposure to the price fluctuations in crude oil, heating oil and gasoline markets.
The fixed prices for each product in each calendar quarter are specified in the applicable swap confirmation. The floating price for
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| | • | crude oil for each quarter equals the average of the closing settlement price(s) on NYMEX for the Nearby Light Crude Futures Contract that is “first nearby” as of any determination date during that calendar quarter;quarter quoted in U.S. dollars per barrel; |
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| | • | unleaded gasoline for each quarter equals the average of the closing settlement prices on NYMEX for the Unleaded Gasoline contractFutures Contract that is “first nearby” for any determination period to and including the determination period ending December 31, 2006 and the average of the closing settlement prices on NYMEX for Reformulated Gasoline Blendstock for Oxygen Blending futures contractFutures Contract that is “first nearby” for each determination period thereafter quoted in U.S. dollars per gallon; and |
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| | • | heating oil for each quarter equals to the average of the closing settlement prices on NYMEX for the Heating Oil Futures Contract that is “first nearby” as of any determination date during such calendar quarter quoted in U.S. dollars per gallon. |
The hedge transaction is governed by the standard form 1992 International Swap Dealersand Derivatives Association, Inc., or ISDA Master Agreement, which includes a schedule to the ISDA Master Agreement setting forth certain specific transaction terms.
Coffeyville Resources, LLC’s obligations under the hedge transaction are:
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| | • | guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; |
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| | • | secured by a $150$150.0 million funded letter of credit issued under the First Lien Credit Facility in favor of J. Aron; and |
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| | • | to the extent J. Aron’s exposure under the derivative transaction exceeds $150$150.0 million, secured by the same collateral that secures our First Lien Credit Facility. |
In addition, J. Aron is an additional named insured and loss payee under certain insurance policies of Coffeyville Resources, LLC.
The obligations of J. Aron under the derivative transaction are guaranteed by The Goldman Sachs Group, Inc.
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The derivative transaction terminatestransactions terminate on June 30, 2010. Prior to the termination date, neither party has a right to terminate the derivative transaction unless one of the events of default or termination events under the ISDA Master Agreement has occurred. In addition to standard events of default and termination events described in the ISDA Master Agreement, the schedulesschedule to the ISDA Master Agreement provideprovides for the termination of the derivative transaction if:
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| | • | Coffeyville Resources, LLC’s obligations under the derivative transaction cease to be secured as described above equally and ratably with the security interest granted under the First Lien Credit Facility; |
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| | • | Coffeyville Resources, LLC’s obligations under the derivative transaction cease to be guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; or |
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| | • | Coffeyville Resources, LLC fails to maintain a $150$150.0 million funded letter of credit in favor of J. Aron. |
If a termination event occurs, the derivative transaction will be cash-settled on the termination date designated by a party entitled to such designation under the ISDA Master Agreement (to the extent of the amounts owed to either party on the termination date, without netting of payments) and no further payments or deliveries under the derivative transaction will be required.
Intercreditor matters among J. Aron and the lenders under the First Lien Credit Facility and the Second Lien Credit Facility are governed by the Intercreditor Agreement. J. Aron’s security interest in the collateral is pari passu with the security interest in the collateral granted under the First Lien Credit Facility and the Second Lien Credit Facility. In addition, pursuant to the Intercreditor Agreement, J. Aron is entitled to vote together as a class with the lenders under the First Lien Credit Facility with respect to (1) any remedies proposed to be taken by the holders of the secured obligations with respect to the collateral, (2) any matters related to a breach, waiver or modification of the covenants in the First Lien Credit Facility that restrict the granting of liens, the incurrence of indebtedness, and the ability of Coffeyville Resources, LLC to enter into derivative transactions for more than 75% of Coffeyville Resources, LLC’s actual production (based on the three monththree-month period preceding the trade date of the relevant derivative) of refined products or for a term longer than six years, (3) the maintenance of insurance, and (4) any matters relating to the collateral. For any of the foregoing matters, J. Aron is entitled to vote with the lenders under the First Lien Credit Facility as a single class to the extent of the greater of (x) its exposure under the derivative transaction, less the amount secured by the letter of credit and (y) $75 million.
Payment Deferrals Related to Cash Flow Swap
As a result of the flood and the temporary cessation of our Company’s operations on June 30, 2007, Coffeyville Resources, LLC entered into several deferral agreements with J. Aron with respect to the Cash Flow Swap. These deferral agreements deferred to January 31, 2008 payment of approximately $123.7 million plus accrued interest ($5.8 million as of June 1, 2008) which we owed to J. Aron. J. Aron agreed to further defer these payments to August 31, 2008 but required that we use 37.5% of our consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferred amounts, but as of March 31, 2008 we were not required to prepay any portion of the deferred amount.
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| • | On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%. |
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| • | On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payment and |
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| | (b) interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On July 26, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to September 7, 2007 both the $45.0 million payment due August 7, 2007 (and accrued interest) and the $43.7 million payment due July 25, 2007 (and accrued interest). J. Aron deferred these payments on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%. |
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| • | On August 23, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to January 31, 2008 the $45.0 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35.0 million payment which we owed to J. Aron under the Cash Flow Swap to settle hedged volume through August 15, 2007. J. Aron deferred these payments (totaling $123.7 million plus accrued interest) on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payments and (b) interest accrued on the amounts to the date of payment at the rate of LIBOR plus 1.50%. |
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DESCRIPTION OF CONCURRENT OFFERING OF CONVERTIBLE NOTES
Concurrently with this offering, we are offering $125,000,000 aggregate principal amount of % Convertible Senior Notes due 2013 (the “convertible senior notes”). We have also granted the underwriters of the convertible senior note offering an option to purchase an additional $18.75 million aggregate principal amount of convertible senior notes solely to cover over-allotments. The consummation of the convertible senior notes offering is not conditioned upon the concurrent consummation of this offering.
We will pay interest on the convertible senior notes in cash semiannually, in arrears, on and of each year, beginning on , 2008. The convertible senior notes will mature on , 2013.
The convertible senior notes will be our general unsecured obligations (except to the extent of the interest escrow described below) and will rank equal in right of payment to all of our other senior unsecured indebtedness and senior in right of payment to all indebtedness that is contractually subordinated to the convertible senior notes. The convertible senior notes will be structurally subordinated to (i) all existing and future claims of our subsidiaries’ creditors, including trade creditors and (ii) any preferred stock which our subsidiaries may issue to the extent of its liquidation preference. The convertible senior notes will be effectively subordinated to any of our existing and future secured indebtedness to the extent of the value of the collateral securing such indebtedness.
A portion of the proceeds of the concurrent convertible senior notes offering will be invested in government securities to be deposited in an escrow account and will be used to make the first six scheduled interest payments on the convertible senior notes. These payments will be secured by a pledge of the funds in the escrow account.
Holders may convert their convertible senior notes at their option at any time, in whole or in part, prior to the close of business on the scheduled trading day (as defined in the prospectus for the convertible senior notes offering) immediately preceding , 2013, only under the following circumstances: (1) during the five business day period after any five consecutive trading day period (the “measurement period”) during which the trading price (as defined in the prospectus for the convertible senior notes offering) per $1,000 in principal amount of the convertible senior notes for each day of the measurement period was less than 98% of the product of the last reported sale price (as defined in the prospectus for the convertible senior notes offering) of our common stock and the applicable conversion rate for the convertible senior notes for such date; (2) during any calendar quarter (and only during such calendar quarter) after the calendar quarter ending September 30, 2008, if the last reported sale price of our common stock for 20 or more trading days (as defined in the prospectus for the convertible senior notes offering) in a period of 30 consecutive trading days ending on the last trading day of the immediately preceding calendar quarter exceeds 130% of the applicable conversion price in effect for the convertible senior notes on the last trading day of the immediately preceding calendar quarter; or (3) upon the occurrence of specified corporate events. The convertible senior notes will be convertible, regardless of the foregoing circumstances, on and after , 2013 but prior to the close of business on the scheduled trading day immediately preceding the maturity date of the convertible senior notes.
The initial conversion rate for the convertible senior notes will be shares of common stock per $1,000 in principal amount of convertible senior notes (equivalent to an initial conversion price of approximately $ per share of common stock). The conversion rate will be subject to adjustment in some events but will not be adjusted for accrued interest. In addition, we may be required in certain circumstances to increase the conversion rate for any convertible senior notes converted in connection with a make-whole fundamental change (as defined).
Upon the occurrence of a fundamental change, holders may require us to repurchase all or a portion of their convertible senior notes for cash at a price equal to 100% of the principal amount of the convertible senior notes being repurchased, plus accrued and unpaid interest, if any.
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Unless we have made an irrevocable net share settlement election, upon conversion of the convertible senior notes, we will settle conversions of the convertible senior notes (i) entirely in shares of our common stock, (ii) entirely in cash, or (iii) in cash for the principal amount of the convertible senior notes and shares of our common stock, or cash and shares of our common stock, for the excess, if any, of the conversion value above the principal amount. In addition, at any time on or prior to the 35th scheduled trading day prior to the maturity date of the convertible senior notes, we may make an irrevocable net share settlement election pursuant to which we will settle all future conversions of the convertible senior notes either (i) entirely in cash or (ii) in cash for the principal portion amount of convertible senior notes and shares of our common stock, or cash and shares of our common stock, for the excess, if any, of the conversion value above the principal amount. It is our current intent and policy to settle any conversion of the convertible senior notes in the manner specified in clause (ii) of the preceding sentence. The irrevocable net share settlement election is in our sole discretion and does not require the consent of holders of the convertible senior notes.
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DESCRIPTION OF CAPITAL STOCK
Immediately following the completion of this offering, ourOur authorized capital stock will consistconsists of 350,000,000 shares of common stock, par value $0.01 per share, and 50,000,000 shares of preferred stock, par value $0.01 per share, the rights and preferences of which may be established from time to time by our board of directors. UponAs of the completiondate of this offering,prospectus, there will beare 86,141,291 outstanding shares of common stock and no outstanding shares of preferred stock. The following description of our capital stock does not purport to be complete and is subject to and qualified by our amended and restated certificate of incorporation and bylaws, which are included as exhibits to the registration statement of which this prospectus forms a part, and by the provisions of applicable Delaware law.
Common Stock
Holders of our common stock are entitled to one vote for each share on all matters voted upon by our stockholders, including the election of directors, and do not have cumulative voting rights. Subject to the rights of holders of any then outstanding shares of our preferred stock, our common stockholders are entitled to any dividends that may be declared by our board of directors. Holders of our common stock are entitled to share ratably in our net assets upon our dissolution or liquidation after payment or provision for all liabilities and any preferential liquidation rights of our preferred stock then outstanding. Holders of our common stock have no preemptive rights to purchase shares of our stock. The shares of our common stock are not subject to any redemption provisions and are not convertible into any other shares of our capital stock. All outstanding shares of our common stock are and the shares of common stock to be issued in this offering will be, upon payment therefor, fully paid and nonassessable. The rights, preferences and privileges of holders of our common stock will be subject to those of the holders of any shares of our preferred stock we may issue in the future.
Our common stock will be represented by certificates, unless our board of directors adopts a resolution providing that some or all of our common stock shall be uncertificated. Any such resolution will not apply to any shares of common stock that are already certificated until such shares are surrendered to us.
Preferred Stock
Our board of directors may, from time to time, authorize the issuance of one or more classes or series of preferred stock without stockholder approval. Subject to the provisions of our amended and restated certificate of incorporation and limitations prescribed by law, our board of directors is authorized to adopt resolutions to issue shares, designate the series, establish the number of shares, change the number of shares constituting any series, and provide or change the voting powers, designations, preferences and relative participating, optional and other special rights, and any qualifications, limitations or restrictions on shares of our preferred stock, including dividend rights, terms of redemption, conversion rights and liquidation preferences, in each case without any action or vote by our stockholders. We have no current intention to issue any shares of preferred stock.
One of the effects of undesignated preferred stock may be to enable our board of directors to discourage an attempt to obtain control of our company by means of a tender offer, proxy contest, merger or otherwise. The issuance of preferred stock may adversely affect the rights of our common stockholders by, among other things:
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| | • | restricting dividends on the common stock; |
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| | • | diluting the voting power of the common stock; |
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| | • | impairing the liquidation rights of the common stock; or |
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| | • | delaying or preventing a change in control without further action by the stockholders. |
Limitation ofon Liability and Indemnification of Officers and Directors
Our amended and restated certificate of incorporation limits the liability of directors to the fullest extent permitted by Delaware law. The effect of these provisions is to eliminate the rights of our company and our stockholders, through stockholders’ derivative suits on behalf of our company, to recover monetary damages against a director for breach of fiduciary duty as a director, including breaches resulting from grossly
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negligent behavior. However, our directors will be personally liable to us and our stockholders
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for monetary damages if they actedany breach of the director’s duty of loyalty, for acts or omissions not in badgood faith knowingly or intentionally violatedwhich involve intentional misconduct or a knowing violation of law, under Section 174 of the law, authorized illegal dividendsDelaware General Corporation Law or redemptions orfor any transaction from which the director derived an improper benefit from their actions as directors.personal benefit. In addition, our amended and restated certificate of incorporation providesand bylaws provide that we will indemnify our directors and officers to the fullest extent permitted by Delaware law. We may enter into indemnification agreements with our current directors and executive officers prior to the completion of this offering. We also maintain directors and officers insurance.
Corporate Opportunities
Our amended and restated certificate of incorporation provides that the Goldman Sachs Funds and the Kelso Funds have no obligation to offer us an opportunity to participate in business opportunities presented to the Goldman Sachs Funds or the Kelso Funds or their respective affiliates even if the opportunity is one that we might reasonably have pursued, and that neither the Goldman Sachs Funds, the Kelso Funds nor their respective affiliates will be liable to us or our stockholders for breach of any duty by reason of any such activities unless, in the case of any person who is a director or officer of our company, such business opportunity is expressly offered to such director or officer in writing solely in his or her capacity as an officer or director of our company. Stockholders will be deemed to have notice of and consented to this provision of our certificate of incorporation.
In addition, the Partnership’s partnership agreement provides that the owners of the managing general partner of the Partnership, which include the Goldman Sachs Funds and the Kelso Funds, are permitted to engage in separate businesses which directly compete with the Partnership and are not required to share or communicate or offer any potential corporate opportunities to the Partnership even if the opportunity is one that we might reasonably have pursued. The agreement provides that the owners of the managing general partner will not be liable to the Partnership or any partner for breach of any fiduciary or other duty by reason of the fact that such person pursued or acquired for itself any corporate opportunity. See “Risk Factors — Risks Related to the Limited Partnership Structure Through Which We Hold Our Interest in the Nitrogen Fertilizer Business — The managing general partner of the Partnership has a fiduciary duty to favor the interests of its owners, and these interests may differ from, or conflict with, our interests and the interests of our stockholders.”
Delaware Anti-Takeover Law
WeOur amended and restated certificate of incorporation provides that we are not subject to Section 203 of the Delaware General Corporation Law which regulates corporate acquisitions. This law provides that specified persons who, together with affiliates and associates, own, or within three years did own, 15% or more of the outstanding voting stock of a corporation may not engage in business combinations with the corporation for a period of three years after the date on which the person became an interested stockholder. The law defines the term “business combination” to include mergers, asset sales and other transactions in which the interested stockholder receives or could receive a financial benefit on other than a pro rata basis with other stockholders. This provision has
Removal of Directors; Vacancies
Our amended and restated certificate of incorporation and bylaws provide that any director or the entire board of directors may be removed with or without cause by the affirmative vote of the majority of all shares then entitled to vote at an anti-takeover effect with respect to transactions not approved in advance byelection of directors. Our amended and restated certificate of incorporation and bylaws also provide that any vacancies on our board of directors including discouraging takeover attempts that might resultwill be filled by the affirmative vote of a majority of the board of directors then in office, even if less than a premium over the market price forquorum, or by a sole remaining director.
Voting
The affirmative vote of a plurality of the shares of our common stock. Withstock present, in person or by proxy will decide the approvalelection of any directors, and the affirmative vote of a majority of the shares of our common stock present, in person or by proxy will decide all other matters voted on by stockholders, unless the question is one upon which, by express provision of law, under our amended
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and restated certificate of incorporation, or under our bylaws, a different vote is required, in which case such provision will control.
Action by Written Consent
Our amended and restated certificate of incorporation and bylaws provide that stockholder action can be taken by written consent of the stockholders only if the Goldman Sachs Funds and the Kelso Funds collectively beneficially own more than 35.0% of the outstanding shares of our common stock.
Ability to Call Special Meetings
Our bylaws provide that special meetings of our stockholders we could amendcan only be called pursuant to a resolution adopted by a majority of our board of directors or by the chairman of our board of directors. Special meetings may also be called by the holders of not less than 25% of the outstanding shares of our common stock if the Goldman Sachs Funds and the Kelso Funds collectively beneficially own 50% or more of the outstanding shares of our common stock. Thereafter, stockholders will not be permitted to call a special meeting or to require our board to call a special meeting.
Amending Our Certificate of Incorporation and Bylaws
Our amended and restated certificate of incorporation provides that our certificate of incorporation may be amended by the affirmative vote of a majority of the board of directors and by the affirmative vote of the majority of all shares of our common stock then entitled to vote at any annual or special meeting of stockholders. In addition, our amended and restated certificate of incorporation and bylaws provide that our bylaws may be amended, repealed or new bylaws may be adopted by the affirmative vote of a majority of the board of directors or by the affirmative vote of the majority of all shares of our common stock then entitled to vote at any annual or special meeting of stockholders.
Advance Notice Provisions for Stockholders
In order to nominate directors to our board of directors or bring other business before an annual meeting of our stockholders, a stockholder’s notice must be received by the Secretary of the Company at the principal executive offices of the Company not less than 120 calendar days before the date that our proxy statement is released to stockholders in connection with the previous year’s annual meeting of stockholders, subject to certain exceptions contained in our bylaws. If no annual meeting was held in the futureprevious year, or if the date of the applicable annual meeting has been changed by more than 30 days from the date of the previous year’s annual meeting, then a stockholder’s notice, in order to avoidbe considered timely, must be received by the restrictions imposed by this anti-takeover law.Secretary of the Company no later than the later of the 90th day prior to such annual meeting or the tenth day following the day on which notice of the date of the annual meeting was mailed or public disclosure of such date was made.
Listing
Our common stock is listed on the New York Stock Exchange under the symbol “CVI.”
Transfer Agent and Registrar
The transfer agent and registrar for our common stock is .American Stock Transfer & Trust Company.
153270
SHARES ELIGIBLE FOR FUTURE SALE
Upon the completion of this offering, we willWe have outstanding 86,141,291 shares of common stock. The 23,000,000 shares sold in thisour initial public offering plus anyand the 27,100 shares of common stock granted to our non-executive officer employees in connection with our initial public offering and registered pursuant to a registration statement onForm S-8 filed on October 24, 2007 are, and the 10,000,000 shares (11,500,000 shares assuming the underwriters exercise their option to purchase additional shares of common stock in full) sold by the selling stockholder upon exercise of the underwriters’ option and any shares soldstockholders in any directed share program established by us prior to this offering will be, freely tradable without restriction under the Securities Act, unless purchased by our “affiliates” as that term is defined in Rule 144 under the Securities Act. In general, affiliates include executive officers, directors and our largest stockholders. Shares of common stock purchased by affiliates will remain subject to the resale limitations of Rule 144.
The remaining 53,114,191 shares (51,614,191 shares assuming the underwriters exercise their option to purchase additional shares of common stock in full) outstanding prior tofollowing this offering are restricted securities within the meaning of Rule 144. Restricted securities may be sold in the public market only if registered or if they qualify for an exemption from registration under Rules 144 144(k) or Rule 701 promulgated under the Securities Act, which are summarized below.
The executive officers,selling stockholders and our directors and selling stockholder willofficers have agreed to enter intolock-up lock up agreements in connection with this offering, generally providing that they will not offer, sell, contract to sell or grant any option to purchase or otherwise dispose of our common stock or any securities exercisable for or convertible into our common stock owned by itthem (other than the shares of common stock offered hereby) for a period of 18090 days after the date of this prospectus without the prior written consent of .the representatives.
Despite possible earlier eligibility for sale under the provisions of Rules 144 144(k) and 701 under the Securities Act, any shares subject to alock-up agreement will not be salable until thelock-up agreement expires or is waived by .the representatives. Taking into account thelock-up agreement, and assuming does not releasethat Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC are not released from itstheirlock-up agreement,agreements, the 53,114,191 shares (51,694,191 shares assuming the underwriters exercise their option to purchase additional shares of common stock in full) held by our affiliates will be eligible for future sale in accordance with the requirements of Rule 144.144 upon the expiration of the lockup agreements.
In general, under Rule 144 as currently in effect, after the expiration of any applicablelock-up agreements, a personan affiliate who has beneficially owned restricted securities for at least one yearsix months would be entitled to sell within any three month period a number of shares that does not exceed the greater of the following:
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| | • | one percent of the number of shares of common stock then outstanding, which will equal approximately 861,413 shares immediately after this offering; or |
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| | • | the average weekly trading volume of the common stock during the four calendar weeks preceding the sale. |
Sales by affiliates under Rule 144 are also subject to requirements with respect tomanner-of-salemanner of sale requirements, notice requirements and the availability of current public information about us. Under Rule 144(k),144, a person who is not deemed to have been our affiliate at any time during the three months preceding a sale, and who has beneficially owned the shares proposed to be sold for at least two years,six months, is entitled to sell his or her shares without complyingprovided he or she complies with themanner-of-sale, current public information volume limitation,requirement. After one year, a non-affiliate may freely sell his or notice provisions of Rule 144.her shares.
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Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and John J. Lipinski, who, assuming all of the shares of common stock offered hereby are sold, will collectively hold 53,114,191 shares of our common stock (51,614,191 shares assuming the underwriters exercise their option to purchase additional shares of common stock in full), and are parties to registration rights agreements with us. Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, who will hold 52,911,720 shares collectively (51,411,720 shares assuming the underwriters exercise their option to purchase additional shares of common stock in full) can request that we register their shares with the SEC at any time on up to three occasions each, including pursuant to shelf registration statements. Mr. Lipinski can piggyback on any registration statement we file with the SEC.
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UNITED STATES TAX CONSEQUENCES TONON-UNITED STATES HOLDERS
The following is a summary of the material United States federal income and estate tax consequences of the acquisition, ownership and disposition of our common stock by anon-U.S. holder. As used in this summary, the term“non-U.S. holder” means a beneficial owner of our common stock that is not, for United States federal income tax purposes:
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| | • | an individual who is a citizen or resident of the United States or a former citizen or resident of the United States subject to taxation as an expatriate; |
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| | • | a corporation created or organized in or under the laws of the United States, any state thereof or the District of Columbia; |
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| | • | a partnership; |
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| | • | an estate whose income is includible in gross income for U.S. federal income tax purposes regardless of its source; or |
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| | • | a trust, if (1) a United States court is able to exercise primary supervision over the trust’s administration and one or more “United States persons” (within the meaning of the U.S. Internal Revenue Code of 1986, as amended, or the Code) has the authority to control all of the trust’s substantial decisions, or (2) the trust has a valid election in effect under applicable U.S. Treasury regulations to be treated as a “United States person.”person”. |
An individual may be treated as a resident of the United States in any calendar year for United States federal income tax purposes, instead of a nonresident, by, among other ways, being present in the United States on at least 31 days in that calendar year and for an aggregate of at least 183 days during a three-year period ending in the current calendar year. For purposes of this calculation, an individual would count all of the days present in the current year, one-third of the days present in the immediately preceding year and one-sixth of the days present in the second preceding year. Residents are taxed for U.S. federal income purposes as if they were U.S. citizens.
If an entity or arrangement treated as a partnership or other type of pass-through entity for U.S. federal income tax purposes owns our common stock, the tax treatment of a partner or beneficial owner of such entity may depend upon the status of the partner or beneficial owner and the activities of the partnership or entity and by certain determinations made at the partner or beneficial owner level. Partners and beneficial owners in such entities that own our common stock should consult their own tax advisors as to the particular U.S. federal income and estate tax consequences applicable to them.
This summary does not discuss all of the aspects of U.S. federal income and estate taxation that may be relevant to anon-U.S. holder in light of thenon-U.S. holder’s particular investment or other circumstances. In particular, this summary only addresses anon-U.S. holder that holds our common stock as a capital asset (generally, investment property) and does not address:
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| | • | special U.S. federal income tax rules that may apply to particularnon-U.S. holders, such as financial institutions, insurance companies, tax-exempt organizations, and dealers and traders in securities or currencies; |
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| | • | non-U.S. holders holding our common stock as part of a conversion, constructive sale, wash sale or other integrated transaction or a hedge, straddle or synthetic security; |
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| | • | any U.S. state and local ornon-U.S. or other tax consequences; and |
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| | • | the U.S. federal income or estate tax consequences for the beneficial owners of anon-U.S. holder. |
This summary is based on provisions of the Code, applicable United States Treasury regulations and administrative and judicial interpretations, all as in effect or in existence on the date of this prospectus. Subsequent developments in United States federal income or estate tax law, including
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changes in law or differing interpretations, which may be applied retroactively, could have a material effect on the U.S. federal income and estate tax consequences of purchasing, owning and disposing
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of our common stock as set forth in this summary.Eachnon-U.S. holder should consult a tax advisor regarding the U.S. federal, state, local andnon-U.S. income and other tax consequences of acquiring, holding and disposing of our common stock.
Dividends
We do not anticipate making cash distributions on our common stock in the foreseeable future. See “Dividend Policy.”Policy”. In the event, however, that we make cash distributions on our common stock, such distributions will constitute dividends for United States federal income tax purposes to the extent paid out of current or accumulated earnings and profits of the Company. To the extent such distributions exceed the Company’s earnings and profits, they will be treated first as a return of the shareholder’sstockholder’s basis in their common stock to the extent thereof, and then as gain from the sale of a capital asset. If we make a distribution that is treated as a dividend and is not effectively connected with anon-U.S. holder’s conduct of a trade or business in the United States, we will have to withhold a U.S. federal withholding tax at a rate of 30%, or a lower rate under an applicable income tax treaty, from the gross amount of the dividends paid to suchnon-U.S. holder.Non-U.S. holders should consult their own tax advisors regarding their entitlement to benefits under a relevant income tax treaty.
In order to claim the benefit of an applicable income tax treaty, anon-U.S. holder will be required to provide a properly executed U.S. Internal Revenue ServiceIRSForm W-8BEN (or other applicable form) in accordance with the applicable certification and disclosure requirements. Special rules apply to partnerships and other pass-through entities and these certification and disclosure requirements also may apply to beneficial owners of partnerships and other pass-through entities that hold our common stock. Anon-U.S. holder that is eligible for a reduced rate of U.S. federal withholding tax under an income tax treaty may obtain a refund or credit of any excess amounts withheld by filing an appropriate claim for a refund with the U.S. Internal Revenue Service.IRS.Non-U.S. holders should consult their own tax advisors regarding their entitlement to benefits under a relevant income tax treaty and the manner of claiming the benefits.
Dividends that are effectively connected with anon-U.S. holder’s conduct of a trade or business in the United States and, if required by an applicable income tax treaty, are attributable to a permanent establishment maintained by thenon-U.S. holder in the United States, will be taxed on a net income basis at the regular graduated rates and in the manner applicable to United States persons. In that case, we will not have to withhold U.S. federal withholding tax if thenon-U.S. holder provides a properly executed U.S. Internal Revenue ServiceIRSForm W-8ECI (or other applicable form) in accordance with the applicable certification and disclosure requirements. In addition, a “branch profits tax” may be imposed at a 30% rate, or a lower rate under an applicable income tax treaty, on dividends received by a foreign corporation that are effectively connected with the conduct of a trade or business in the United States.
Gain on disposition of our common stock
Anon-U.S. holder generally will not be taxed on any gain recognized on a disposition of our common stock unless:
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| | • | the gain is effectively connected with thenon-U.S. holder’s conduct of a trade or business in the United States and, if required by an applicable income tax treaty, is attributable to a permanent establishment maintained by thenon-U.S. holder in the United States; in these cases, the gain will be taxed on a net income basis at the regular graduated rates and in the manner applicable to U.S. persons (unless an applicable income tax treaty provides otherwise) and, if thenon-U.S. holder is a foreign corporation, the “branch profits tax” described above may also apply; |
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| | • | thenon-U.S. holder is an individual who holds our common stock as a capital asset, is present in the United States for more than 182 days in the taxable year of the disposition and meets other requirements (in which case, except as otherwise provided by an applicable income tax treaty, the gain, which may be offset by U.S. source capital losses, generally will be subject to a flat 30% U.S. federal income tax, even though thenon-U.S. holder is not considered a resident alien under the Code); or |
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| | • | we are or have been a “U.S. real property holding corporation” for U.S. federal income tax purposes at any time during the shorter of the five-year period ending on the date of disposition or the period that thenon-U.S. holder held our common stock. |
Generally, a corporation is a “U.S. real property holding corporation” if the fair market value of its “U.S. real property interests” equals or exceeds 50% of the sum of the fair market value of its worldwide real property interests plus its other assets used or held for use in a trade or business. We believe that we are not currently, and we do not anticipate becoming in the future, a U.S. real property holding corporation. However, because this determination is made from time to time and is dependent upon a number of factors, some of which are beyond our control, including the value of our assets, there can be no assurance that we will not become a U.S. real property holding corporation.
However, even if we are or have been a U.S. real property holding corporation, anon-U.S. holder which did not beneficially own, actually or constructively, more than 5% of the total fair market value of our common stock at any time during the shorter of the five-year period ending on the date of disposition or the period that our common stock was held by thenon-U.S. holder (a “non-5% holder”) and which is not otherwise taxed under any other circumstances described above, generally will not be taxed on any gain realized on the disposition of our common stock if, at any time during the calendar year of the disposition, our common stock was regularly traded on an established securities market within the meaning of the applicable United States Treasury regulations.
We have applied to have ourOur common stock is listed on the .New York Stock Exchange. Although not free from doubt, our common stock should be considered to be regularly traded on an established securities market for any calendar quarter during which it is regularly quoted by brokers or dealers that hold themselves out to buy or sell our common stock at the quoted price. If our common stock were not considered to be regularly traded on an established securities market at any time during the applicable calendar year, then a non-5% holder would be taxed for U.S. federal income tax purposes on any gain realized on the disposition of our common stock on a net income basis as if the gain were effectively connected with the conduct of a U.S. trade or business by the non-5% holder during the taxable year and, in such case, the person acquiring our common stock from a non-5% holder generally would have to withhold 10% of the amount of the proceeds of the disposition. Such withholding may be reduced or eliminated pursuant to a withholding certificate issued by the U.S. Internal Revenue ServiceIRS in accordance with applicable U.S. Treasury regulations. We urge allnon-U.S. holders to consult their own tax advisors regarding the application of these rules to them.
Federal estate tax
Our common stock that is owned or treated as owned by an individual who is not a U.S. citizen or resident of the United States (as specially defined for U.S. federal estate tax purposes) at the time of death will be included in the individual’s gross estate for U.S. federal estate tax purposes, unless an applicable estate tax or other treaty provides otherwise and, therefore, may be subject to U.S. federal estate tax.
Information reporting and backup withholding tax
Dividends paid to anon-U.S. holder maywill be subject to U.S. information reporting and may be subject to backup withholding. Anon-U.S. holder will be exempt from backup withholding if thenon-U.S. holder provides a properly executed U.S. Internal Revenue ServiceIRSForm W-8BEN or otherwise meets documentary
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evidence requirements for establishing its status as anon-U.S. holder or otherwise establishes an exemption.
The gross proceeds from the disposition of our common stock may be subject to U.S. information reporting and backup withholding. If anon-U.S. holder sells our common stock outside the United States through anon-U.S. office of anon-U.S. broker and the sales proceeds are paid to thenon-U.S. holder outside the United States, then the U.S. backup withholding and information reporting requirements generally will not apply to that payment. However, United States information reporting, but not U.S. backup withholding, will apply to a payment of sales proceeds, even if that payment is
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made outside the United States, if anon-U.S. holder sells our common stock through anon-U.S. office of a broker that:
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| | • | is a United States person; |
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| | • | derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States; |
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| | • | is a “controlled foreign corporation” for U.S. federal income tax purposes; or |
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| | • | is a foreign partnership, if at any time during its tax year: |
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| | • | one or more of its partners are United States persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or |
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| | • | the foreign partnership is engaged in a U.S. trade or business, |
unless the broker has documentary evidence in its files that thenon-U.S. holder is not a United States person and certain other conditions are met or thenon-U.S. holder otherwise establishes an exemption.
If anon-U.S. holder receives payments of the proceeds of a sale of our common stock to or through a United States office of a broker, the payment is subject to both U.S. backup withholding and information reporting unless thenon-U.S. holder provides a properly executed U.S. Internal Revenue ServiceIRSForm W-8BEN certifying that thenon-U.S. Holder is not a “United States person” or thenon-U.S. holder otherwise establishes an exemption.
Anon-U.S. holder generally may obtain a refund of any amounts withheld under the backup withholding rules that exceed thenon-U.S. holder’s U.S. federal income tax liability by filing a refund claim with the U.S. Internal Revenue Service.IRS.
158276
UNDERWRITING
The Company, the selling stockholderstockholders and the underwriters to be subsequently identified will enter into an underwriting agreement with respect to the shares being offered. Subject to certain conditions, each underwriter has severally agreed to purchase the number of shares indicated in the following table. Goldman, Sachs & Co. and Deutsche Bank Securities Inc. are the joint book-running managers for this offering and the representatives of the underwriters.
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Underwriters | | Number of Shares | |
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| Goldman, Sachs & Co. | | | | |
| Deutsche Bank Securities Inc. | | | | |
| Citigroup Global Markets Inc. | | | | |
| Credit Suisse Securities (USA) LLC | | | | |
| | | | |
| Total | | | 10,000,000 | |
| | | | |
The underwriters are committed to take and pay for all of the shares being offered, if any are taken, other than the shares covered by the option described below unless and until this option is exercised. We expect that the underwriting agreement will provide that the obligations of the underwriters to take and pay for the shares are subject to a number of conditions, including, among others, the accuracy of the Company’s and the selling stockholders’ representations and warranties in the underwriting agreement, receipt of specified letters from counsel and the Company’s independent registered public accounting firm, and receipt of specified officers’ certificates.
To the extent that the underwriters sell more than 10,000,000 shares, the underwriters have an option to buy up to an additional 1,500,000 shares of common stock from certain of the selling stockholderstockholders to cover such sales. They may exercise that option for 30 days. If any shares are purchased pursuant to this option, the underwriters will severally purchase shares from each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC pro rata in approximately the same proportion as set forth in the table above.
The following table shows the per share and total underwriting discounts and commissions to be paid to the underwriters by the Company and the selling stockholder.stockholders. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase 1,500,000 additional shares of common stock.
Paid by the Company
| | | | | | | | | |
| | | No Exercise | | | Full Exercise | |
| |
| Per Share | | $ | | | | $ | | |
| Total | | $ | | | | $ | | |
Paid by the selling stockholder
| | | | | | | | |
| | No Exercise | | | Full Exercise | |
|
Per Share | | | | | | | | |
Total | | | | | | | | |
Shares sold by the underwriters to the public will initially be offered at the initial public offering price set forth on the cover page of this prospectus. Any shares sold by the underwriters to securities dealers may be sold at a discount of up to $ per share from the initial public offering price. If all of the shares are not sold at the initial public offering price, the representatives may change the offering price and the other selling terms. The offering of the shares by the underwriters is subject to receipt and acceptance and subject to the underwriters’ right to reject any order in whole or in part.
The Company, itsthe selling stockholders and our directors and executive officers directors and the selling stockholder have agreed with the underwriters, subject to exceptions, not to dispose of or hedge any of the shares of common stock or securities convertible into or exchangeable for shares of common stock during the period from the date of this prospectus continuing through the date 18090 days after the date of this prospectus, except with the prior written consent of the representatives. This agreement does not apply to any existing employee benefit plans or shares issued in connection with acquisitions or business transactions. See ”Shares“Shares Eligible for Future Sale” for a discussion of specified transfer restrictions.
The180-day restricted period described in the preceding paragraph will be automatically extended if: (1) during the last 17 days of the180-day restricted period the Company issues an earnings underwriters have informed us that they do not presently intend to release shares or announces material news or a material event; or (2) priorother securities subject to the expirationlock-up agreements. Any determination to release any shares subject to thelock-up agreements would be based on a number of the180-day restricted period,factors at the Company announces that it will release earnings results during the15-day period following the last daytime of the180-day period, in which case the restrictions described in the preceding paragraph will continue to apply until the expiration of the18-day period beginning on the issuance of the earnings release or the announcement of the material news or material event.any such determination;
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Atsuch factors may include the Company’s request, have reserved for sale, at the initial public offeringmarket price up to % of the shares offered hereby sold to certain directors, officers, employees and persons having relationships with the Company. The number of shares of common stock, available for sale to the general public will be reduced toliquidity of the extent such persons purchase such reserved shares. Any reserved shares which are not so purchased will be offered by the underwriters to the general public on the same terms as the other shares offered hereby.
Prior to this offering, there has been no publictrading market for the common stock. The initial public offering price willstock, general market conditions, the number of shares proposed to be negotiated among the Company, the selling stockholdersold, and the representatives. Among the factors to be considered in determining the initial public offering pricetiming, purpose and terms of the shares, in addition to prevailing market conditions, will be the Company’s historical performance, estimates of the business potential and earnings prospects of the Company, an assessment of the Company’s management and the consideration of the above factors in relation to market valuation of companies in related businesses.proposed sale.
An application has been made to list the shares ofOur common stock is listed on the New York Stock Exchange under the symbol “ ”.“CVI.”
In connection with this offering, the underwriters may purchase and sell shares of the common stock in the open market. These transactions may include short sales, stabilizing transactions and purchases to cover positions created by short sales. Short sales involve the sale by the underwriters of a greater number of shares than they are required to purchase in this offering. “Covered” short sales are sales made in an amount not greater than the underwriters’ option to purchase additional shares from the selling stockholderus in this offering. The underwriters may close out any covered short position by either exercising their option to purchase additional shares or purchasing shares in the open market. In determining the source of shares to close out the covered short position, the underwriters will consider, among other things, the price of shares available for purchase in the open market as compared to the price at which they may purchase additional shares pursuant to the option granted to them. “Naked” short sales are any sales in excess of that option. The underwriters must close out any naked short position by purchasing shares in the open market. A naked short position is more likely to be created if the underwriters are concerned that there may be downward pressure on the price of the shares of common stock in the open market after pricing that could adversely affect investors who purchase in this offering. Stabilizing transactions consist of various bids for or purchases of shares of common stock made by the underwriters in the open market prior to the completion of this offering.
The underwriters may also impose a penalty bid. This occurs when a particular underwriter repays to the underwriters a portion of the underwriting discount received by it because the representatives have repurchased shares sold by or for the account of that underwriter in stabilizing or short covering transactions.
Purchases to cover a short position and stabilizing transactions may have the effect of preventing or retarding a decline in the market price of the shares of common stock and, together with the imposition of the penalty bid, may stabilize, maintain or otherwise affect the market price of the shares of common stock. As a result, the price of the shares of common stock may be higher than the price that otherwise might exist in the open market. If these activities are commenced, they may be discontinued at any time. These transactions may be effected on the NYSE, in theover-the-counter market or otherwise.
Each of the underwritersunderwriter has represented and agreed that:
(a) it has not made or will not make an offer of shares to the public in the United Kingdom within the meaning of section 102B of the Financial Services and Markets Act 2000, as amended, or FSMA, except to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities or otherwise in circumstances which do not require the publication by us of a prospectus pursuant to the Prospectus Rules of the Financial Services Authority, or FSA;
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(b) it has only communicated or caused to be communicated and will only communicate or cause to be communicated an invitation or inducement to engage in investment activity (within the meaning of sectionSection 21 of the FSMA) to persons who have professional experiencereceived by it in matters relating to investments falling within Article 19(5)connection with the issue or sale of the Financial Services and Markets Act 2000 (Financial Promotion) Order 2005 orshares in circumstances in which section 21Section 21(1) of the FSMA does not apply to us;the Company; and
(c)(b) it has complied with, and will comply with all applicable provisions of the FSMA with respect to anything done by it in relation to the shares in, from or otherwise involving the United Kingdom.
In relation to each Member State of the European Economic Area which has implemented the Prospectus Directive (each, a “RelevantRelevant Member State”)State), each underwriter has represented and agreed that with effect from and including the date on which the Prospectus Directive is implemented in that Relevant Member State (the “RelevantRelevant Implementation Date”)Date) it has not made and will not make an offer of shares to the public in that Relevant Member State prior to the publication of a prospectus in relation to the shares which has been approved by the competent authority in that Relevant Member State or, where appropriate, approved in another Relevant Member State and notified to the competent authority in that Relevant Member State, all in accordance with the Prospectus Directive, except that it may, with effect from and including the Relevant Implementation Date, make an offer of shares to the public in that Relevant Member State at any time:
(a) to legal entities which are authorized or regulated to operate in the financial markets or, if not so authorized or regulated, whose corporate purpose is solely to invest in securities;
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(b) to any legal entity which has two or more of (1) an average of at least 250 employees during the last financial year; (2) a total balance sheet of more than €43,000,000 and (3) an annual net turnover of more than €50,000,000, as shown in its last annual or consolidated accounts;
(c) to fewer than 100 natural or legal persons (other than qualified investors as defined in the Prospectus Directive) subject to obtaining the prior consent of the representatives for any such offer; or
(c)(d) in any other circumstances which do not require the publication by the Company of a prospectus pursuant to Article 3 of the Prospectus Directive.
For the purposes of this provision, the expression an “offer of shares to the public” in relation to any shares in any Relevant Member State means the communication in any form and by any means of sufficient information on the terms of the offer and the shares to be offered so as to enable an investor to decide to purchase or subscribe the shares, as the same may be varied in that Relevant Member State by any measure implementing the Prospectus Directive in that Relevant Member State and the expression Prospectus Directive means Directive 2003/71/EC and includes any relevant implementing measure in each Relevant Member State.
The shares may not be offered or sold by means of any document other than (i) in circumstances which do not constitute an offer to the public within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), or (ii) to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder, or (iii) in other circumstances which do not result in the document being a “prospectus” within the meaning of the Companies Ordinance (Cap. 32, Laws of Hong Kong), and no advertisement, invitation or document relating to the shares may be issued or may be in the possession of any person for the purpose of issue (in each case whether in Hong Kong or elsewhere), which is directed at, or the contents of which are likely to be accessed or read by, the public in Hong Kong (except if permitted to do so under the laws of Hong Kong) other than with respect to shares which are or are intended to be disposed of only to persons outside Hong Kong or only to “professional investors” within the meaning of the Securities and Futures Ordinance (Cap. 571, Laws of Hong Kong) and any rules made thereunder.
This prospectus has not been registered as a prospectus with the Monetary Authority of Singapore. Accordingly, this prospectus and any other document or material in connection with the
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offer or sale, or invitation for subscription or purchase, of the shares may not be circulated or distributed, nor may the shares be offered or sold, or be made the subject of an invitation for subscription or purchase, whether directly or indirectly, to persons in Singapore other than (1) to an institutional investor under Section 274 of the Securities and Futures Act, Chapter 289 of Singapore, or the SFA, (2) to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA or (3) otherwise pursuant to, and in accordance with the conditions of, any other applicable provision of the SFA.
Where the shares are subscribed or purchased under Section 275 by a relevant person which is: (a) a corporation (which is not an accredited investor) the sole business of which is to hold investments and the entire share capital of which is owned by one or more individuals, each of whom is an accredited investor; or (b) a trust (where the trustee is not an accredited investor) whose sole purpose is to hold investments and each beneficiary is an accredited investor, shares, debentures and units of shares and debentures of that corporation or the beneficiaries’ rights and interest in that trust shall not be transferable for 6 months after that corporation or that trust has acquired the shares under Section 275 except: (1) to an institutional investor under Section 274 of the SFA or to a relevant person, or any person pursuant to Section 275(1A), and in accordance with the conditions, specified in Section 275 of the SFA; (2) where no consideration is given for the transfer; or (3) by operation of law.
The securities have not been and will not be registered under the Securities and Exchange Law of Japan (the “Securities and Exchange Law”) and each underwriter has agreed that it will not offer or sell any securities, directly or indirectly, in Japan or to, or for the benefit of, any resident of Japan (which
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(which term as used herein means any person resident in Japan, including any corporation or other entity organized under the laws of Japan), or to others for re-offering or resale, directly or indirectly, in Japan or to a resident of Japan, except pursuant to an exemption from the registration requirements of, and otherwise in compliance with, the Securities and Exchange Law and any other applicable laws, regulations and ministerial guidelines of Japan.
The underwriters do not expect sales to discretionary accounts to exceed five percent of the total number of shares offered.
The Company estimates that its share of the total expenses of this offering excluding underwriting discounts and commissions, will be approximately $ .$1.3 million.
The Company and the selling stockholderstockholders have agreed to indemnify the several underwriters against specified liabilities, including liabilities under the Securities Act.
Affiliates of Goldman, Sachs & Co. own more than 10% of the Company’s outstanding common stock. As a result, Goldman, Sachs & Co. is deemed to be an affiliate of the Company under Rule 2720(b)(1) of the NASD Conduct Rules and is deemed to have a conflict of interest under Rule 2720 of the NASD Conduct Rules. Accordingly, this offering will be made in compliance with the applicable provisions of Rule 2720 of the NASD Conduct Rules as required by Rule 2720 of the NASD Conduct Rules.
Coffeyville Acquisition II LLC, a selling stockholder and an affiliate of Goldman, Sachs & Co., will receive a portion of the net proceeds of this offering.
Certain of the underwriters and their respective affiliates have, from time to time, performed, and may in the future perform, various financial advisory, investment banking, commercial banking and other services for our company, for which they received or will receive customary fees and expenses. Furthermore, certain of the underwriters and their respective affiliates may, from time to time, enter into arms-length transactions with us in the ordinary course of their business.
Goldman Sachs Credit Partners L.P. and Credit Suisse Securities (USA) LLC are joint lead arrangers and joint bookrunners under our Credit Facility, Credit Suisse is the administrative agent and Deutsche Bank Trust Company Americas is the syndication agent under our Credit Facility. Goldman Sachs Credit Partners L.P., Deutsche Bank Securities Inc., Credit Suisse and Citicorp North America, Inc. are lenders under the Credit Facility. In addition, each of the underwriters for this offering is also participating in our concurrent offering of convertible senior notes.
For a description of other transactions between us and Goldman, Sachs & Co. and its affiliates, including payments of dividends and payments under our credit facilities by us to such affiliates and director designation rights, see “Certain Relationships and Related Party Transactions” and “The Nitrogen Fertilizer Limited Partnership.”
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LEGAL MATTERS
The validity of the shares of common stock offered by this prospectus will be passed upon for our company by Fried, Frank, Harris, Shriver & Jacobson LLP, New York, New York. Debevoise & Plimpton LLP, New York, New York is acting as counsel to the underwriters. Debevoise & Plimpton LLP has in the past provided, and continues to provide, legal services to Kelso & Company, including relating to Coffeyville Acquisition LLC.
EXPERTS
The consolidated financial statements of CVR Energy, Inc. and subsidiaries, which we refer to as Successor, collectively refer to the consolidated financial statements for the year ended December 31, 2003 and for the 62 day period ended March 2, 2004 for the former Farmland Petroleum Division and one facility within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor), the consolidated financial statements as of December 31, 2004 and for the 304-day period ended December 31, 2004 and for the 174-day period ended June 23, 2005 for Coffeyville Group Holdings, LLC and subsidiaries, excluding Leiber Holdings LLC, as discussed in note 1 to the consolidated financial statements, which we refer to as Immediate Predecessor, and the consolidated financial statements as of December 31, 20052006 and 2007 and for the 233 day233-day period ended December 31, 2005
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for Coffeyville Acquisition LLC and subsidiaries, which we refer to as Successor have been included herein (and in the registration statement) in reliance upon the report of KPMG LLP, independent registered public accounting firm, appearing elsewhere herein, and upon the authority of said firm as experts in accounting and auditing.
The audit report covering the consolidated financial statements of CVR Energy, Inc. and subsidiaries noted above contains an explanatory paragraph that states that as discussed in note 1 to the consolidated financial statements, effective March 3, 2004, Immediate Predecessor acquired the net assets of Original Predecessor in a business combination accounted for as a purchase, and effective June 24, 2005, Successor acquired the net assets of Immediate Predecessor in a business combination accounted for as a purchase. As a result of these acquisitions, the consolidated financial statements for the periods after the acquisitions are presented on a different cost basis than that for the periods before the acquisitions and, therefore, are not comparable. Furthermore, theThe audit report covering the consolidated financial statements of Coffeyville Acquisition LLC noted abovealso contains an emphasisexplanatory paragraph that states as discussed in note 2 to the consolidated financial statements, Farmland allocated certain general corporate expensesthe Company has restated the accompanying consolidated financial statements as of and interest expense to Original Predecessor for the year ended December 31, 2003, and for the 62 day period ended March 2, 2004. The allocation of these costs is not necessarily indicative of the costs that would have been incurred if Original Predecessor had operated as a stand-alone entity.2007.
WHERE YOU CAN FIND MORE INFORMATION
We have filed with the SEC a registration statement onForm S-1 under the Securities Act with respect to the common stock. This prospectus does not contain all of the information set forth in the registration statement and the exhibits and schedules to the registration statement. For further information with respect to us and our common stock, we refer you to the registration statement and the exhibits and schedules filed as a part of the registration statement. Statements contained in this prospectus concerning the contents of any contract or any other document are not necessarily complete. If a contract or document has been filed as an exhibit to the registration statement, we refer you to the copy of the contract or document that has been filed as an exhibit and reference thereto is qualified in all respects by the terms of the filed exhibit. The registration statement, including exhibits and schedules, may be inspected without charge at the Public Reference Room of the SEC at 100 F Street, N.E., Washington, D.C. 20549, and copies of all or any part of it may be obtained from that office after payment of fees prescribed by the SEC. Information on the operation of the Public Reference Room may be obtained by calling the SEC at1-800-SEC-0330. The SEC maintains a web site that contains reports, proxy and information statements and other information regarding registrants that file electronically with the SEC athttp://www.sec.gov.
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GLOSSARY OF SELECTED TERMS
The following are definitions of certain industry terms used in this prospectus.
| | |
Alkylation2-1-1 crack spread | | A process uniting olefins and isoparaffins forming a longer chain, isoparaffin; particularly the reactingThe approximate gross margin resulting from processing two barrels of butylene and isobutane, with sulfuric acid or hydrofluoric acid as a catalyst,crude oil to produce a high-octane, low-sensitivity blending agent for gasoline.one barrel of gasoline and one barrel of heating oil. |
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| Barrel | | Common unit of measure in the oil industry which equates to 42 gallons. |
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| Blendstocks | | Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others. |
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| bpd | | Abbreviation for barrels per day. |
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| Btu | | British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit. |
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| Bulk sales | | Volume sales through third party pipelines, in contrast to tanker truck quantity sales. |
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| By-products | | Products that result from extracting high value products such as gasoline and diesel fuel from crude oil; these include black oil, sulfur, propane, pet coke and other products. |
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| Capacity | | Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints. |
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| Catalyst | | A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process. |
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Coffeyville supply area | | Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and Iowa. |
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| Coker unit | | A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke. |
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| Common units | | The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies. |
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| Corn belt | | The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. |
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| Crack spread | | A simplified modelcalculation that measures the difference between the price for light products and crude oil. For example, 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude |
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| | oil to produce one barrel of gasoline and one barrel of diesel fuel. |
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| Crude slate | | The mix of different crude types (qualities) being charged to a crude unit. |
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| Crude slate optimization | | The process of determining the most economic crude oils to be refined based upon the prevailing product values, crude prices, crude oil yields and refinery process unit operating unit constraints to maximize profit. |
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| Crude unit | | The initial refinery unit to process crude oil by separating the crude oil according to boiling point under high heat to recover various hydrocarbon fractions. |
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| Distillates | | Primarily diesel fuel, kerosene and jet fuel. |
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| Ethanol | | A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate. |
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| Farm belt | | Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. |
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| Feedstocks | | Hydrocarbon compounds,Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. |
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| Fluid catalytic cracking unit | | Converts gas oil from the crude unit or coker unit into liquefied petroleum gas, distillates and gasoline blendstocks by applying heat in the presence of a catalyst. |
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| Fluxant | | Material added to coke to aid in the removal of coke metal impurities from the gasifier. The material consists of a mixture of fly ash and sand. |
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| Heavy crude oil | | A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel. |
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| Independent refiner | | A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties. |
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| Jobber | | A person or company that purchases quantities of refined fuel from refining companies, either for sale to retailers or to sell directly to the users of those products. |
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| Light crude oil | | A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel. |
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| Liquefied petroleum gas | | Light hydrocarbon material gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling. |
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| Magellan Midstream Partners L.P. | | A publicly traded company whose business is the transportation, storage and distribution of refined petroleum products. |
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| Maya | | A heavy, sour crude oil from Mexico characterized by an API gravity of approximately 22.0 and a sulfur content of approximately 3.3 weight percent. |
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MTBEMidcontinent | | Methyl Tertiary Butyl Ether, an ether produced fromRefers to the reactionstates of isobutyleneKansas, Oklahoma, Missouri, Nebraska and methanol specifically for use as a gasoline blendstock. The EPA required MTBE or other oxygenates to be blended into reformulated gasoline.Iowa. |
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| Modified Solomon complexity | | Standard industry measure of a refinery’s ability to process less expensive feedstock, such as heavier and high-sulfur content crude oils, into value-added products. The weighted average of the Solomon complexity factors for each operating unit multiplied by the throughput of each refinery unit, divided by the crude capacity of the refinery. |
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| MMBtu | | One million British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Farenheit. |
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| Naphtha | | The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane. |
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| Netbacks | | Refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excludes shipment costs. Also referred to as plant gate price. |
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| Operating units | | Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on service. |
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| Override units | | The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which represent profits interests in the respective limited liability companies. With respect to the override units issued under the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, the units are classified as either operating units or value units. |
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| PADD I | | East Coast Petroleum Area for Defense District which includes Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West Virginia. |
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| PADD II | | Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin. |
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| PADD III | | Gulf Coast Petroleum Area for Defense District which includes Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas. |
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| PADD IV | | Rocky Mountains Petroleum Area for Defense District which includes Colorado, Idaho, Montana, Utah, and Wyoming. |
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| PADD V | | West Coast Petroleum Area for Defense District which includes Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington. |
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| Pet coke | | A coal-like substance that canis produced during the refining process. |
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| Phantom performance points | | Phantom points granted or to be burnedgranted pursuant to generate electricitythe Phantom Unit Plan I and Phantom Unit Plan II, which vest based on performance of the investment made by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively. |
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| Phantom points | | The class of interests to be issued under the Phantom Unit Plan I, and to be issued under the Phantom Unit Plan II, which represent or usedwill represent the opportunity to receive a cash payment when distributions of profit are made pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Phantom points are classified as a hardenereither phantom service points or phantom performance points. |
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| Phantom service points | | Phantom points granted or to be granted pursuant to the Phantom Unit Plan I and Phantom Unit Plan II, which vest based on service. |
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| Phantom Unit Plan I | | The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition LLC. |
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| Phantom Unit Plan II | | The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition II LLC. |
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| Profits interests | | Interests in concrete.the profits of Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, also referred to as “override units.” |
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| Rack sales | | Sales which are made into tanker truck (versus bulk pipeline batcher) via either a proprietary or third terminal facility designed for truck loading. |
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| Recordable incident | | An injury, as defined by OSHA. All work-related deaths and illnesses, and those work-related injuries which result in loss of consciousness, restriction of work or motion, transfer to another job, or require medical treatment beyond first aid. |
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| Recordable injury rate | | The number of recordable injuries per 200,000 hours rate worked. |
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| Refined products | | Hydrocarbon compounds,Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery. |
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| Refining margin | | A measurement calculated as the difference between net sales and cost of products sold (exclusive of depreciation and amortization). |
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| Reformer unit | | A refinery unit that processes naphtha and converts it to high-octane gasoline by using a platinum/rhenium catalyst. Also known as a platformer. |
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| Reformulated gasoline | | The composition andGasoline with compounds or properties of which meet the requirements of the reformulated gasoline regulations. |
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| Slag | | A glasslike substance removed from the gasifier containing the metal impurities originally present in the coke. |
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| Slurry | | A byproduct of the fluid catalytic cracking process that is sold for further processing or blending with fuel oil. |
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| Sour crude oil | | A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil. |
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| Spot market | | A market in which commodities are bought and sold for cash and delivered immediately. |
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| Sweet crude oil | | A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil. |
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| Syngas | | A mixture of gases (largely carbon monoxide and hydrogen) that results from heating coal in the presence of steam. |
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| Throughput | | The volume per day processed through a unit or a refinery. |
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| Ton | | One ton is equal to 2,000 pounds. |
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| Turnaround | | A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years. |
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| UAN | | UAN is a solution of urea and ammonium nitrate in water used as a fertilizer. |
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| Utilization | | Ratio of total refinery throughput to the rated capacity of the refinery. |
| | | |
| Vacuum unit | | Secondary refinery unit to process crude oil by separating product from the crude unit according to boiling point under high heat and low pressure to recover various hydrocarbons. |
| | | |
| Value units | | Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on performance of the investment made by Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, respectively. |
| | |
| Wheat belt | | The primary wheat producing region of the United States, which includes Oklahoma, Kansas, Texas, North Dakota, South Dakota and South Dakota.Texas. |
| | |
| WTI | | West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 3839 and 4041 and a sulfur content of approximately 0.30.4 weight percent that is used as a benchmark for other crude oils. |
| | | |
| WTS | | West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of 32-3330-32 degrees and a sulfur content of approximately 22.0 weight percent. |
| | | |
| Yield | | The percentage of refined products that is produced from crude and other feedstocks. |
167286
CVR Energy, Inc. and Subsidiaries
ENERGY, INC. AND SUBSIDIARIES
| | | | | |
Audited Consolidated Financial Statements: | | | | |
| | | F-2 | |
| 2007 | | | F-3 | |
| | | F-4 | |
| | | F-5 | |
| | | F-7 | |
| | | F-8 | |
Unaudited Condensed Consolidated Financial Statements:
| | | | |
| | | F-38 | |
| | | F-4 | |
Consolidated Statements of Changes in Stockholders’ Equity/Members’ Equity for the174-day period ended June 30,23, 2005, (Successor) (unaudited)for the233-day period ended December 31, 2005, and for the six monthsyears ended June 30,December 31, 2006 (Successor) (unaudited)and December 31, 2007 | | | F-39F-5 | |
| | | F-40 | |
| | | F-9 | |
| Notes to Consolidated Financial Statements | | | F-10 | |
Unaudited Condensed Consolidated Financial Statements: | | | | |
| Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007 (unaudited) | | | F-65 | |
Condensed Consolidated Statements of Operations for the three months ended March 31, 2008 (unaudited) and the sixthree months ended June 30, 2006 (Successor)March 31, 2007 (unaudited) | | | F-41F-66 | |
| | | F-67 | |
| Notes to Condensed Consolidated Financial Statements (unaudited) | | | F-42F-68 | |
EX-23.1: CONSENT OF KPMG LLP |
F-1
When the transaction referred to in note 1 of the notes to consolidated financial statements has been consummated, we will be in a position to render the following report:
/s/ KPMG LLPREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Report of Independent Registered Public Accounting Firm
The Board of Directors
CVR Energy, Inc.:
We have audited the accompanying consolidated balance sheets of CVR Energy, Inc. and subsidiaries (the Company), which collectively refers to the consolidated balance sheetSuccessor) as of December 31, 20042006 and 2007, and the related statements of operations, changes in stockholders’ equity/members’ equity, and cash flows for Coffeyville Group Holdings, LLC and subsidiaries, excluding Leiber Holdings, LLC, as discussed in note 1 to the consolidated financial statements (Immediate(the Predecessor), and the consolidated balance sheet as of December 31, 2005 of Coffeyville Acquisition LLC and subsidiaries (the Successor) and the related consolidated statements of operations, equity, and cash flows for the former Farmland Industries, Inc. (Farmland) Petroleum Division and one facility within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor) for the year ended December 31, 2003 and for the62-day period ended March 2, 2004 and for the Immediate Predecessor for the304-day period ended December 31, 2004 and for the174-day period ended June 23, 2005, and for the Successor for the233-day period ended December 31, 2005.2005 and for the years ended December 31, 2006 and 2007, as discussed in note 1 to the consolidated financial statements. These consolidated financial statements are the responsibility of the Company’sSuccessor’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the Standardsstandards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe our audits provide a reasonable basis for our opinion.
As discussed in note 2 to the consolidated financial statements, Farmland allocated certain general corporate expense and interest expense to the Original Predecessor for the year ended December 31, 2003 and for the62-day period ended March 2, 2004. The allocation of these costs is not necessarily indicative of the costs that would have been incurred if the Predecessor had operated as a stand-alone entity.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Immediate Predecessor as of December 31, 2004 and the Successor as of December 31, 20052006 and 2007, and the results of the Original Predecessor’s operations and its cash flows for the year ended December 31, 2003 and for the62-day period ended March 2, 2004 and the results of the Immediate Predecessor’s operations and cash flows for the304-day period ended December 31, 2004 and for the174-day period ended June 23, 2005 and the results of the Successor’s operations and its cash flows for the233-day period ended December 31, 2005 and for the years ended December 31, 2006 and 2007, in conformity with U.S. generally accepted accounting principles.
As discussed in note 1 to the consolidated financial statements, effective March 3, 2004, the Immediate Predecessor acquired the net assets of the Original Predecessor in a business combination accounted for as a purchase, and effective June 24, 2005, the Successor acquired the net assets of the Immediate Predecessor in a business combination accounted for as a purchase. As a result of these acquisitions,this acquisition, the consolidated financial statements for the periods after the acquisitionsacquisition are presented on a different cost basis than that for the periodsperiod before the acquisitionsacquisition and, therefore, are not comparable.
As discussed in note 2 to the consolidated financial statements, the Company has restated the accompanying consolidated financial statements as of and for the year ended December 31, 2007.
KPMG LLP
Kansas City, Missouri
April 24, 2006
March 28, 2008, except as to note 1,2, which is as of , 2006May 8, 2008
F-2
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
| | | | | | | | | | |
| | | Coffeyville Group
| | | | | | | | | | | | | |
| | | Holdings, LLC
| | | | Coffeyville
| | | December 31,
| | December 31,
| |
| | | Immediate
| | | | Acquisition LLC
| | | 2006 | | 2007 | |
| | | Predecessor | | | | Successor | | | (In thousands of dollars) | |
| | | December 31,
| | | | December 31,
| | | | | As restated(†) | |
| | | 2004 | | | | 2005 | |
ASSETS | | | | | | | | | | ASSETS |
| Current assets: | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 52,651,952 | | | | $ | 64,703,524 | | | $ | 41,919 | | | $ | 30,509 | |
| Accounts receivable, net of allowance for doubtful accounts of $190,468 and $275,188, respectively | | | 23,383,818 | | | | | 71,560,052 | | |
| Accounts receivable, net of allowance for doubtful accounts of $375 and $391, respectively | | | | 69,589 | | | | 86,546 | |
| Inventories | | | 80,422,506 | | | | | 154,275,818 | | | | 161,433 | | | | 254,655 | |
| Prepaid expenses and other current assets | | | 7,844,264 | | | | | 14,709,309 | | | | 18,525 | | | | 14,186 | |
| Insurance receivable | | | | — | | | | 73,860 | |
| Income tax receivable | | | | 32,099 | | | | 31,367 | |
| Deferred income taxes | | | 264,246 | | | | | 31,059,748 | | | | 18,889 | | | | 79,047 | |
| | | | | | | | | | | | | |
| Total current assets | | | 164,566,786 | | | | | 336,308,451 | | | | 342,454 | | | | 570,170 | |
| Property, plant, and equipment, net of accumulated depreciation | | | 50,005,847 | | | | | 772,512,884 | | | | 1,007,156 | | | | 1,192,174 | |
| Intangible assets | | | 79,824 | | | | | 1,008,547 | | |
| Intangible assets, net | | | | 638 | | | | 473 | |
| Goodwill | | | — | | | | | 83,774,885 | | | | 83,775 | | | | 83,775 | |
| Deferred financing costs | | | 7,206,653 | | | | | 19,524,839 | | |
| Deferred financing costs, net | | | | 9,128 | | | | 7,515 | |
| Insurance receivable | | | | — | | | | 11,400 | |
| Other long-term assets | | | 6,946,793 | | | | | 8,418,297 | | | | 6,329 | | | | 2,849 | |
| Deferred income taxes | | | 351,434 | | | | | — | | |
| | | | | | | | | | | | | |
| Total assets | | $ | 229,157,337 | | | | $ | 1,221,547,903 | | | $ | 1,449,480 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
| | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | LIABILITIES AND EQUITY |
| Current liabilities: | | | | | | | | | | | | | | | | | |
| Current portion of long-term debt | | $ | 1,500,000 | | | | $ | 2,235,973 | | | $ | 5,798 | | | $ | 4,874 | |
| Revolving debt | | | 56,510 | | | | | — | | |
| Note payable and capital lease obligations | | | | — | | | | 11,640 | |
| Payable to swap counterparty | | | | 36,895 | | | | 262,415 | |
| Accounts payable | | | 31,059,282 | | | | | 87,914,833 | | | | 138,911 | | | | 182,225 | |
| Personnel accruals | | | 6,591,495 | | | | | 10,796,896 | | | | 24,731 | | | | 36,659 | |
| Accrued taxes other than income taxes | | | 2,652,948 | | | | | 4,841,234 | | | | 9,035 | | | | 14,732 | |
| Accrued income taxes | | | 1,301,160 | | | | | 4,939,614 | | |
| Payable to swap counterparty | | | — | | | | | 96,688,956 | | |
| Deferred revenue | | | 11,119,905 | | | | | 12,029,987 | | | | 8,812 | | | | 13,161 | |
| Other current liabilities | | | 3,723,057 | | | | | 8,831,937 | | | | 6,019 | | | | 33,820 | |
| | | | | | | | | | | | | |
| Total current liabilities | | | 58,004,357 | | | | | 228,279,430 | | | | 230,201 | | | | 559,526 | |
| Long-term liabilities: | | | | | | | | | | | | | | | | | |
| Long-term debt, less current portion | | | 147,375,000 | | | | | 497,201,527 | | | | 769,202 | | | | 484,328 | |
| Accrued environmental liabilities | | | 9,100,937 | | | | | 7,009,388 | | | | 5,395 | | | | 4,844 | |
| Deferred income taxes | | | — | | | | | 209,523,747 | | | | 284,123 | | | | 286,986 | |
| Other long-term liabilities | | | | — | | | | 1,122 | |
| Payable to swap counterparty | | | — | | | | | 160,033,333 | | | | 72,806 | | | | 88,230 | |
| Other long-term liabilities | | | 592,881 | | | | | — | | |
| | | | | | | | | | | | | |
| Total long-term liabilities | | | 157,068,818 | | | | | 873,767,995 | | | | 1,131,526 | | | | 865,510 | |
| Management voting common units subject to redemption | | | — | | | | | 4,172,350 | | |
| Less: note receivable from management unitholder | | | — | | | | | (500,000 | ) | |
| Commitments and contingencies | | | | | | | | | |
| Minority interest in subsidiaries | | | | 4,326 | | | | 10,600 | |
| Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006 | | | | 6,981 | | | | — | |
| Stockholders’ equity/members’ equity | | | | | | | | | |
| Voting common units, 22,614,937 units issued and outstanding in 2006 | | | | 73,593 | | | | — | |
| Management nonvoting override units, 2,976,353 units issued and outstanding in 2006 | | | | 2,853 | | | | — | |
| Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding | | | | — | | | | 861 | |
Additionalpaid-in-capital | | | | — | | | | 458,359 | |
| Retained deficit | | | | — | | | | (26,500 | ) |
| | | | | | | | | | | | | |
| Total management voting common units subject to redemption, net | | | — | | | | | 3,672,350 | | |
| Members’ equity: | | | | | | | | | | |
| Voting preferred units | | | 10,485,160 | | | | | — | | |
| Non-voting common units | | | 7,584,993 | | | | | — | | |
| Unearned compensation | | | (3,985,991 | ) | | | | — | | |
| Voting common units | | | — | | | | | 114,830,560 | | |
| Management nonvoting override units | | | — | | | | | 997,568 | | |
| Total stockholders’ equity/members’ equity | | | | 76,446 | | | | 432,720 | |
| | | | | | | | | | | | | |
| Total members’ equity | | | 14,084,162 | | | | | 115,828,128 | | |
| Commitments and contingencies | | | | | | | | | | |
| Total liabilities and stockholders’ equity/members’ equity | | | $ | 1,449,480 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
| Total liabilities and equity | | $ | 229,157,337 | | | | $ | 1,221,547,903 | | |
| | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-3
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Coffeyville
| |
| | | Farmland Industries, Inc.
| | | | Coffeyville Group Holdings, LLC
| | | | Acquisition LLC
| |
| | | Original Predecessor | | | | Immediate Predecessor | | | | Successor | |
| | | Year Ended
| | | 62 Days Ended
| | | | 304 Days Ended
| | | 174 Days Ended
| | | | 233 Days Ended
| |
| | | December 31,
| | | March 2,
| | | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2003 | | | 2004 | | | | 2004 | | | 2005 | | | | 2005 | |
| Net sales | | $ | 1,262,196,894 | | | $ | 261,086,529 | | | | $ | 1,479,893,189 | | | $ | 980,706,261 | | | | $ | 1,454,259,542 | |
| Cost of goods sold | | | 1,198,332,922 | | | | 245,234,642 | | | | | 1,363,369,459 | | | | 850,037,564 | | | | | 1,277,217,863 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Gross profit | | | 63,863,972 | | | | 15,851,887 | | | | | 116,523,730 | | | | 130,668,697 | | | | | 177,041,679 | |
| Operating expenses: | | | | | | | | | | | | | | | | | | | | | | |
| Selling, general and administrative expenses | | | 23,617,264 | | | | 4,649,145 | | | | | 16,552,393 | | | | 18,413,003 | | | | | 18,506,617 | |
| Reorganization expenses: | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of property, plant and equipment | | | 9,638,626 | | | | — | | | | | — | | | | — | | | | | — | |
| Rejection of executory contracts | | | 1,250,000 | | | | — | | | | | — | | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total operating expenses | | | 34,505,890 | | | | 4,649,145 | | | | | 16,552,393 | | | | 18,413,003 | | | | | 18,506,617 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating income | | | 29,358,082 | | | | 11,202,742 | | | | | 99,971,337 | | | | 112,255,694 | | | | | 158,535,062 | |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | | | |
| Interest expense | | | (1,281,513 | ) | | | — | | | | | (10,058,450 | ) | | | (7,801,821 | ) | | | | (25,007,159 | ) |
| Interest income | | | — | | | | — | | | | | 169,652 | | | | 511,687 | | | | | 972,264 | |
| Gain (loss) on derivatives | | | 303,742 | | | | — | | | | | 546,604 | | | | (7,664,725 | ) | | | | (316,062,111 | ) |
| Loss on extinguishment of debt | | | — | | | | — | | | | | (7,166,110 | ) | | | (8,093,754 | ) | | | | — | |
| Other income (expense) | | | (458,514 | ) | | | 9,345 | | | | | 52,659 | | | | (762,616 | ) | | | | (563,190 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | (1,436,285 | ) | | | 9,345 | | | | | (16,455,645 | ) | | | (23,811,229 | ) | | | | (340,660,196 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Income (loss) before provision for income taxes | | | 27,921,797 | | | | 11,212,087 | | | | | 83,515,692 | | | | 88,444,465 | | | | | (182,125,134 | ) |
| Income tax expense (benefit) | | | — | | | | — | | | | | 33,805,480 | | | | 36,047,516 | | | | | (62,968,044 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 27,921,797 | | | $ | 11,212,087 | | | | $ | 49,710,212 | | | $ | 52,396,949 | | | | $ | (119,157,090 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 1) | | | | | | | | | | | | | | | | | | | | | | |
| Basic and diluted earnings per common share | | | | | | | | | | | | | | | | | | | | $ | — | |
| Basic and diluted weighted average common shares outstanding | | | | | | | | | | | | | | | | | | | | | — | |
| | | | | | | | | | | | | | | | | | |
| | | Immediate Predecesssor | | | | Successor | |
| | | 174 Days Ended
| | | | 233 Days Ended
| | | Year Ended
| | | Year Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| | | (in thousands except share amounts) | |
| | | | | | | | | | | | | As restated(†) | |
| Net sales | | $ | 980,706 | | | | $ | 1,454,260 | | | $ | 3,037,567 | | | $ | 2,966,865 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 768,067 | | | | | 1,168,137 | | | | 2,443,374 | | | | 2,308,740 | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | 80,914 | | | | | 85,313 | | | | 198,980 | | | | 276,138 | |
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | | | 18,342 | | | | | 18,320 | | | | 62,600 | | | | 93,122 | |
| Net costs associated with flood | | | — | | | | | — | | | | — | | | | 41,523 | |
| Depreciation and amortization | | | 1,128 | | | | | 23,954 | | | | 51,005 | | | | 60,779 | |
| | | | | | | | | | | | | | | | | | |
| Total operating costs and expenses | | | 868,451 | | | | | 1,295,724 | | | | 2,755,959 | | | | 2,780,302 | |
| | | | | | | | | | | | | | | | | | |
| Operating income | | | 112,255 | | | | | 158,536 | | | | 281,608 | | | | 186,563 | |
| Other income (expense): | | | | | | | | | | | | | | | | | |
| Interest expense and other financing costs | | | (7,802 | ) | | | | (25,007 | ) | | | (43,880 | ) | | | (61,126 | ) |
| Interest income | | | 512 | | | | | 972 | | | | 3,450 | | | | 1,100 | |
| Gain (loss) on derivatives | | | (7,665 | ) | | | | (316,062 | ) | | | 94,493 | | | | (281,978 | ) |
| Loss on extinguishment of debt | | | (8,094 | ) | | | | — | | | | (23,360 | ) | | | (1,258 | ) |
| Other income (expense) | | | (761 | ) | | | | (564 | ) | | | (900 | ) | | | 356 | |
| | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | (23,810 | ) | | | | (340,661 | ) | | | 29,803 | | | | (342,906 | ) |
| | | | | | | | | | | | | | | | | | |
| Income (loss) before income taxes and minority interest in subsidiaries | | | 88,445 | | | | | (182,125 | ) | | | 311,411 | | | | (156,343 | ) |
| Income tax expense (benefit) | | | 36,048 | | | | | (62,968 | ) | | | 119,840 | | | | (88,515 | ) |
| Minority interest in loss of subsidiaries | | | — | | | | | — | | | | — | | | | 210 | |
| | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 52,397 | | | | $ | (119,157 | ) | | $ | 191,571 | | | $ | (67,618 | ) |
| | | | | | | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 13) | | | | | | | | | | | | | | | | | |
| Net earnings (loss) per share | | | | | | | | | | | | | | | | | |
| Basic | | | | | | | | | | | $ | 2.22 | | | $ | (0.78 | ) |
| Diluted | | | | | | | | | | | $ | 2.22 | | | $ | (0.78 | ) |
| Weighted average common shares outstanding: | | | | | | | | | | | | | | | | | |
| Basic | | | | | | | | | | | | 86,141,291 | | | | 86,141,291 | |
| Diluted | | | | | | | | | | | | 86,158,791 | | | | 86,141,291 | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-4
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
| | | | | | | | | | | | | | | | | | | | | |
| | | Divisional
| | | Voting
| | | Nonvoting
| | | Unearned
| | | | |
| | | Equity | | | Preferred | | | Common | | | Compensation | | | Total | |
| |
Original Predecessor | | | | | | | | | | | | | | | | | | | | |
For the year ended December 31, 2003 and the 62 days ended March 2, 2004 | | | | | | | | | | | | | | | | | | | | |
| Balance, January 1, 2003 | | $ | 49,773,605 | | | $ | — | | | $ | — | | | $ | — | | | $ | 49,773,605 | |
| Net income | | | 27,921,797 | | | | — | | | | — | | | | — | | | | 27,921,797 | |
| Net distribution to Farmland Industries, Inc. | | | (19,503,913 | ) | | | — | | | | — | | | | — | | | | (19,503,913 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, December 31, 2003 | | | 58,191,489 | | | | — | | | | — | | | | — | | | | 58,191,489 | |
| Net income | | | 11,212,087 | | | | — | | | | — | | | | — | | | | 11,212,087 | |
| Net distribution to Farmland Industries, Inc. | | | (53,216,357 | ) | | | — | | | | — | | | | — | | | | (53,216,357 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance, March 2, 2004 | | $ | 16,187,219 | | | $ | — | | | $ | — | | | $ | — | | | $ | 16,187,219 | |
| | | | | | | | | | | | | | | | | | | | | |
Immediate Predecessor | | | | | | | | | | | | | | | | | | | | |
For the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005 | | | | | | | | | | | | | | | | | | | | |
| Members’ Equity, March 3, 2004 | | $ | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Issuance of 63,200,000 preferred units for cash | | | — | | | | 63,200,000 | | | | — | | | | — | | | | 63,200,000 | |
| Issuance of 11,152,941 common units to management for recourse promissory notes and unearned compensation | | | — | | | | — | | | | 3,100,000 | | | | (3,037,000 | ) | | | 63,000 | |
| Issuance of 500,000 common units to management for recourse promissory notes and unearned compensation | | | — | | | | — | | | | 2,047,450 | | | | (2,044,600 | ) | | | 2,850 | |
| Recognition of earned compensation expense related to common units | | | — | | | | — | | | | — | | | | 1,095,609 | | | | 1,095,609 | |
| Dividends on preferred units ($1.50 per unit) | | | — | | | | (94,686,276 | ) | | | — | | | | — | | | | (94,686,276 | ) |
| Dividends to management on common units ($0.48 per unit) | | | — | | | | — | | | | (5,301,233 | ) | | | — | | | | (5,301,233 | ) |
| Net income | | | — | | | | 41,971,436 | | | | 7,738,776 | | | | — | | | | 49,710,212 | |
| | | | | | | | | | | | | | | | | | | | | |
| Members’ Equity, December 31, 2004 | | | — | | | | 10,485,160 | | | | 7,584,993 | | | | (3,985,991 | ) | | | 14,084,162 | |
| Recognition of earned compensation expense related to common units | | | — | | | | — | | | | — | | | | 3,985,991 | | | | 3,985,991 | |
| Contributed capital | | | — | | | | 728,724 | | | | — | | | | — | | | | 728,724 | |
| Dividends on preferred units ($0.70 per unit) | | | — | | | | (44,083,323 | ) | | | — | | | | — | | | | (44,083,323 | ) |
| Dividends to management on common units ($0.70 per unit) | | | — | | | | — | | | | (8,128,170 | ) | | | — | | | | (8,128,170 | ) |
| Net income | | | — | | | | 44,239,908 | | | | 8,157,041 | | | | — | | | | 52,396,949 | |
| | | | | | | | | | | | | | | | | | | | | |
| Members’ Equity, June 23, 2005 | | $ | — | | | $ | 11,370,469 | | | $ | 7,613,864 | | | $ | — | | | $ | 18,984,333 | |
| | | | | | | | | | | | | | | | | | | | | |
F-5
CVR Energy, Inc. and SubsidiariesStockholders’ Equity/Members’ Equity
CONSOLIDATED STATEMENTS OF EQUITY — (Continued)
| | | | | | | | | | | | | |
| | | Management Voting Common
| | | Note Receivable from
| | | | |
| | | Units Subject to Redemption | | | Management Unit Holder | | | Total | |
| |
Successor | | | | | | | | | | | | |
For the 233 days ended December 31, 2005 | | | | | | | | | | | | |
| Balance at May 13, 2005 | | $ | — | | | $ | — | | | $ | — | |
| Issuance of 177,500 common units for cash | | | 1,775,000 | | | | — | | | | 1,775,000 | |
| Issuance of 50,000 common units for note receivable | | | 500,000 | | | | (500,000 | ) | | | — | |
| Adjustment to fair value for management common units | | | 3,035,586 | | | | — | | | | 3,035,586 | |
| Net loss allocated to management common units | | | (1,138,236 | ) | | | — | | | | (1,138,236 | ) |
| | | | | | | | | | | | | |
| Balance at December 31, 2005 | | $ | 4,172,350 | | | $ | (500,000 | ) | | $ | 3,672,350 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | Management
| | | | |
| | | Voting
| | | Management
| | | Nonvoting
| | | | |
| | | Common
| | | Nonvoting Override
| | | Override
| | | | |
| | | Units | | | Operating Units | | | Value Units | | | Total | |
| |
For the 233 days ended December 31, 2005 | | | | | | | | | | | | | | | | |
| Balance at May 13, 2005 | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Issuance of 23,588,500 common units for cash | | | 235,885,000 | | | | — | | | | — | | | | 235,885,000 | |
| Issuance of 919,630 nonvested operating override units | | | — | | | | — | | | | — | | | | — | |
| Issuance of 1,839,265 nonvested value override units | | | — | | | | — | | | | — | | | | — | |
| Recognition of share-based compensation expense related to override units | | | — | | | | 602,381 | | | | 395,187 | | | | 997,568 | |
| Adjustment to fair value for management common units | | | (3,035,586 | ) | | | — | | | | — | | | | (3,035,586 | ) |
| Net loss allocated to management common units | | | (118,018,854 | ) | | | — | | | | — | | | | (118,018,854 | ) |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | $ | 114,830,560 | | | $ | 602,381 | | | $ | 395,187 | | | $ | 115,828,128 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Voting
| | | Nonvoting
| | | Unearned
| | | | |
| | | Preferred | | | Common | | | Compensation | | | Total | |
| | | (in thousands of dollars) | |
| |
Immediate Predecessor | | | | | | | | | | | | | | | | |
| Members’ Equity, December 31, 2004 | | $ | 10,485 | | | $ | 7,585 | | | $ | (3,986 | ) | | $ | 14,084 | |
| Recognition of earned compensation expense related to common units | | | — | | | | — | | | | 3,986 | | | | 3,986 | |
| Contributed capital | | | 728 | | | | — | | | | — | | | | 728 | |
| Dividends on preferred units ($0.70 per unit) | �� | | (44,083 | ) | | | — | | | | — | | | | (44,083 | ) |
| Dividends to management on common units ($0.70 per unit) | | | — | | | | (8,128 | ) | | | — | | | | (8,128 | ) |
| Net income | | | 44,240 | | | | 8,157 | | | | — | | | | 52,397 | |
| | | | | | | | | | | | | | | | | |
| Members’ Equity, June 23, 2005 | | $ | 11,370 | | | $ | 7,614 | | | $ | — | | | $ | 18,984 | |
| | | | | | | | | | | | | | | | | |
See accompanying notes to consolidated financial statements.
F-6
F-5
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
Stockholders’ Equity/Members’ Equity — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | Coffeyville Group
| | | | Coffeyville
| |
| | | Farmland Industries, Inc.
| | | | Holdings, LLC
| | | | Acquisition LLC
| |
| | | Original Predecessor | | | | Immediate Predecessor | | | | Successor | |
| | | Year Ended
| | | 62 Days Ended
| | | | 304 Days Ended
| | | 174 Days Ended
| | | | 233 Days Ended
| |
| | | December 31,
| | | March 2,
| | | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2003 | | | 2004 | | | | 2004 | | | 2005 | | | | 2005 | |
| Cash flows from operating activities: | | | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 27,921,797 | | | $ | 11,212,087 | | | | $ | 49,710,212 | | | $ | 52,396,949 | | | | $ | (119,157,090 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 3,313,526 | | | | 432,003 | | | | | 2,445,961 | | | | 1,128,005 | | | | | 23,954,031 | |
| Provision for doubtful accounts | | | — | | | | — | | | | | 190,468 | | | | (190,468 | ) | | | | 275,189 | |
| Amortization of deferred financing costs | | | — | | | | — | | | | | 1,332,890 | | | | 812,166 | | | | | 1,751,041 | |
| Loss on extinguishment of debt | | | — | | | | — | | | | | 7,166,110 | | | | 8,093,754 | | | | | — | |
| Reorganization expenses — impairment of property, plant, and equipment | | | 9,638,626 | | | | — | | | | | — | | | | — | | | | | — | |
| Share-based compensation | | | — | | | | — | | | | | 1,095,609 | | | | 3,985,991 | | | | | 997,568 | |
| Changes in assets and liabilities, net of effect of acquisition: | | | | | | | | | | | | | | | | | | | | | | |
| Accounts receivable | | | (25,301,358 | ) | | | 19,635,303 | | | | | (23,571,436 | ) | | | (11,334,177 | ) | | | | (34,506,244 | ) |
| Inventories | | | 10,371,108 | | | | (6,399,677 | ) | | | | 20,068,625 | | | | (59,045,550 | ) | | | | 1,895,473 | |
| Prepaid expenses and other current assets | | | (23,806,340 | ) | | | 25,716,107 | | | | | (6,758,666 | ) | | | (937,543 | ) | | | | (6,491,633 | ) |
| Other long-term assets | | | (90,733 | ) | | | 715,132 | | | | | (5,379,727 | ) | | | 3,036,659 | | | | | (4,651,733 | ) |
| Accounts payable | | | 8,347,575 | | | | (6,759,702 | ) | | | | 31,059,282 | | | | 16,124,794 | | | | | 40,655,763 | |
| Accrued income taxes | | | — | | | | — | | | | | 1,301,160 | | | | 4,503,574 | | | | | (136,398 | ) |
| Deferred revenue | | | 1,545,894 | | | | 8,319,913 | | | | | 1,209,008 | | | | (9,073,050 | ) | | | | 9,983,132 | |
| Other current liabilities | | | 419,415 | | | | 364,555 | | | | | 12,967,500 | | | | 1,254,196 | | | | | 10,499,712 | |
| Payable to swap counterparty | | | — | | | | — | | | | | — | | | | — | | | | | 256,722,289 | |
| Accrued environmental liabilities | | | 7,958,165 | | | | (20,057 | ) | | | | (1,746,043 | ) | | | (1,553,184 | ) | | | | (538,365 | ) |
| Other long-term liabilities | | | — | | | | — | | | | | (689,372 | ) | | | (297,105 | ) | | | | (295,776 | ) |
| Deferred income taxes | | | — | | | | — | | | | | (615,680 | ) | | | 3,803,937 | | | | | (98,424,817 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 20,317,675 | | | | 53,215,664 | | | | | 89,785,901 | | | | 12,708,948 | | | | | 82,532,142 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | | | | | | | | | | |
| Cash paid for acquisition of Original Predecessor | | | — | | | | — | | | | | (116,599,329 | ) | | | — | | | | | — | |
| Cash paid for acquisition of Immediate Predecessor, net of cash acquired | | | — | | | | — | | | | | — | | | | — | | | | | (685,125,669 | ) |
| Capital expenditures | | | (813,762 | ) | | | — | | | | | (14,160,280 | ) | | | (12,256,793 | ) | | | | (45,172,134 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net cash used in investing activities | | | (813,762 | ) | | | — | | | | | (130,759,609 | ) | | | (12,256,793 | ) | | | | (730,297,803 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | | | | | | | | | | |
| Revolving debt payments | | | — | | | | — | | | | | (57,686,789 | ) | | | (343,449 | ) | | | | (69,286,016 | ) |
| Revolving debt borrowings | | | — | | | | — | | | | | 57,743,299 | | | | 492,308 | | | | | 69,286,016 | |
| Proceeds from issuance of long-term debt | | | — | | | | — | | | | | 171,900,000 | | | | — | | | | | 500,000,000 | |
| Principal payments on long-term debt | | | — | | | | — | | | | | (23,025,000 | ) | | | (375,000 | ) | | | | (562,500 | ) |
| Repayment of capital lease obligation | | | — | | | | — | | | | | (1,176,424 | ) | | | — | | | | | — | |
| Net divisional equity distribution | | | (19,503,913 | ) | | | (53,216,357 | ) | | | | — | | | | — | | | | | — | |
| Payment of deferred financing costs | | | — | | | | — | | | | | (16,309,917 | ) | | | — | | | | | (24,628,315 | ) |
| Prepayment penalty on extinguishment of debt | | | — | | | | — | | | | | (1,095,000 | ) | | | — | | | | | — | |
| Issuance of members’ equity | | | — | | | | — | | | | | 63,263,000 | | | | — | | | | | 237,660,000 | |
| Distribution of members’ equity | | | — | | | | — | | | | | (99,987,509 | ) | | | (52,211,493 | ) | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | (19,503,913 | ) | | | (53,216,357 | ) | | | | 93,625,660 | | | | (52,437,634 | ) | | | | 712,469,185 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | — | | | | (693 | ) | | | | 52,651,952 | | | | (51,985,479 | ) | | | | 64,703,524 | |
| Cash and cash equivalents, beginning of period | | | 2,250 | | | | 2,250 | | | | | — | | | | 52,651,952 | | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 2,250 | | | $ | 1,557 | | | | $ | 52,651,952 | | | $ | 666,473 | | | | $ | 64,703,524 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Supplemental disclosures | | | | | | | | | | | | | | | | | | | | | | |
| Cash paid for income taxes | | $ | — | | | $ | — | | | | $ | 33,820,000 | | | $ | 27,040,000 | | | | $ | 35,593,172 | |
| Cash paid for interest | | $ | — | | | $ | — | | | | $ | 8,570,069 | | | $ | 7,287,351 | | | | $ | 23,578,178 | |
| Non-cash financing activities: | | | | | | | | | | | | | | | | | | | | | | |
| Contributed capital through Leiber tax savings | | $ | — | | | $ | — | | | | $ | — | | | $ | 728,724 | | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | Management Voting
| | | Note Receivable
| | | | |
| | | Common Units
| | | from Management
| | | | |
| | | Subject to Redemption | | | Unit Holder
| | | Total
| |
| | | Units | | | Dollars | | | Dollars | | | Dollars | |
| | | (in thousands of dollars except share amounts) | |
| |
Successor | | | | | | | | | | | | | | | | |
For the 233 days ended December 31, 2005, and the year ended December 31, 2006 | | | | | | | | | | | | | | | | |
| Balance at May 13, 2005 | | | — | | | $ | — | | | $ | — | | | $ | — | |
| Issuance of 177,500 common units for cash | | | 177,500 | | | | 1,775 | | | | — | | | | 1,775 | |
| Issuance of 50,000 common units for note receivable | | | 50,000 | | | | 500 | | | | (500 | ) | | | — | |
| Adjustment to fair value for management common units | | | — | | | | 3,035 | | | | — | | | | 3,035 | |
| Net loss allocated to management common units | | | — | | | | (1,138 | ) | | | — | | | | (1,138 | ) |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 227,500 | | | | 4,172 | | | | (500 | ) | | | 3,672 | |
| Payment of note receivable | | | — | | | | — | | | | 150 | | | | 150 | |
| Forgiveness of note receivable | | | — | | | | — | | | | 350 | | | | 350 | |
| Adjustment to fair value for management common units | | | — | | | | 4,240 | | | | — | | | | 4,240 | |
| Prorata reduction of management common units outstanding | | | (26,437 | ) | | | — | | | | — | | | | — | |
| Distributions to management on common units | | | — | | | | (3,119 | ) | | | — | | | | (3,119 | ) |
| Net income allocated to management common units | | | — | | | | 1,688 | | | | — | | | | 1,688 | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 201,063 | | | | 6,981 | | | | — | | | | 6,981 | |
| Adjustment to fair value for management common units, as restated(†) | | | — | | | | 2,037 | | | | — | | | | 2,037 | |
| Net loss allocated to management common units, as restated(†) | | | — | | | | (362 | ) | | | — | | | | (362 | ) |
| Change from partnership to corporate reporting structure | | | (201,063 | ) | | | (8,656 | ) | | | — | | | | (8,656 | ) |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | | — | | | $ | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-6
CVR ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in
Stockholders’ Equity/Members’ Equity — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Management
| | | Management
| | | | |
| | | | | | | | | Nonvoting Override
| | | Nonvoting Override
| | | | |
| | | Voting Common Units | | | Operating Units | | | Value Units | | | Total
| |
| | | Units | | | Dollars | | | Units | | | Dollars | | | Units | | | Dollars | | | Dollars | |
| | | (in thousands of dollars except share amounts) | |
| |
For the 233 days ended December 31, 2005, and the year ended December 31, 2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at May 13, 2005 | | | — | | | $ | — | | | | — | | | $ | — | | | | — | | | $ | — | | | $ | — | |
| Issuance of 23,588,500 common units for cash | | | 23,588,500 | | | | 235,885 | | | | — | | | | — | | | | — | | | | — | | | | 235,885 | |
| Issuance of 919,630 nonvested operating override units | | | — | | | | — | | | | 919,630 | | | | — | | | | — | | | | — | | | | — | |
| Issuance of 1,839,265 nonvested value override units | | | — | | | | — | | | | — | | | | — | | | | 1,839,265 | | | | — | | | | — | |
| Recognition of share-based compensation expense related to override units | | | — | | | | — | | | | — | | | | 603 | | | | — | | | | 395 | | | | 998 | |
| Adjustment to fair value for management common units | | | — | | | | (3,035 | ) | | | — | | | | — | | | | — | | | | — | | | | (3,035 | ) |
| Net loss allocated to common units | | | — | | | | (118,019 | ) | | | — | | | | — | | | | — | | | | — | | | | (118,019 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 23,588,500 | | | | 114,831 | | | | 919,630 | | | | 603 | | | | 1,839,265 | | | | 395 | | | | 115,829 | |
| Issuance of 2,000,000 common units for cash | | | 2,000,000 | | | | 20,000 | | | | — | | | | — | | | | — | | | | — | | | | 20,000 | |
| Recognition of share-based compensation expense related to override units | | | — | | | | — | | | | — | | | | 1,160 | | | | — | | | | 695 | | | | 1,855 | |
| Adjustment to fair value for management common units | | | — | | | | (4,240 | ) | | | — | | | | — | | | | — | | | | — | | | | (4,240 | ) |
| Prorata reduction of common units outstanding | | | (2,973,563 | ) | | | — | | | | — | | | | — | | | | — | | | | — | | | | — | |
| Issuance of 72,492 nonvested operating override units | | | — | | | | — | | | | 72,492 | | | | — | | | | — | | | | — | | | | — | |
| Issuance of 144,966 nonvested value override units | | | — | | | | — | | | | — | | | | — | | | | 144,966 | | | | — | | | | — | |
| Distributions to common unit holders | | | — | | | | (246,881 | ) | | | — | | | | — | | | | — | | | | — | | | | (246,881 | ) |
| Net income allocated to common units | | | — | | | | 189,883 | | | | — | | | | — | | | | — | | | | — | | | | 189,883 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2006 | | | 22,614,937 | | | | 73,593 | | | | 992,122 | | | | 1,763 | | | | 1,984,231 | | | | 1,090 | | | | 76,446 | |
| Recognition of share-based compensation expense related to override units | | | — | | | | — | | | | — | | | | 1,018 | | | | — | | | | 701 | | | | 1,719 | |
| Adjustment to fair value for management common units, as restated(†) | | | — | | | | (2,037 | ) | | | — | | | | — | | | | — | | | | — | | | | (2,037 | ) |
| Adjustment to fair value for minority interest | | | — | | | | (1,053 | ) | | | — | | | | — | | | | — | | | | — | | | | (1,053 | ) |
| Reversal of minority interest fair value adjustments upon redemption of the minority interest | | | — | | | | 1,053 | | | | — | | | | — | | | | — | | | | — | | | | 1,053 | |
| Net loss allocated to common units, as restated(†) | | | — | | | | (40,756 | ) | | | — | | | | — | | | | — | | | | — | | | | (40,756 | ) |
| Change from partnership to corporate reporting structure, as restated(†) | | | (22,614,937 | ) | | | (30,800 | ) | | | (992,122 | ) | | | (2,781 | ) | | | (1,984,231 | ) | | | (1,791 | ) | | | (35,372 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007 | | | — | | | $ | — | | | | — | | | $ | — | | | | — | | | $ | — | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-7
CVR ENERGY, INC. AND SUBSIDIARIES
Consolidated Statements of Changes in
Stockholders’ Equity/Members’ Equity — (Continued)
| | | | | | | | | | | | | | | | | | | | | |
| | | Common Stock | | | Additional
| | | | | | | |
| | | Shares
| | | | | | Paid-In
| | | Retained
| | | | |
| | | Issued | | | Amount | | | Capital | | | Deficit | | | Total | |
| | | (in thousands of dollars except share amounts) | |
| |
Balance at January 1, 2007 | | | — | | | $ | — | | | $ | — | | | $ | — | | | $ | — | |
| Change from partnership to corporate reporting structure, as restated(†) | | | 62,866,720 | | | | 629 | | | | 43,398 | | | | — | | | | 44,027 | |
| Issuance of common stock in exchange for minority interest of related party | | | 247,471 | | | | 2 | | | | 4,700 | | | | — | | | | 4,702 | |
| Cash dividend declared | | | — | | | | — | | | | (10,600 | ) | | | — | | | | (10,600 | ) |
| Public offering of common stock, net of stock issuance costs of $39,873,655 | | | 22,917,300 | | | | 229 | | | | 395,326 | | | | — | | | | 395,555 | |
| Purchase of common stock by employees through share purchase program | | | 82,700 | | | | 1 | | | | 1,570 | | | | — | | | | 1,571 | |
| Share-based compensation | | | — | | | | — | | | | 23,400 | | | | — | | | | 23,400 | |
| Issuance of common stock to employees | | | 27,100 | | | | — | | | | 565 | | | | — | | | | 565 | |
| Net loss, as restated(†) | | | — | | | | — | | | | — | | | | (26,500 | ) | | | (26,500 | ) |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2007, as restated(†) | | | 86,141,291 | | | $ | 861 | | | $ | 458,359 | | | $ | (26,500 | ) | | $ | 432,720 | |
| | | | | | | | | | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-8
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSConsolidated Statements of Cash Flows
| | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | | | | | | | | |
| | | Predecessor | | | | Successor | |
| | | 174 Days Ended
| | | | 233 Days Ended
| | | Year Ended
| | | Year Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| | | | | | | | | | | | | As restated(†) | |
| | | (in thousands of dollars) | |
| Cash flows from operating activities: | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 52,397 | | | | $ | (119,157 | ) | | $ | 191,571 | | | $ | (67,618 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | 1,128 | | | | | 23,954 | | | | 51,005 | | | | 68,406 | |
| Provision for doubtful accounts | | | (190 | ) | | | | 276 | | | | 100 | | | | 15 | |
| Amortization of deferred financing costs | | | 812 | | | | | 1,751 | | | | 3,337 | | | | 2,778 | |
| Loss on disposition of fixed assets | | | — | | | | | — | | | | 1,188 | | | | 1,273 | |
| Loss on extinguishment of debt | | | 8,094 | | | | | — | | | | 23,360 | | | | 1,258 | |
| Forgiveness of note receivable | | | — | | | | | — | | | | 350 | | | | — | |
| Share-based compensation | | | 3,986 | | | | | 1,093 | | | | 16,905 | | | | 44,083 | |
| Minority interest in loss of subsidiaries | | | — | | | | | — | | | | — | | | | (210 | ) |
| Changes in assets and liabilities, net of effect of acquisition: | | | | | | | | | | | | | | | | | |
| Accounts receivable | | | (11,335 | ) | | | | (34,507 | ) | | | 1,871 | | | | (16,972 | ) |
| Inventories | | | (59,045 | ) | | | | 1,895 | | | | (7,157 | ) | | | (84,980 | ) |
| Prepaid expenses and other current assets | | | (939 | ) | | | | (6,492 | ) | | | (5,384 | ) | | | 4,848 | |
| Insurance receivable | | | — | | | | | — | | | | — | | | | (105,260 | ) |
| Insurance proceeds for flood | | | — | | | | | — | | | | — | | | | 20,000 | |
| Other long-term assets | | | 3,036 | | | | | (4,651 | ) | | | 1,971 | | | | 3,245 | |
| Accounts payable | | | 16,125 | | | | | 40,656 | | | | 5,005 | | | | 59,110 | |
| Accrued income taxes | | | 4,504 | | | | | (136 | ) | | | (37,039 | ) | | | 732 | |
| Deferred revenue | | | (9,073 | ) | | | | 9,983 | | | | (3,218 | ) | | | 4,349 | |
| Other current liabilities | | | 1,255 | | | | | 10,405 | | | | 4,592 | | | | 27,027 | |
| Payable to swap counterparty | | | — | | | | | 256,722 | | | | (147,021 | ) | | | 240,944 | |
| Accrued environmental liabilities | | | (1,553 | ) | | | | (539 | ) | | | (1,614 | ) | | | (551 | ) |
| Other long-term liabilities | | | (297 | ) | | | | (296 | ) | | | — | | | | 1,122 | |
| Deferred income taxes | | | 3,804 | | | | | (98,425 | ) | | | 86,770 | | | | (57,684 | ) |
| | | | | | | | | | | | | | | | | | |
| Net cash provided by operating activities | | | 12,709 | | | | | 82,532 | | | | 186,592 | | | | 145,915 | |
| | | | | | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | | | | | |
| Cash paid for acquisition of Immediate Predecessor, net of cash acquired | | | — | | | | | (685,126 | ) | | | — | | | | — | |
| Capital expenditures | | | (12,257 | ) | | | | (45,172 | ) | | | (240,225 | ) | | | (268,593 | ) |
| | | | | | | | | | | | | | | | | | |
| Net cash used in investing activities | | | (12,257 | ) | | | | (730,298 | ) | | | (240,225 | ) | | | (268,593 | ) |
| | | | | | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | | | | | |
| Revolving debt payments | | | (343 | ) | | | | (69,286 | ) | | | (900 | ) | | | (345,800 | ) |
| Revolving debt borrowings | | | 492 | | | | | 69,286 | | | | 900 | | | | 345,800 | |
| Proceeds from issuance of long-term debt | | | — | | | | | 500,000 | | | | 805,000 | | | | 50,000 | |
| Principal payments on long-term debt | | | (375 | ) | | | | (562 | ) | | | (529,438 | ) | | | (335,797 | ) |
| Payment of financing costs | | | — | | | | | (24,628 | ) | | | (9,364 | ) | | | (2,491 | ) |
| Prepayment penalty on extinguishment of debt | | | — | | | | | — | | | | (5,500 | ) | | | — | |
| Payment of note receivable | | | — | | | | | — | | | | 150 | | | | — | |
| Issuance of members’ equity | | | — | | | | | 237,660 | | | | 20,000 | | | | — | |
| Net proceeds from sale of common stock | | | — | | | | | — | | | | — | | | | 399,556 | |
| Distribution of members’ equity | | | (52,211 | ) | | | | — | | | | (250,000 | ) | | | (10,600 | ) |
| Sale of managing general partnership interest | | | — | | | | | — | | | | — | | | | 10,600 | |
| | | | | | | | | | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | (52,437 | ) | | | | 712,470 | | | | 30,848 | | | | 111,268 | |
| | | | | | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (51,985 | ) | | | | 64,704 | | | | (22,785 | ) | | | (11,410 | ) |
| Cash and cash equivalents, beginning of period | | | 52,652 | | | | | — | | | | 64,704 | | | | 41,919 | |
| | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 667 | | | | $ | 64,704 | | | $ | 41,919 | | | $ | 30,509 | |
| | | | | | | | | | | | | | | | | | |
| Supplemental disclosures | | | | | | | | | | | | | | | | | |
| Cash paid for income taxes, net of refunds (received) | | $ | 27,040 | | | | $ | 35,593 | | | $ | 70,109 | | | $ | (31,563 | ) |
| Cash paid for interest | | $ | 7,287 | | | | $ | 23,578 | | | $ | 51,854 | | | $ | 56,886 | |
| Non-cash investing and financing activities: | | | | | | | | | | | | | | | | | |
Step-up in basis in property for exchange of common stock for minority interest, net of deferred taxes of $389 | | $ | — | | | | $ | — | | | $ | — | | | $ | 586 | |
| Accrual of construction in progress additions | | $ | — | | | | $ | — | | | $ | 45,991 | | | $ | (15,268 | ) |
| Contributed capital through Leiber tax savings | | $ | 729 | | | | $ | — | | | $ | — | | | $ | — | |
| Notes payable and capital lease obligations for insurance and inventory | | $ | — | | | | $ | — | | | $ | — | | | $ | 11,640 | |
| | |
| † | | See Note 2 to consolidated financial statements. |
See accompanying notes to consolidated financial statements.
F-9
CVR ENERGY, INC. AND SUBSIDIARIES
| |
| (1) | Organization and History of the Company |
GeneralOrganization
The “Company” or “CVR” may be used to refer to CVR Energy, Inc. (CVR) was incorporated in Delaware in September 2006. CVR has assumed that concurrent with this offering,and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a newly formed direct subsidiary of CVR’s will merge with Coffeyville Refining & Marketing, Inc. (CRM) and a separate newly formed direct subsidiary of CVR’s will merge with Coffeyville Nitrogen Fertilizers, Inc. (CNF) which will make CRM and CNF directly owned subsidiaries of CVR.
Earnings per share is calculated on a pro forma basis, based on an assumed number of shares outstanding at the timedate prior to October 16, 2007 (the date of the initial public offering with respect to the existing shares. Pro forma earnings per share assumes that in conjunction with the initial public offering, the two direct wholly owned subsidiaries of Successor will merge with two of CVR’s direct wholly owned subsidiaries, CVR will effect a -for- stock split prior to completion of this offering, and CVR will issue shares of common stockrestructuring as further discussed in this offering. No effect has been givenNote) and subsequent to any shares that might be issued in this offering pursuantJune 24, 2005 are to the exercise by the underwriters of their option.
Successor is a Delaware limited liability company formed May 13, 2005. Successor, acting through wholly-owned subsidiaries, is an independent petroleum refinerCoffeyville Acquisition LLC (CALLC) and marketer in the mid-continental United States and a producer and marketer of upgraded nitrogen fertilizer products in North America.its subsidiaries.
On June 24, 2005, SuccessorCALLC acquired all of the outstanding stock of Coffeyville Refining & Marketing, Inc. (CRM); Coffeyville Nitrogen Fertilizer,Fertilizers, Inc. (CNF); Coffeyville Crude Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and Coffeyville Terminal, Inc. (CT) (collectively, CRIncs) from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). As a result of this transaction, CRIncs ownership increased tocollectively own 100% of CL JV Holdings, LLC (CLJV), a Delaware limited liability company formed on September 27, 2004. CRIncs and, directly and indirectly,or through CLJV, they collectively own 100% of Coffeyville Resources, LLC (CRLLC) and its wholly owned subsidiaries, Coffeyville Resources Refining & Marketing, LLC (CRRM); Coffeyville Resources Nitrogen Fertilizers, LLC (CRNF); Coffeyville Resources Crude Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC (CRP); and Coffeyville Resources Terminal, LLC (CRT).
The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer in the mid-continental United States and a producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. CALLC formed Coffeyville Refining & Marketing Holdings, Inc. (Refining Holdco) as a wholly owned subsidiary, incorporated in Delaware in August 2007, by contributing its shares of CRM to Refining Holdco in exchange for its shares. Refining Holdco was formed in connection with a financing transaction in August 2007. The initial public offering of CVR was consummated on October 26, 2007. In conjunction with the initial public offering, a restructuring occurred in which CVR became a direct or indirect owner of all of the subsidiaries of CALLC. Additionally, in connection with the initial public offering, CALLC was split into two entities: Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (CALLC II).
Initial Public Offering of CVR Energy, Inc.
On October 26, 2007, CVR Energy, Inc. completed an initial public offering of 23,000,000 shares of its common stock. The initial public offering price was $19.00 per share.
The net proceeds to CVR from the initial public offering were approximately $408.5 million, after deducting underwriting discounts and commissions, but before deduction of offering expenses. The Company also incurred approximately $11.4 million of other costs related to the initial public offering. The net proceeds from this offering were used to repay $280 million of term debt under the Company’s credit facility and to repay all indebtedness under the Company’s $25 million unsecured facility and $25 million secured facility, including related accrued interest through the date of repayment of approximately $5.9 million. Additionally, $50 million of net proceeds were used to repay outstanding indebtedness under the revolving loan facility under the Company’s credit facility. In connection with the repayment of the $25 million unsecured facility and the $25 million secured facility, the Company recorded a write-off of unamortized deferred financing fees of approximately $1.3 million in the fourth quarter of 2007.
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 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
F-10
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
officer received 247,471 shares of CVR common stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully vested and were exchanged at fair market value.
The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in connection with the initial public offering. The compensation expense recorded in the fourth quarter of 2007 was $565,000 related to shares issued. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, which does not include the non-vested shares issued noted below.
On October 24, 2007, 17,500 shares of non-vested stock having a fair value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights on these shares from the date of grant. The fair value of each share of restricted stock was measured based on the market price of the common stock as of the date of grant and will be amortized over the respective vesting periods. One-third of the restricted stock will vest on October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on October 24, 2010. Additionally, options to purchase 10,300 common shares at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. These awards will vest over a three year service period. Fair value was measured using an option-pricing model at the date of grant.
Nitrogen Fertilizer Limited Partnership
In conjunction with the consummation of CVR’s initial public offering, CVR transferred CRNF, its nitrogen fertilizer business, to a newly created limited partnership (Partnership) in exchange for a managing general partner interest (managing GP interest), a special general partner interest (special GP interest, represented by special GP units) and a de minimis limited partner interest (LP interest, represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to an entity owned by its controlling stockholders and senior management at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing general partner interest was $10.6 million. This interest has been reflected as minority interest in the consolidated balance sheet at December 31, 2007.
The valuation of the managing general partner interest was based on a discounted cash flow analysis, using a discount rate commensurate with the risk profile of the managing general partner interest. The key assumptions underlying the analysis were commodity price projections, which were used to determine the Partnership’s raw material costs and output revenues. Other business expenses of the Partnership were based on management’s projections. The Partnership’s cash distributions were assumed to be flat at expected forward fertilizer prices, with cash reserves developed in periods of high prices and cash reserves reduced in periods of lower prices. The Partnership’s projected cash flows due to the managing general partner under the terms of the Partnership’s partnership agreement used for the valuation were modeled based on the structure of expectations of the Partnership’s operations, including production volumes and operating costs, which were developed by management based on historical operations and experience. Price projections were based on information received from Blue, Johnson & Associates, a leading fertilizer industry consultant in the United States which CVR routinely uses for fertilizer market analysis.
In conjunction with CVR Energy’s indirect ownership of the special GP interest, it initially owned all of the interests in the Partnership (other than the managing general partner interest and the IDRs) and initially was entitled to all cash distributed by the Partnership. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership
F-11
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the amended and restated partnership agreement, generated by the Partnership during the period from the completion of the Partnership’s initial public offering of its common units representing limited partner interests (Partnership Offering) through December 31, 2009 has been distributed in respect of the GP units and subordinated GP units, which CVR Energy will indirectly hold following completion of the Partnership Offering, and the Partnership’s common units (which will be issued in connection with the Partnership Offering) and any other partnership interests that are issued in the future. The Partnership and its subsidiaries are currently guarantors under CRLLC’s credit facility.
The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR the Partnership and the managing general partner also entered into a number of agreements to regulate certain business relations between the partners.
At December 31, 2007, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing general partner interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing general partner interest and the IDRs.
On February 28, 2008, the Partnership filed a registration statement with the SEC to effect the contemplated initial public offering of its common units representing limited partner interests. The registration statement provided that upon consummation of the Partnership’s initial public offering, CVR will indirectly own the Partnership’s special general partner and approximately 87% of the outstanding units of the Partnership. There can be no assurance that any such offering will be consummated on the terms described in the registration statement or at all. The offering is under review by the Securities and Exchange Commission (SEC) and as a result the terms and resulting structure disclosed below could be materially different.
In connection with the Partnership’s initial public offering, CRLLC will contribute all of its special LP units to the Partnership’s special general partner and all of the Partnership’s special general partner interests and special limited partner interests will be converted into a combination of GP and subordinated GP units. Following the initial public offering, the Partnership will have five types of partnership interest outstanding:
| | |
| • | 5,250,000 common units representing limited partner interests, all of which the Partnership will sell in the initial public offering; |
|
| • | 18,750,000 GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner; |
|
| • | 18,000,000 subordinated GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner; |
|
| • | incentive distribution rights representing limited partner interests, all of which will be held by the Partnership’s managing general partner; and |
F-12
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| | |
| • | a managing general partner interest, which is not entitled to any distributions, which is held by the Partnership’s managing general partner. |
Effective with the Partnerships’ initial public offering, the partnership agreement will require that the Partnership distribute all of its cash on hand at the end of each quarter, less reserves established by its managing general partner, subject to the sustainability requirement in the event the Partnership elects to increase the quarterly distribution amount. The amount of available cash may be greater or less than the aggregate amount necessary to make the minimum quarterly distribution on all common units, GP units and subordinated units.
Subsequent to the initial public offering, the Partnership will make minimum quarterly distributions of $0.375 per common unit ($1.50 per common unit on an annualized basis) to the extent the Partnership has sufficient available cash. In general, cash distributions will be made each quarter as follows:
| | |
| • | First, to the holders of common units and GP units until each common unit and GP unit has received a minimum quarterly distribution of $0.375 plus any arrearages from prior quarters; |
|
| • | Second, to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.375; and |
|
| • | Third, to all unitholders, pro rata, until each unit has received a quarterly distribution of $0.4313. |
If cash distributions exceed $0.4313 per unit in a quarter, the Partnership’s managing general partner, as holder of the IDRs, will receive increasing percentages, up to 48%, of the cash the Partnership distributes in excess of $0.4313 per unit. However, the managing general partner will not be entitled to receive any distributions in respect of the IDRs until the Partnership has made cash distributions in an aggregate amount equal to the Partnership’s adjusted operating surplus generated during the period from the closing of the initial public offering until December 31, 2009.
During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units and GP units have received the minimum quarterly distribution of $0.375 per unit plus any arrearages from prior quarters. The subordination period will end once the Partnership meets the financial tests in the partnership agreement.
If the Partnership meets the financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after the first quarter whose first day begins at least three years following the closing of the Partnership Offering, 25% of the subordinated GP units will convert into GP units on a one-for-one basis. If the Partnership meets these financial tests for any three consecutive four-quarter periods ending on or after the first quarter whose first day begins at least four years following the closing of the Partnership Offering, an additional 25% of the subordinated GP units will convert into GP units on a one-for-one basis. The early conversion of the second 25% of the subordinated GP units may not occur until at least one year following the end of the last four-quarter period in respect of which the first 25% of the subordinated GP units were converted. If the subordinated GP units have converted into subordinated LP units at the time the financial tests are met they will convert into common units, rather than GP units. In addition, the subordination period will end if the managing general partner is removed as the managing general partner where “cause” (as defined in the partnership agreement) does not exist and no units held by the managing general partner and its affiliates are voted in favor of that removal.
When the subordination period ends, all subordinated units will convert into GP units or common units on a one-for-one basis, and the common units and GP units will no longer be entitled to arrearages.
F-13
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
The partnership agreement authorizes the Partnership to issue an unlimited number of additional units and rights to buy units for the consideration and on the terms and conditions determined by the managing general partner without the approval of the unitholders.
The Partnership will distribute all cash received by it or its subsidiaries in respect of accounts receivable existing as of the closing of the initial public offering exclusively to its special general partner.
The managing general partner, together with the special general partner, manages and operates the Partnership. Common unitholders will only have limited voting rights on matters affecting the Partnership. In addition, common unitholders will have no right to elect either of the general partners or the managing general partner’s directors on an annual or other continuing basis.
If at any time the managing general partner and its affiliates own more than 80% of the common units, the managing general partner will have the right, but not the obligation, to purchase all of the remaining common units at a purchase price equal to the greater of (x) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (y) the highestper-unit price paid by the managing general partner or any of its affiliates for common units during the90-day period preceding the date such notice is first mailed.
Successor and Immediate Predecessor
Successor refers collectively to both CVR Energy, Inc. and CALLC. CALLC was formed as a Delaware limited liability company on May 13, 2005. On June 24, 2005, CALLC acquired all of the outstanding stock of CRIncs from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). As a result of this transaction, CRIncs ownership increased to 100% of CLJV, a Delaware limited liability company formed on September 27, 2004. CRIncs directly and indirectly, through CLJV, collectively own 100% of CRLLC and its wholly owned subsidiaries, CRRM; CRNF; CRCT; CRP; and CRT.
CALLC had no financial statement activity during the period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil, and gasoline option agreements entered into with a related party (see notes 14Notes 16 and 15)17) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 233 days ended December 31, 2005.
Immediate Predecessor was a Delaware limited liability company formed in October 2003. There was no financial statement activity until March 3, 2004, when Immediate Predecessor, acting through wholly owned subsidiaries, acquired the assets of the former Farmland Industries, Inc. (Farmland) Petroleum Division and one facility located in Coffeyville, Kansas within Farmland’s eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division (collectively, Original Predecessor) (the Initial Acquisition). As of March 3, 2004, Immediate Predecessor owned 100% of CRIncs, and CRIncs owned 100% of CRLLC and its wholly owned subsidiaries, CRRM, CRNF, CRCT, CRP, and CRT. Farmland was a farm supply cooperative and a processing and marketing cooperative. Original Predecessor operated as a division of Farmland (Petroleum), and as a plant within a division of Farmland (Nitrogen Fertilizer). The accompanying Original Predecessor financial statements principally reflect the refining, crude oil gathering, and petroleum distribution operations of Farmland and the only coke gasification plant of Farmland’s nitrogen fertilizer operations.
F-8
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Since the assets and liabilities of Successor and Immediate Predecessor (collectively, CVR) were each presented on a new basis of accounting, the financial information for Successor and Immediate Predecessor, and Original Predecessor (collectively, the Entities) is not comparable.
On October 8, 2004, Immediate Predecessor, acting through its wholly owned subsidiaries, CRM and CNF, contributed 68.7% of its membership in CRLLC to CLJV, in exchange for a controlling interest in CLJV. Concurrently, The Leiber Group, Inc., a company whose majority stockholder iswas Pegasus Partners II, L.P., the Immediate Predecessor’s principal stockholder, contributed to CLJV its
F-14
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
interest in the Judith Leiber business, which is a designer handbag business, in exchange for a minority interest in CLJV. The Judith Leiber business iswas at the time owned through Leiber Holdings, LLC (LH), a Delaware limited liability company wholly owned at the time by CLJV. Based on the relative values of the properties at the time of contribution to CLJV, CRM and CNF collectively, were entitled to 80.5% of CLJV’s net profits and net losses. Under the terms of CRLLC’s credit agreement, CRLLC was permitted to make tax distributions to its members, including CLJV, in amounts equal to the tax liability that would be incurred by CRLLC if its net income were subject to corporate-level income tax. From the tax distributions CLJV received from CRLLC as of December 31, 2004 and June 23, 2005, CLJV contributed $1,600,000 and $4,050,000, respectively, to LH which is presented as tax expense in the respective periods in the accompanying consolidated statements of operations for the reasons discussed below.
On June 23, 2005, as part of the stock purchase agreement, LH completed a merger with Leiber Merger, LLC, a wholly owned subsidiary of The Leiber Group, Inc. As a result of the merger, the surviving entity was LH. Under the terms of the agreement, CLJV forfeited all of its ownership in LH to The Leiber Group, Inc in exchange for LH’s interest in CLJV. The result of this transaction was to effectively redistribute the contributed businesses back to The Leiber Group, Inc.
The operations of LH and its subsidiaries (collectively, Leiber) have not been included in the accompanying consolidated financial statements of the Immediate Predecessor because Leiber’s operations were unrelated to, and are not part of, the ongoing operations of CVR. CLJV’s management was not the same as the Immediate Predecessor’s, the Successor’s, or CVR’s, there were no intercompany transactions between CLJV and the Immediate Predecessor, the Successor, or CVR, aside from the contributions, and the Immediate Predecessor only participated in the joint venture for a short period of time. CLJV’s contributions to LH of $1,600,000 and $4,050,000 have been reflected as a reduction to accrued income taxes in the accompanying consolidated balance sheets to appropriately reflect the accrued income tax obligations of Immediate Predecessor as of December 31, 2004 and June 23, 2005, respectively. The tax benefits received from LH, as a result of losses incurred by LH, have been reflected as capital contributions in the accompanying consolidated financial statements of the Immediate Predecessor.
Farmland Industries, Inc.’s Bankruptcy Proceedings and the Initial Acquisition
On May 31, 2002 (the Petition Date), Farmland Industries, Inc. and four of its subsidiaries, Farmland Foods, Inc.; Farmland Pipeline Company, Inc.; Farmland Transportation, Inc.; and SFA, Inc. (collectively, the Debtors or Farmland), filed voluntary petitions for protection under Chapter 11 of the United States Bankruptcy Code (the Bankruptcy Code) in the United States Bankruptcy Court, Western District of Missouri (the Court). Petroleum and Nitrogen Fertilizer were divisions of Farmland; therefore, their assets and liabilities were included in the bankruptcy filings. Farmland continued to manage the business asdebtor-in-possession but could not engage in transactions outside the ordinary course of business without the approval of the Court.
As a result of the filing on May 31, 2002 of petitions under Chapter 11 of the Bankruptcy Code by the Debtors, the accompanying Original Predecessor’s financial statements have been prepared in
F-9F-15
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
accordance with AICPA Statement of Position (SOP) 90-7,Financial Reporting by Entities in Reorganization Under the Bankruptcy Code, and in accordance with accounting principles generally accepted in the United States of America applicable to a going concern, which, unless otherwise noted, assume the realization of assets and the payment of liabilities in the ordinary course of business.
Asdebtors-in-possession, the Debtors, subject to any required Court approval, may elect to assume or reject real estate leases, employment contracts, personal property leases, service contracts, and other unexpired executory pre-petition contracts. Damages related to rejected contracts are a pre-petition claim. The Petroleum Segment had no material accruals for any damages as of December 31, 2003. The Nitrogen Fertilizer Segment rejected an operating and maintenance agreement with a vendor resulting in an accrual of approximately $1,250,000 as of December 31, 2003 which was charged to reorganization expenses in the year ending December 31, 2003.
Pursuant to the provisions of the Bankruptcy Code, on November 27, 2002 the Debtors filed with the Court a Plan of Reorganization under which the Debtors’ liabilities and equity interests would be restructured. Subsequently, on July 31, 2003, the Debtors filed with the Court an Amended Plan of Reorganization (the Amended Plan). The Amended Plan as filed in effect contemplated that the Debtors would continue in existence solely for the purpose of liquidating any remaining assets of the estate, including the Petroleum and Nitrogen Fertilizer segments. In accordance with the Amended Plan, on October 10, 2003, the Court entered an order approving the auction and bid procedures for the sale of the Petroleum Division and Coffeyville nitrogen fertilizer plant to subsidiaries of Immediate Predecessor. Through an auction process conducted by the Court, the assets of Original Predecessor were sold on March 3, 2004, to Immediate Predecessor for $106,727,365, including the assumption of $23,216,554 of liabilities. Immediate Predecessor also paid transaction costs of $9,871,964, which consisted of legal, accounting, and advisory fees of $7,371,964 paid to various parties and a finder’s fee of $2,500,000 paid to Pegasus Capital Advisors, L.P. (see note 15). Immediate Predecessor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Initial Acquisition was financed through long-term borrowings of approximately $60.7 million and the issuance of preferred units of approximately $63.2 million. The allocation of the purchase price at March 3, 2004, the date of the Initial Acquisition, was as follows:
| | | | | |
| Assets acquired | | | | |
| Inventories | | $ | 100,491,131 | |
| Prepaid expenses and other current assets | | | 1,085,598 | |
| Property, plant, and equipment | | | 38,239,154 | |
| | | | | |
| Total assets acquired | | $ | 139,815,883 | |
| | | | | |
| Liabilities assumed | | | | |
| Deferred revenue | | $ | 9,910,897 | |
| Capital lease obligations | | | 1,176,424 | |
| Accrued environmental liabilities | | | 10,846,980 | |
| Other long-term liabilities | | | 1,282,253 | |
| | | | | |
| Total liabilities assumed | | $ | 23,216,554 | |
| | | | | |
| Cash paid for acquisition of Original Predecessor | | $ | 116,599,329 | |
| | | | | |
The SubsequentSuccessor Acquisition
On May 15, 2005, Successor and Immediate Predecessor entered into an agreement whereby Successor acquired 100% of the outstanding stock of CRIncs with an effective date of June 24, 2005
F-10
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
for $673,273,440,$673,273,000, including the assumption of $353,084,637$353,085,000 of liabilities. Successor also paid transaction costs of $12,518,702,$12,519,000, which consisted of legal, accounting, and advisory fees of $5,782,740$5,783,000 paid to various parties, and transaction fees of $6,000,000 and $735,962$736,000 in expenses related to the acquisition paid to institutional investors (see note 15)Note 17). Successor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Subsequent Acquisition was financed through long-term borrowings of approximately $500 million, short-term borrowings of approximately $12.6 million, and the issuance of common units for approximately $227.7 million. The allocation of the purchase price at June 24, 2005, the date of the Subsequent Acquisition, is as follows:
| | | | | | | | | |
| Assets acquired | | | | | | | | |
| Cash | | $ | 666,473 | | | $ | 667,000 | |
| Accounts receivable | | | 37,328,997 | | | | 37,329,000 | |
| Inventories | | | 156,171,291 | | | | 156,171,000 | |
| Prepaid expenses and other current assets | | | 4,865,241 | | | | 4,865,000 | |
| Intangibles, contractual agreements | | | 1,322,000 | | | | 1,322,000 | |
| Goodwill | | | 83,774,885 | | | | 83,775,000 | |
| Other long-term assets | | | 3,837,647 | | | | 3,838,000 | |
| Property, plant, and equipment | | | 750,910,245 | | | | 750,910,000 | |
| | | | | | | |
| Total assets acquired | | $ | 1,038,876,779 | | | $ | 1,038,877,000 | |
| | | | | | | |
| Liabilities assumed | | | | | | | | |
| Accounts payable | | $ | 47,259,070 | | | $ | 47,259,000 | |
| Other current liabilities | | | 16,017,210 | | | | 16,017,000 | |
| Current income taxes | | | 5,076,012 | | | | 5,076,000 | |
| Deferred income taxes | | | 276,888,816 | | | | 276,889,000 | |
| Other long-term liabilities | | | 7,843,529 | | | | 7,844,000 | |
| | | | | | | |
| Total liabilities assumed | | $ | 353,084,637 | | | $ | 353,085,000 | |
| | | | | | | |
| Cash paid for acquisition of Immediate Predecessor | | $ | 685,792,142 | | | $ | 685,792,000 | |
| | | | | | | |
Pro forma revenue would be unchanged for the periods presented. Unaudited pro forma net income (loss) as if the Subsequent Acquisition and related debt refinancing had occurred as of the beginning of each period presented compared to historical net income (loss) presented below is as follows (in thousands):
| | | | | | | | | |
| | | Historical | | Pro Forma |
| | | (non-GAAP) | | |
| |
| Year ended December 31, 2005 | | $ | (66,760 | )(1) | | $ | (82,898 | ) |
| Year ended December 31, 2004 | | $ | 60,922 | (2) | | $ | 20,730 | |
| | |
(1) | | Reflects the sum of the results of operations for the periods ended June 23, 2005 and December 31, 2005. |
|
(2) | | Reflects the sum of the results of operations for the periods ended March 2, 2004 and December 31, 2004. |
| |
| (2) | BasisRestatement of PresentationFinancial Statements |
The accompanying Original Predecessor(A) On April 23, 2008, the Audit Committee of the Board of Directors and management of the Company concluded that the Company’s previously issued consolidated financial statements reflectfor the year ended December 31, 2007 and the related quarter ended September 30, 2007 contained errors. The Company arrived at this conclusion during the course of its closing process and review for the quarter ended March 31, 2008. The restatement principally relates to errors in the calculation of the cost of crude oil purchased by the Company and associated financial transactions.
For the year ended December 31, 2007, net loss increased by $10.8 million, from $56.8 million to $67.6 million. This increase in net loss is the result of an allocationincrease in cost of certain general corporate expensesproduct sold (exclusive of Farmland, including generaldepreciation and corporate insurance, corporateamortization) of $17.7 million, with an associated increase in income tax benefit of $6.9 million.
Due to the restatement, inventories for the year ended December 31, 2007 increased by $5.4 million and accounts payable increased by $23.1 million. Income tax receivable increased by $6.1 million and current deferred income tax asset increased by $0.8 million.
F-11F-16
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
The effect of the above adjustments on the consolidated financial statements is set forth in the tables in 2(B) below. The restatement had no effect on net cash flows from operating, investing or financing activities as shown in the Consolidated Statements of Cash Flows. The restatement did not have any impact on the Company’s covenant compliance under its debt facilities or its cash position as of December 31, 2007.
(B) Notes 5, 11, 13, 15, 17, 18, 19 and 20 have been restated to reflect the adjustments described above.
F-17
retirement and benefits, human resources and payroll department salaries, facility costs, information services, and information systems support. Those costs allocatedCVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
The following is a summary of the Original Predecessor were $12,709,178 and $3,802,996impact of the restatement described in Note 2(A) on the Company’s Consolidated Balance Sheet as of December 31, 2007:
| | | | | | | | | | | | | |
| | | December 31, 2007 | |
| | | Previously
| | | | | | As
| |
| | | Reported | | | Adjustment | | | Restated | |
| |
Assets |
| Consolidated Balance Sheet | | | | | | | | | | | | |
| Current assets: | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 30,509 | | | $ | — | | | $ | 30,509 | |
| Accounts receivable, net of allowance for doubtful accounts of $375 and $391, respectively | | | 86,546 | | | | — | | | | 86,546 | |
| Inventories | | | 249,243 | | | | 5,412 | | | | 254,655 | |
| Prepaid expenses and other current assets | | | 14,186 | | | | — | | | | 14,186 | |
| Insurance receivable | | | 73,860 | | | | — | | | | 73,860 | |
| Income tax receivable | | | 25,273 | | | | 6,094 | | | | 31,367 | |
| Deferred income taxes | | | 78,265 | | | | 782 | | | | 79,047 | |
| | | | | | | | | | | | | |
| Total current assets | | | 557,882 | | | | 12,288 | | | | 570,170 | |
| Property, plant, and equipment, net of accumulated depreciation | | | 1,192,174 | | | | — | | | | 1,192,174 | |
| Intangible assets, net | | | 473 | | | | — | | | | 473 | |
| Goodwill | | | 83,775 | | | | — | | | | 83,775 | |
| Deferred financing costs, net | | | 7,515 | | | | — | | | | 7,515 | |
| Insurance receivable | | | 11,400 | | | | — | | | | 11,400 | |
| Other long-term assets | | | 2,849 | | | | — | | | | 2,849 | |
| | | | | | | | | | | | | |
| Total assets | | $ | 1,856,068 | | | $ | 12,288 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
Liabilities and Equity |
| Current liabilities: | | | | | | | | | | | | |
| Current portion of long-term debt | | $ | 4,874 | | | | — | | | | 4,874 | |
| Note payable and capital lease obligations | | | 11,640 | | | | — | | | | 11,640 | |
| Payable to swap counterparty | | | 262,415 | | | | — | | | | 262,415 | |
| Accounts payable | | | 159,142 | | | | 23,083 | | | | 182,225 | |
| Personnel accruals | | | 36,659 | | | | — | | | | 36,659 | |
| Accrued taxes other than income taxes | | | 14,732 | | | | — | | | | 14,732 | |
| Deferred revenue | | | 13,161 | | | | — | | | | 13,161 | |
| Other current liabilities | | | 33,820 | | | | — | | | | 33,820 | |
| | | | | | | | | | | | | |
| Total current liabilities | | | 536,443 | | | | 23,083 | | | | 559,526 | |
| Long-term liabilities: | | | | | | | | | | | | |
| Long-term debt, less current portion | | | 484,328 | | | | — | | | | 484,328 | |
| Accrued environmental liabilities | | | 4,844 | | | | — | | | | 4,844 | |
| Deferred income taxes | | | 286,986 | | | | — | | | | 286,986 | |
| Other long-term liabilities | | | 1,122 | | | | — | | | | 1,122 | |
| Payable to swap counterparty | | | 88,230 | | | | — | | | | 88,230 | |
| | | | | | | | | | | | | |
| Total long-term liabilities | | | 865,510 | | | | — | | | | 865,510 | |
| Commitments and contingencies | | | — | | | | | | | | — | |
| Minority interest in subsidiaries | | | 10,600 | | | | — | | | | 10,600 | |
| Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006 | | �� | — | | | | — | | | | — | |
| Stockholders’ equity/members’ equity | | | | | | | | | | | | |
| Voting common units, 22,614,937 units issued and outstanding in 2006 | | | — | | | | — | | | | — | |
Management nonvoting override units, 2,976,353 units issued and
outstanding in 2006 | | | — | | | | — | | | | — | |
| Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding | | | 861 | | | | — | | | | 861 | |
Additionalpaid-in-capital | | | 460,551 | | | | (2,192 | ) | | | 458,359 | |
| Retained deficit | | | (17,897 | ) | | | (8,603 | ) | | | (26,500 | ) |
| | | | | | | | | | | | | |
| Total stockholders’ equity/members’ equity | | | 443,515 | | | | (10,795 | ) | | | 432,720 | |
| | | | | | | | | | | | | |
| Total liabilities and stockholders’ equity/members’ equity | | $ | 1,856,068 | | | $ | 12,288 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
F-18
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
The following is a summary of the impact of the restatement described in Note 2(A) above on the Company’s Consolidated Statements of Operations for the year ended December 31, 2003 and the62-day period ended March 2, 2004, respectively, and are included in selling, general, and administrative expenses. These allocations were based on a variety of factors dependent on the nature of the costs, including fixed asset levels, administrative headcount, and production headcount. The Petroleum Division and Coffeyville nitrogen plant represented a continually increasing percentage of Farmland’s business as a result of Farmland’s restructuring efforts, which by December 2003 included the disposition of nearly all Farmland’s operating assets with the exception of the Petroleum Division and Coffeyville nitrogen plant. As a result, the Petroleum Division and Coffeyville nitrogen plant were allocated a higher percentage of corporate cost in the 62 day period ending on March 2, 2004 than in 2003. The costs of these services are not necessarily indicative of the costs that would have been incurred if Original Predecessor had operated as a stand-alone entity. Reorganization expenses for legal and professional fees incurred by Farmland in connection with the bankruptcy proceedings were not allocated to the Original Predecessor. In addition, umbrella property insurance premiums were allocated across Farmland’s divisions based on recoverable values. Property insurance costs allocated to the Original Predecessor were $2,060,532 and $357,324 for the year ended December 31, 2003 and the62-day period ended March 2, 2004, respectively, and are included in cost of goods sold. All interest expense on secured borrowings was allocated based on identifiable net assets of each of Farmland’s divisions. Under bankruptcy law, payment of interest on Farmland’s unsecured debt was stayed beginning on the Petition Date. Accordingly, Farmland did not allocate any interest on its unsecured borrowings to the Original Predecessor for the 62 days ended March 2, 2004. Management believes all allocations described above were made on a reasonable basis.2007:
| | | | | | | | | | | | | |
| | | December 31, 2007 | |
| | | Previously
| | | | | | | |
| | | Reported | | | Adjustment | | | As Restated | |
| |
| Net sales | | $ | 2,966,865 | | | $ | — | | | $ | 2,966,865 | |
| Operating costs and expenses: | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 2,291,069 | | | | 17,671 | | | | 2,308,740 | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | 276,138 | | | | — | | | | 276,138 | |
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | | | 93,122 | | | | — | | | | 93,122 | |
| Net costs associated with flood | | | 41,523 | | | | — | | | | 41,523 | |
| Depreciation and amortization | | | 60,779 | | | | — | | | | 60,779 | |
| | | | | | | | | | | | | |
| Total operating costs and expenses | | | 2,762,631 | | | | 17,671 | | | | 2,780,302 | |
| | | | | | | | | | | | | |
| Operating income | | | 204,234 | | | | (17,671 | ) | | | 186,563 | |
| Other income (expense): | | | | | | | | | | | | |
| Interest expense and other financing costs | | | (61,126 | ) | | | — | | | | (61,126 | ) |
| Interest income | | | 1,100 | | | | — | | | | 1,100 | |
| Gain (loss) on derivatives | | | (281,978 | ) | | | — | | | | (281,978 | ) |
| Loss on extinguishment of debt | | | (1,258 | ) | | | — | | | | (1,258 | ) |
| Other income (expense) | | | 356 | | | | — | | | | 356 | |
| | | | | | | | | | | | | |
| Total other income (expense) | | | (342,906 | ) | | | — | | | | (342,906 | ) |
| Income (loss) before income taxes and minority interest in subsidiaries | | | (138,672 | ) | | | (17,671 | ) | | | (156,343 | ) |
| | | | | | | | | | | | | |
| Income tax expense (benefit) | | | (81,639 | ) | | | (6,876 | ) | | | (88,515 | ) |
| Minority interest in loss of subsidiaries | | | 210 | | | | — | | | | 210 | |
| | | | | | | | | | | | | |
| Net income (loss) | | $ | (56,823 | ) | | $ | (10,795 | ) | | $ | (67,618 | ) |
| | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 13) | | | | | | | | | | | | |
| Net earnings (loss) per share | | | | | | | | | | | | |
| Basic | | $ | (0.66 | ) | | $ | (0.12 | ) | | $ | (0.78 | ) |
| Diluted | | $ | (0.66 | ) | | $ | (0.12 | ) | | $ | (0.78 | ) |
| Weighted average common shares outstanding: | | | | | | | | | | | | |
| Basic | | | 86,141,291 | | | | | | | | 86,141,291 | |
| Diluted | | | 86,141,291 | | | | | | | | 86,141,291 | |
Farmland used a centralized approach to cash management and the financing of its operations. As a result, amounts owed to or by Farmland are reflected as a component of divisional equity on the accompanying consolidated statements of equity. Farmland’s divisional equity represents the net investment Farmland had in the reporting entity.
| |
| (3) | Summary of Significant Accounting Policies |
Principles of Consolidation
The accompanying CVR consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interest of minority investors in its subsidiaries are recorded as minority interest. All significant intercompany balancesaccounts and transactions have been eliminated in consolidation.
F-19
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Cash and Cash Equivalents
For purposes of the consolidated statements of cash flows, CVR considers all highly liquid debt instruments with original maturities of three months or less to be cash equivalents. CVR had restricted cash held for debt repaymentIn connection with CVR’s initial public offering, $4.2 million of $3,500,000 and $0 at December 31, 2004 and 2005, respectively; restricted cash wasdeferred offering costs in 2007 were presented in operating activities in the interim financial statements. Such amounts have now been reflected in other long-term assets on the consolidated balance sheet since the restriction wasas financing activities for the term2007 period in the Consolidated Statements of the debt (see note 10).Cash Flows. The impact on prior financial statements of this revision is not considered material.
Accounts Receivable
CVR grants credit to its customers. Credit is extended based on an evaluation of a customer’s financial condition; generally, collateral is not required. Accounts receivable are due on negotiated terms and are stated at amounts due from customers, net of an allowance for doubtful accounts. Accounts outstanding longer than their contractual payment terms are considered past due. CVR determines its allowance for doubtful accounts by considering a number of factors, including the length
F-12
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
of time trade accounts are past due, the customer’s ability to pay its obligations to CVR, and the condition of the general economy and the industry as a whole. CVR writes off accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. At December 31, 2004, three customers individually represented greater than 10%2006 and collectively represented 38% of the accounts receivable balance. The largest concentration of credit for any one customer at December 31, 2004 was 15% of the total accounts receivable balance. At December 31, 2005,2007, two customers individually represented greater than 10% and collectively represented 41%29% and 29%, respectively, of the total accounts receivable balance. The largest concentration of credit for any one customer at December 31, 20052006 and December 31, 2007 was 28%16% and 15%, respectively, of the accounts receivable balance.
Inventories
Inventories consist primarily of crude oil, blending stock and components, work in progress, fertilizer products, and refined fuels and by-products. Inventories are valued at the lower of moving-average cost, which approximates thefirst-in, first-out (FIFO) method,cost, 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 theability-to-bare process, whereby raw materials and production costs are allocated towork-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of moving average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.
In connection with the initial distribution of the accompanying Original Predecessor financial statements for purposes of effecting a business combination, the Original Predecessor changed its method of accounting for inventories from thelast-in, first-out (LIFO) method to the FIFO method. Management believes the FIFO method is preferable in the circumstances because the FIFO method is considered to represent a better matching of costs with related revenues under current volatile market conditions. Accordingly, crude oil, blending stock and components, work in progress, and refined fuels and by-products are valued at the lower of FIFO cost or market for all years presented.
Prepaid Expenses and Other Current Assets
Prepaid expenses and other current assets consist of prepayments for crude oil deliveries to the refinery for which title had not transferred, non-trade accounts receivables, current portions of prepaid insurance and deferred financing costs, and other general current assets.
Property, Plant, and Equipment
Additions to property, plant and equipment, including capitalized interest and certain costs allocable to construction and property purchases, are recorded at cost. Capitalized interest is added to any capital project over $1,000,000 in cost which is expected to take more than six months to complete. Depreciation is computed using principally the straight-line method over the estimated
F-20
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
useful lives of the various classes of depreciable assets. The useful lives used in computing depreciation for such assets are as follows:
| | | |
| | | Range of Useful
|
Asset | | Range of useful lives,Lives, in yearsYears
|
| |
| Improvements to land | | | 15 to 20 | |
| Buildings | | | 20 to 30 | |
| Machinery and equipment | | | 5 to 30 | |
| Automotive equipment | | | 5 | |
| Furniture and fixtures | | | 3 to 5 | 7 |
F-13
CVR Energy, Inc.Our leasehold improvements are depreciated on the straight-line method over the shorter of the contractual lease term or the estimated useful life. Expenditures for routine maintenance and Subsidiaries
repair costs are expenses when incurred. Such expenses are reported in direct operating expenses (exclusive of depreciation and amortization) in the Company’s consolidated statements of operations.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Goodwill and Intangible Assets
Goodwill represents the excess of the cost of an acquired entity over the fair value of the assets acquired less liabilities assumed. Intangible assets are assets that lack physical substance (excluding financial assets). Goodwill acquired in a businesscombinationand intangible assets with indefinite useful lives are not amortized, and intangible assets with finite useful lives are amortized. Goodwill and intangible assets not subject to amortization are tested for impairment annually or more frequently if events or changes in circumstances indicate the asset might be impaired. CVR uses November 1 of each year as its annual valuation date for the impairment test. The annual review of impairment is performed by comparing the carrying value of the applicable reporting unit to its estimated fair value, using a combination of the discounted cash flow analysis and market approach. Our reporting units are defined as operating segments due to each operating segment containing only one component. As such all goodwill impairment testing is done at each operating segment.
Deferred Financing costsCosts
Deferred financing costs related to the term debt areamortized to interest expense and other financing costs using the effective-interest method over the life of the loan.term debt. Deferred financing costs related to the revolving loan facility and the funded letters of credit facility are amortized to interest expense and other financing costs using the straight-line method through the termination date of each credit facility.
Planned Major Maintenance Costs
The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense whenmaintenanceservices are performed. During the304-day period year ended December 31, 2004,2006, the Coffeyville nitrogen plant completed a major scheduled turnaround. Costs of approximately $1,800,000$2,570,000 associated with the turnaround are included in costdirect operating expenses (exclusive of goods sold for that period.depreciation and amortization). The Coffeyville nitrogen plant is scheduled for the next turnaround in 2006. The Coffeyville refinery last completed a major scheduled turnaround in 20022007. Costs of approximately $3,984,000 and is scheduled$76,393,000, associated with the 2007 turnaround, were included in direct operating expenses (exclusive of depreciation and amortization) for the next turnaroundyear ended December 31, 2006 and December 31, 2007, respectively.
Planned major maintenance activities for the nitrogen plant generally occur every two years. The required frequency of the maintenance varies by unit, for the refinery, but generally is every four years.
F-21
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Cost Classifications
Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of approximately $150,000, $1,061,000, $2,148,000, and $2,390,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses exclude depreciation and amortization of approximately $907,000, $22,706,000, $47,714,000, and $57,367,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively. Direct operating expenses also exclude depreciation of $7,627,000 for the year ended December 31, 2007 that is included in 2007.“Net Costs Associated with Flood” on the consolidated statement of operations as a result of the assets being idle due to the flood.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consist primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of approximately $71,000, $187,000, $1,143,000, and $1,022,000 for the174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.
Income Taxes
Original Predecessor was not a separate legal entity, and its operating results were included with the operating results of Farmland and its subsidiaries in filing consolidated federal and state income tax returns. As a cooperative, Farmland was subject toCVR accounts for income taxes on all income not distributed to patrons as qualified patronage refunds,under the provision of Statement Financial Accounting Standards (SFAS) No. 109,Accounting for Income Taxes. SFAS 109 requires the asset and Farmland did not allocateincome taxes to its divisions. As a result, the accompanying Original Predecessor financial statements do not reflect any provisionliability approach for accounting for income taxes.
Income taxes for CVR are accounted for under theasset-and-liability method. Under this method, deferred tax assets and liabilities are recognized for the anticipated future tax consequences attributable to differences between the financial statement carrying amounts of existingassetsand liabilities and their respective tax bases. Deferred amounts are measured using enacted tax rates expected to apply to taxable income in the year those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in the period that includes the enactment date.
As discussed in Note 11 (“Income Taxes”), CVR adopted Financial Accounting Standards Board (FASB) Interpretation No. 48,Accounting for Uncertainty in Income Taxes an Interpretation of FASB No. 109(FIN 48) effective January 1, 2007.
Consolidation of Variable Interest Entities
In accordance with FASB Interpretation No. 46R,Consolidation of Variable Interest Entities, (FIN 46R), management has reviewed the terms associated with its interests in the Partnership based upon the partnership agreement. Management has determined that the Partnership is a variable interest entity (VIE) and as such has evaluated the criteria under FIN 46R to determine that CVR is the primary beneficiary of the Partnership. FIN 46R requires the primary beneficiary of a variable interest entity’s activities to consolidate the VIE. FIN 46R defines a variable interest entity as an entity in which the equity investors do not have substantive voting rights and where there is not sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. As the primary beneficiary, CVR absorbs the majority of the expected lossesand/or receives a majority of the expected residual returns of the VIE’s activities.
F-22
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Impairment of Long-Lived Assets
CVR accounts for long-lived assets in accordance with Statement of Financial Accounting StandardsSFAS No. 144, (SFAS 144),Accounting for the Impairment or Disposal of Long-Lived Assets.Assets. In accordance with SFAS 144, CVR reviews long-lived assets (excluding goodwill, intangible assets with indefinite lives, and deferred tax assets) for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of an asset to estimated undiscounted future net cash flows expected to be generated by the asset. If the carrying amount of an asset exceeds its estimated undiscounted future net cash flows, an impairment charge is recognized for the amount by which the carrying amount of the assets exceeds their fair value. Assets to be disposed of are reported at the lower of their carrying value or fair value less cost to sell.
F-14
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
In its Plan of Reorganization, Farmland stated, among other things, its intent to dispose of its petroleum and nitrogen assets. Despite this stated intent, these assets were not classified as held for sale under SFAS 144 because, ultimately, any disposition required approval of the Court and the Court did not ultimately approve such disposition until March 3, 2004. Since Farmland determined that it was more likely than not that its petroleum and nitrogen fertilizer assets would be disposed of, those assets were tested for impairment in 2002 pursuant to SFAS 144, using projected undiscounted net cash flows based on Farmland’s best assumptions regarding the use and eventual disposition of those assets, primarily from indications of value received from potential bidders through the bankruptcy sales process. Based on the tests, assumptions and determinations as of the impairment testing date, the assets were determined to be impaired. Farmland’s best estimate at December 31, 2002 was that the carrying value of these assets exceeded the fair value expected to be received on disposition of these assets by $375,068,359. Accordingly, an impairment charge was recognized for such amount in 2002. The ultimate proceeds from disposition of these assets resulted from a bidding and auction process conducted in the bankruptcy proceedings. In 2003, as a result of receiving a stalking horse bid from Coffeyville Resources, LLC in the bankruptcy court’s sales process, Farmland revised its estimate for the amount to be generated from the disposition of these assets, and an additional impairment charge of $9,638,626 was taken. No impairment charges were recognized for any of the years ended December 31, 2004 or 2005.periods presented.
Revenue Recognition
SalesRevenues for products sold are recognizedrecorded upon delivery of the products to customers, which is the point at which title is transferred, the customer has the assumed risk of loss, and when the productpayment has been received or collection is delivered and all significant obligations of CVR have been satisfied.reasonably assumed. Deferred revenue represents customer prepayments under contracts to guarantee a price and supply of nitrogen fertilizer in quantities expected to be delivered in the next 12 months in the normal course of business. Excise and other taxes collected from customers and remitted to governmental authorities are not included in reported revenues.
Shipping Costs
Pass-through finished goods delivery costs reimbursed by customers are reported in net sales, while an offsetting expense is included in cost of goods sold.product sold (exclusive of depreciation and amortization).
Derivative Instruments and Fair Value of Financial Instruments
CVR uses futures contracts, options, and forward swap contracts primarily to reduce the exposure to changes in crude oil prices, finished goods product prices and interest rates and to provide economic hedges of inventory positions. These derivative instruments have not been designated as hedges for accounting purposes. Accordingly, these instruments are recorded in the consolidated balance sheets at fair value, and each period’s gain or loss is recorded as a component of other income (expense)gain (loss) on derivatives in accordance with Statement of Financial Accounting StandardsSFAS No. 133,Accounting for Derivative Instruments and Hedging Activities.
Financial instruments consisting of cash and cash equivalents, accounts receivable, and accounts payable are carried at cost, which approximates fair value, as a result of the short-term nature of the instruments. The carrying value of long-term and revolving debt approximates fair value as a result of the floating interest rates assigned to those financial instruments.
Share-Based Compensation
CVR, accountsCALLC, CALLC II and CALLC III account for share-based compensation in accordance with Statement of Financial Accounting Standards (SFAS)SFAS No. 123(R),Share-Based Payments.PaymentsandEITF 00-12 IssueNo. 00-12,Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee(EITF 00-12). CVR has been allocated non-cash share-based compensations expense from CALLC, CALLC II and CALLC III.
In accordance with SFAS 123(R), CVR, appliesCALLC, CALLC II and CALLC III apply afair-value-based fair-value based measurement method in accounting for share-based compensation. In accordance with
F-15F-23
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
EITF 00-12, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance in EITF IssueNo. 96-18,Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires variable accounting in the circumstances.
Non-vested shares, when granted, are valued at the closing market price of CVR’s common stock on the date of issuance and amortized to compensation expense on a straight-line basis over the vesting period of the stock. The fair value of the stock options is estimated on the date of grant using the Black — Scholes option pricing model.
As of December 31, 2007, there had been 17,500 shares of non-vested common stock awarded. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have voting and non-forfeitable dividend rights on these shares from the date of grant. See Note 4, “Members’ Equity and Share-Based Compensation”.
Environmental Matters
Liabilities related to future remediation costs of past environmental contamination of properties are recognized when the related costs are considered probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existinginternal and third-party assessments of contamination, available remediation technology, site-specific costs, and currently enacted laws and regulations. In reporting environmental liabilities, no offset is made for potential recoveries. All liabilitiesLoss contingency accruals, including those for environmental remediation, are monitoredsubject to revision as further information develops or circumstances change and adjusted as new facts or changes in law or technology occur.such accruals can take into account the legal liability of other parties. Environmental expenditures are capitalized at the time of the expenditure when such costs provide future economic benefits.
Use of Estimates
In preparingThe consolidated financial statements have been prepared in conformity with U.S. generally accepted accounting principles, generally accepted in the United States of America, management is required to makeusing management’s best estimates and assumptions thatjudgments where appropriate. These estimates and judgments affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates.these estimates and judgments.
Recently AdoptedNew Accounting StandardsPronouncements
In November 2004,September 2006, the FASB issued Statement of Financial Accounting StandardsFAS No. 151 (SFAS 151),157,Inventory CostsFair Value Measurements, which clarifiesestablishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. FAS 157 states that fair value is “the price that would be received to sell the accountingasset 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 abnormal amounts of idle facility expense, freight, handling costs, and wasted material, and requires that those items be recognized as current-period charges. SFAS 151 also requires that allocation of fixed production overhead to the cost of conversion be based on the normal capacity of the production facilities. SFAS 151 is effectivefinancial statements issued for fiscal years beginning after JuneNovember 15, 20052007, and interim periods within those fiscal years. The Company is not expected tocurrently evaluating the effect that this statement will have a material effect on Successor’sits financial position or results of operations.statements.
In December 2004,February 2007, the FASB issued StatementFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities(FAS 159). Under this standard, an entity is required to provide additional information that will assist investors and other users of Accounting Standards No. 153 (SFAS 153),Exchangesfinancial information to more easily understand the effect of Nonmonetary Assets,which addresses the measurement of exchanges of nonmonetary assets. SFAS 153 eliminates the exception fromcompany’s choice to use fair value measurement for nonmonetary exchanges of similar productive assets, which was previously provided by APB Opinion No. 29,Accounting for Nonmonetary Transactions, and replaces it with an exception for exchanges which do not have commercial substance. SFAS 153 specifies that a nonmonetary exchange has commercial substance if the future cash flows ofon its earnings. Further, the entity are expectedis required to change significantly as a result of the exchange. SFAS 153 is effective for nonmonetary asset exchanges occurring in fiscal periods beginning after June 15, 2005. The adoption of SFAS 153 is not expected to have a material effect on CVR’s financial position or results of operations.
In December 2004, the FASB issued SFAS 123(R),Share-Based Payments.SFAS 123(R) revises SFAS 123 and supersedes APB 25. SFAS 123(R) requires that compensation costs relating to share-based payment transactions be recognized in a company’s financial statements. SFAS 123(R) applies to transactions in which an entity exchanges its equity instruments for goods or services and also may apply to liabilities an entity incurs for goods or services that are based ondisplay the fair value of those equity instruments. Under SFAS 123(R), CVR is requiredassets and liabilities for which the company has chosen to apply afair-value-based measurement method in accounting for share-based payment transactions with employees. SFAS 123(R) is effective for periods beginning after December 15, 2005; however, Successor elected early adoption of SFAS 123(R) foruse fair value on the233-day period ended December 31, 2005. The effect face of the adoption of thisbalance sheet. This standard is described in note 4.
In March 2005,does not eliminate the FASB issued FASB Interpretation No 47 (FIN 47) Accounting for Conditional Asset Retirement Obligations.FIN 47 requires conditional asset retirement obligations to bedisclosure requirements about
F-16F-24
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
recognized if a legal obligation exists
fair value measurements included in FAS 157 and FAS No. 107,Disclosures about Fair Value of Financial Instruments. FAS 159 is effective for fiscal years beginning after November 15, 2007, and early adoption is permitted as of January 1, 2007, provided that the entity makes that choice in the first quarter of 2007 and also elects to perform asset retirement activitiesapply the provisions of FAS 157. We are currently evaluating the potential impact that FAS 159 will have on our financial condition, results of operations and a reasonable estimatecash flows.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the business combination, establishes the acquisition date as the date that the acquirer achieves control and requires the acquirer to recognize the assets acquired, liabilities assumed and any noncontrolling interest at their fair values as of the fair valueacquisition date. This statement also requires that acquisition-related costs of the obligation canacquirer be made. FIN 47 also provides guidancerecognized separately from the business combination and will generally be expensed as incurred. CVR will be required to whenadopt this statement as of January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business combinations for which the acquisition date is on or after January 1, 2009.
In December 2007, the FASB issued SFAS No. 160,Noncontrolling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. It clarifies that a noncontrolling interest in a subsidiary is an ownership interest in the consolidated entity would have sufficient information to reasonably estimatethat should be reported as equity in the fair valueconsolidated financial statements. SFAS 160 requires retroactive adoption of an asset retirement obligation. FIN 47 becamethe presentation and disclosure requirements for existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for us beginning January 1, 2009. The Company is currently evaluating the period ending December 31, 2005. A net asset retirement obligationpotential impact of $636,000 was included in other current liabilitiesthe adoption of SFAS 160 on theits consolidated balance sheet.financial statements.
| |
| (4) | Members’ Equity and Share Based Compensation |
Immediate Predecessor issued 63,200,000 voting preferred units at $1 par value for cash to finance the Initial Acquisition, as described in note 1. The preferred units were the only voting units of Immediate Predecessor and, prior to May 10, 2004, had preferential rights to distributions. The preference required that the holders of preferred units were to be distributed $63,200,000, plus a preferred yield equal to 15% per annum compounded monthly, before any distributions could be made to holders of common units.
Concurrent with the issuance of the preferred units, managementManagement of Immediate Predecessor was issued 11,152,941 nonvoting restricted common units for recourse promissory notes aggregating $63,000. Based on the estimated relative fair value of the restricted common units on March 3, 2004, $3,100,000 was allocated to the common units. Accordingly, unearned compensation of $3,037,000 was recognized as a contra-equity balance in the accompanying consolidated balance sheet. The holders of these common units were not vested at the date of issuance. Prior to May 10, 2004, distribution rights were subordinated to the preferred unit holders, as described above. On May 10, 2004, the promissory notes were repaid with cash and an additional 500,000 nonvoting restricted common units were issued to an officer of Immediate Predecessor for a recourse promissory note of $2,850. Based on the estimated fair value of the units on May 10, 2004, unearned compensation of $2,044,600 was recognized as a contra-equity balance in the accompanying consolidated balance sheet. Concurrent with the Subsequent Acquisition at June 23, 2005, as described in noteNote 1, all of the restricted common units of management were fully vested. Immediate Predecessor recognized $1,095,609 and $3,985,991$3,986,000 in compensation expense for the304-day period ended December 31, 2004 and the174-day period ended June 23, 2005, respectively, related to earned compensation.
On May 10, 2004, Immediate Predecessor refinanced its existing long term-debt with a $150 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under Immediate Predecessor’s previous credit facility. The borrowings were also used to distribute a $99,987,509 dividend, which included the preference payment of $63,200,000 plus the yield of $1,802,956 to the preferred unit holders and a $63,000 payment to the common unit holders for undistributed capital per the LLC agreement. The remaining $34,921,553 was distributed to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.
On June 23, 2005, immediately prior to the Subsequent Acquisition (see noteNote 1), the Immediate Predecessor used available cash balances to distribute a $52,211,493$52,211,000 dividend to the preferred and common unit holders pro rata according to their ownership percentages, as determined by the aggregate of the common and preferred units.
Successor issued 22,766,000 voting common units at $10 par value for cash to finance the Subsequent Acquisition, as described in noteNote 1. An additional 50,000 voting common units at $10 par value were issued to a member of management for an unsecured recourse promissory note that bearsaccrued interest at 7% and requiresrequired annual principal and interest payments through December 2009. The unpaid balance of the unsecured recourse promissory note and all unpaid interest was forgiven September 25, 2006 (see Note 17).
As required by the term loan agreements to fund certain capital projects, on September 14, 2005 an additional $10,000,000 capital contribution was received in return for 1,000,000 voting common units and on May 23, 2006 an additional $20,000,000 capital contribution was received in return for 2,000,000 at $10 par value (Delayed Draw Capital).
Common units held by management containcontained put rights held by management
F-17
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
and call rights held by SuccessorCALLC exercisable at fair value in the event the management member becomesbecame inactive. Accordingly, in accordance with EITF TopicNo. D-98, “ClassificationClassification and Measurement of Redeemable
F-25
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Securities”, common units held by management were initially recorded at fair value at the date of issuance and have beenwere classified in temporary equity as Management Voting Common Units Subject to Redemption (Capital Subject to Redemption) in the accompanying consolidated balance sheets. The put rights and call rights were eliminated in October 2007.
On November 30, 2006, an amendment to the Second Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC was approved with a pro rata reduction among all holders of common units in order to effect a total reduction of the number of outstanding Common Units. This amendment reduced the number of outstanding Common Units by 11.62%. Because cash unit holder’s value and ownership interest before and after the reallocation is unchanged and since no transfer of value occurred among the common unit holders, this pro rata reduction had no accounting consequence. At December 31, 2005,2006, management held 227,500201,063 of the 23,816,00022,816,000 voting common units.
On December 28, 2006, successor refinanced its existing long-term debt with $775 million term loan and used the proceeds of the borrowings to repay the outstanding borrowings under its previous first and second lien credit facilities, pay related fees and expenses and pay a distribution of $250 million to its common unit holders at December 31, 2006.
The put rights with respect to management’s common units, provide that following their termination of employment, they have the right to sell all (but not less than all) of their common units to Coffeyville Acquisition LLC at their “Fair Market Value” (as that term is defined in the LLC Agreement) if they were terminated without “Cause”, or as a result of death, “Disability” or resignation with “Good Reason” (each as defined in the LLC Agreement) or due to “Retirement” (as that term is defined in the LLC Agreement). Coffeyville Acquisition LLC has call rights with respect to the executives’ common units, so that following the executives’ termination of employment, Coffeyville Acquisition LLC has the right to purchase the common units at their Fair Market Value if the executive was terminated without Cause, or as a result of the executives’ death, Disability or resignation with Good Reason or due to Retirement. The call price will be the lesser of the common unit’s Fair Market Value or Carrying Value (which means the capital contribution, if any, made by the executive in respect of such interest less the amount of distributions made in respect of such interest) if the executive is terminated for Cause or he resigns without Good Reason. For any other termination of employment, the call price will be at the Fair Market Value or Carrying Value of such common units, in the sole discretion of Coffeyville Acquisition LLC’s board of directors. No put or call rights apply to override units following the executive’s termination of employment unless Coffeyville Acquisition LL’s board of directors (or the compensation committee thereof) determines in its discretion that put and call rights will apply.
CVR accounts for changes in redemption value of thesemanagement common units in the period the changes occur and adjusts the carrying value of the CapitalManagement Voting Common Units 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 CapitalManagement Voting Common Units Subject to Redemption waswere redeemable at December 31, 2005.2005 or December 31, 2006.
At December 31, 2005 the CapitalManagement Voting Common Units Subject to Redemption waswere revalued through an independent appraisal process, and the value was determined to be $18.34 per unit. Accordingly, the carrying value of the CapitalManagement Voting Common Units Subject to Redemption increased by $3,035,586$3,035,000 for the233-day period ended December 31, 2005 with an equal and offsetting decrease to Members’ Equity.
At December 31, 2006, the Management Voting Common Units Subject to Redemption were revalued through an independent appraisal process, and the value was determined to be $34.72 per unit. The appraisal utilized a discounted cash flow (DCF) method, a variation of the income approach, and the guideline public company method, a variation of the market approach, to determine the fair
F-26
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
value. The guideline public company method utilized a weighting of market multiples from publicly-traded petroleum refiners and fertilizer manufactures that are comparable to the Company. The recognition of the value of $34.72 per unit increased the carrying value of the Management Voting Common Units Subject to Redemption by $4,240,000 for the year ended December 31, 2006 with an equal and offsetting decrease to Members’ Equity. This increase was the result of higher forward market price assumptions, which were consistent with what was observed in the market during the period, in the refining business resulting in increased free cash flow projections utilized in the DCF method. The market multiples for the public-traded comparable companies also increased from December 31, 2005, resulting in increased value of the units.
Concurrent with the Subsequent Acquisition, Successor issued nonvoting override operating units to certain management members who hold common units. There were no required capital contributions for the override operating units.
Upon completion of the initial public offering on October 26, 2007, members’ equity, Management Voting Common Units Subject to Redemption, and Management Nonvoting Override Units were eliminated and replaced with Stockholders’ Equity to reflect the new corporate structure.
The following describes the share-based compensation plans of CALLC, CALLC II, CALLC III and CRLLC, CVR Energy’s wholly owned subsidiary.
919,630 Override Operating Units at aan Adjusted Benchmark Value of $10$11.31 per Unit
In June 2005, CALLC issued nonvoting override operating units to certain management members holding common units of CALLC. There were no required capital contributions for the override operating units. In accordance with SFAS 123(R),Share Based Compensation, using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,604,950.$3,605,000. Pursuant to the forfeiture schedule described below, the Company is recognizingCVR Energy recognized compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in-substance, multiple awards. Compensation expense inwas $602,000, $1,157,000, and $10,675,000 for the233-day191-day period endedending December 31, 2005, and for the years ending December 31, 2006 and 2007, respectively. In connection with the split of CALLC into two entities on October 16, 2007, management’s equity interest in CALLC was $602,381. split so that half of management’s equity interest is in CALLC and half is in CALLC II. The restructuring resulted in a modification of the existing awards under SFAS 123(R). However, because the fair value of the modified award equaled the fair value of the original award before the modification, there was no accounting consequence as a result of the modification. However, due to the restructuring, the employees of CVR Energy and CVR Partners no longer hold share-based awards in a parent company. Due to the change in status of the employees related to the awards, CVR Energy recognized compensation expense for the newly measured cost attributable to the remaining vesting (service) period prospectively from the date of the change in status, which expense is included in the amounts noted above. Also, CVR Energy now accounts for these awards pursuant toEITF 00-12 following the guidance inEITF 96-18, which requires variable accounting in this circumstance. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units as noted below.
F-27
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Significant assumptions used in the valuation were as follows:
| | | | | | |
| • | | | Estimated forfeiture rate | | None |
| • | | | Explicit service period | | Based on forfeiture schedule below |
| • | | | Grant-date fair value — controlling basis | | $5.16 per share |
| • | | | Marketability and minority interest discounts | | $1.24 per share (24% discount) |
| • | | | Volatility | | 37% |
| | | | | |
| | | Grant Date | | Remeasurement Date |
| |
| Estimated forfeiture rate | | None | | None |
| Explicit service period | | Based on forfeiture schedule below | | Based on forfeiture schedule below |
| Grant — date; fair value — controlling basis | | $5.16 per share | | — |
| October 16, 2007 (date of modification) estimated fair value | | — | | $39.53 |
| December 31, 2007 estimated fair value | | N/A | | $51.84 per share |
| Marketability and minority interest discounts | | 24% discount | | 15% discount |
| Volatility | | 37% | | 35.8% |
72,492 Override operating units participate in distributions in proportion to the numberOperating Units at a Benchmark Value of total common, non-forfeited override operating and participating override value units issued. Distributions to$34.72 per Unit
On December 28, 2006, CALLC issued additional nonvoting override operating units will be reduced untilto a certain management member who holds common units of CALLC. There were no required capital contributions for the total cumulative reductionsoverride operating units. In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units on December 28, 2006 of $473,000. Management believed that this method was preferable for the valuation of the override units as it allowed a better integration of the cash flows with other inputs, including the timing of potential exit events that impact the estimated fair value of the override units. These override operating units are equalbeing accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above and pursuant to the benchmark value. forfeiture schedule described below, CVR recognized compensation expense of $3,000 and $877,000 for the periods ending December 31, 2006 and 2007, respectively. The amount included in the year ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override operating units as described below.
Significant assumptions used in the valuation were as follows:
| | | | | |
| | | Grant Date | | Remeasurement Date |
| |
| Estimated forfeiture rate | | None | | None |
| Explicit service period | | Based on forfeiture schedule below | | Based on forfeiture schedule below |
| Grant — date; fair value — controlling basis | | $8.15 per share | | — |
| October 16, 2007 (date of modification) estimated fair value | | — | | $20.34 |
| December 31, 2007 estimated fair value | | N/A | | $32.65 per share |
| Marketability and minority interest discounts | | 20% discount | | 15% discount |
| Volatility | | 41% | | 35.8% |
F-28
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Override operating units are forfeited upon termination of employment for cause. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:
| | | | | |
| | | Forfeiture
| |
Minimum Period Held | | Percentage | |
| |
| 2 years | | | 75 | % |
| 3 years | | | 50 | % |
| 4 years | | | 25 | % |
| 5 years | | | 0 | % |
F-18
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
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 aan Adjusted Benchmark Value of $10$11.31 per Unit
In June 2005, CALLC issued 1,839,265 nonvoting override value units to certain management members holding common units of CALLC. There were no required capital contributions for the override value units.
In accordance with SFAS 123(R), using the Monte Carlo method of valuation, the estimated fair value of the override value units on June 24, 2005 was $4,064,776.$4,065,000. For the override value units, CVR Energy is recognizing compensation expense ratably over the implied service period of 6 years. CompensationThese override value units are being accounted for the same as the override operating units with an adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above, CVR recognized compensation expense inof $395,000, $677,000, and $12,788,000 for the233-day191-day period endedending December 31, 2005, was $395,187.and for the years ending December 31, 2006 and 2007, respectively. The amount included in the year ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override value units as described below. Significant assumptions used in the valuation were as follows:
| | | | | | |
| • | | | Estimated forfeiture rate | | None |
| • | | | Derived service period | | 6 years |
| • | | | Grant-date fair value — controlling basis | | $2.91 per share |
| • | | | Marketability and minority interest discounts | | $0.70 per share (24% discount) |
| • | | | Volatility | | 37% |
| | | | | |
| | | Grant Date | | Remeasurement Date |
| |
| Estimated forfeiture rate | | None | | None |
| Derived service period | | 6 years | | 6 years |
| Grant — date; fair value — controlling basis | | $2.91 per share | | — |
| October 16, 2007 (date of modification) estimated fair value | | — | | $39.53 |
| December 31, 2007 estimated fair value | | N/A | | $51.84 per share |
| Marketability and minority interest discounts | | 24% discount | | 15% discount |
| Volatility | | 37% | | 35.8% |
144,966 Override Value Units at a Benchmark Value of $34.72 per Unit
On December 28, 2006, CALLC issued 144,966 additional nonvoting override value units fully participate in cash distributions whento a certain management member who holds common units of CALLC. There were no required capital contributions for 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 timeoverride value units.
In accordance with SFAS 123(R), a combination of a distribution, nonebinomial model and a probability-weighted expected return method which utilized CVR Energy’s cash flow projections resulted in an estimated fair value of the override value units participate. Inon December 28, 2006 of $945,000. Management believed that this method was preferable for the eventvaluation of the Current Common Value is greater than two timesoverride units as it allowed a better integration of the original contributed capitalcash flows with other inputs, including the timing of such investors but less than four times,potential exit events that impact the numberestimated
F-29
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
fair value of participatingthe override units. For the override value units, CVR Energy is recognizing compensation expense ratably over the productimplied service period of 1) the number of issued6 years. These override value units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with that accounting method noted above, CVR recognized compensation expense of $17,000, and 2)$718,000 for the fraction,years ending December 31, 2006 and 2007, respectively. The amount included in the numeratoryear ending December 31, 2007 includes compensation expense as a result of the restructuring and modification of the split of CALLC into two entities, as described above. Using a binomial model and a probability-weighted expected return method which isutilized CVR Energy’s cash flow projections resulted in an estimated fair value of 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 untilas noted below.
Significant assumptions used in 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”. valuation were as follows:
| | | | | |
| | | Grant Date | | Remeasurement Date |
| |
| Estimated forfeiture rate | | None | | None |
| Derived service period | | 6 years | | 6 years |
| Grant — date; fair value — controlling basis | | $8.15 per share | | — |
| October 16, 2007 (date of modification) estimated fair value | | — | | $20.34 |
| December 31, 2007 estimated fair value | | N/A | | $32.65 per share |
| Marketability and minority interest discounts | | 20% discount | | 15% discount |
| Volatility | | 41% | | 35.8% |
Unless the compensation committee of the board of directors of CVR Energy takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:
| | | | | |
| | | Subject toForfeiture
|
| | Forfeiture
|
Minimum Period Held | | Percentage | |
| |
| 2 years | | | 75 | % |
| 3 years | | | 50 | % |
| 4 years | | | 25 | % |
| 5 years | | | 0 | % |
Successor,At December 31, 2007, assuming no change in the estimated fair value at December 31, 2007, there was approximately $71.1 million of unrecognized compensation expense related to nonvoting override units. This is expected to be recognized over a period of five years as follows (in thousands):
| | | | | | | | | |
| | | Override
| | | Override
| |
Year Ending December 31, | | Operating Units | | | Value Units | |
| |
| 2008 | | $ | 7,882 | | | $ | 16,924 | |
| 2009 | | | 4,087 | | | | 16,924 | |
| 2010 | | | 1,217 | | | | 16,924 | |
| 2011 | | | — | | | | 7,138 | |
| | | | | | | | | |
| | | $ | 13,186 | | | $ | 57,910 | |
| | | | | | | | | |
Phantom Unit Appreciation Plan
CVR Energy, through a wholly-owned subsidiary, has a Phantom Unit Appreciation Plan whereby directors, employees, and service providers may be awarded phantom points at the discretion of the
F-30
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
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,
F-19
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
or at the discretion of the compensation committee of the board of directors. The total combined interestdirectors of the Phantom Unit Plan and the override units (combined Profits Interest) cannot exceed 15% of the notional and aggregate equity interests of the Successor.CVR Energy. As of December 31, 2005,2007, the issued Profits Interest (combined phantom plan and override units) represented 11.73%15% of combined common unit interest and Profits Interest of the Company.CVR Energy. The Profits Interest was comprised of 10.22%11.1% and 1.51%3.9% of override interest and phantom interest, respectively. SubjectIn accordance with SFAS 123(R), using the December 31, 2007 CVR Energy stock closing price to determine the CVR Energy equity value, through an independent valuation process, the service phantom interest and the performance phantom interest were both valued at $51.84 per point. CVR has recorded compensation expense related to the valuation, vestingPhantom Unit Plan of $95,000, $10,722,000, and forfeiture provisions consistent with other profit interests described previously, $95,019 is included$18,400,000 for the191-day period ending December 31, 2005, and for the years ending December 31, 2006 and December 31, 2007, respectively. $10,817,000 and $29,217,000 were recorded in personnel accruals as of December 31, 20052006 and as compensation expense for the233-day period ending2007, respectively.
At December 31, 20052007, and assuming no change in the estimated fair value at December 31, 2007, there was approximately $25.2 million of unrecognized compensation expense related to the Phantom Unit Plan. This is expected to be recognized over a remaining period of four years.
138,281 Override Units with a Benchmark Amount of $10
In October 2007, CALLC III issued non-voting override units to certain management members holding common units of CALLC III. There were no required capital contributions for the override units. In accordance with SFAS 123(R),Share Based Compensation, using a binomial and a probability-weighted expected return method which utilized the CALLC III’s cash flows projections, the estimated fair value of the operating units at December 31, 2007 was $3,000. CVR Energy recognizes compensation costs for this plan based on the fair value of the awards at the end of each reporting period in accordance withEITF 00-12 using the guidance inEITF 96-18. In accordance withEITF 00-12, as a noncontributing investor, CVR Energy also recognized income equal to the amount that its interest in the investee’s net book value has increased (that is, its percentage share of the contributed capital recognized by the investee) as a result of the disproportionate funding of the compensation costs. This amount equaled the compensation expense recognized for these awards for the year ended December 31, 2007. Pursuant to the forfeiture schedule reflected above, CVR Energy recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed.
Significant Assumptions used in the valuation were as follows:
| | |
| Estimated forfeiture rate | | None |
| Explicit Service Period | | Based on forfeiture schedule above |
| December 31, 2007 estimated fair value | | $0.02 per share |
| Marketability and minority interest discount | | 15% discount |
| Volatility | | 34.7% |
In connection with the initial public offering, the fractional shares held by the Company’s chief executive officer in the Successor’s subsidiaries were exchanged at the fair value for 247,471 shares of CVR common stock. This exchange resulted in the elimination of the minority interest, the reversal of previous fair value adjustments of $1,053,000 in Members’ Equity, thestep-up in property, plant and equipment of $974,000, and the recognition of a related deferred tax liability of $389,000.
In February 2008, CALLC III issued additional non-voting override units to management members.
F-31
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Long Term Incentive Plan
The CVR Energy, Inc. 2007 Long Term Incentive Plan, or the LTIP, permits the grant of options, stock appreciation rights, or SARs, restricted stock, restricted stock units, dividend equivalent rights, share awards and performance awards (including performance share units, performance units and performance-based restricted stock). Individuals who are eligible to receive awards and grants under the LTIP include the Company’s subsidiaries’ employees, officers, consultants, advisors and directors. A summary of the principal features of the LTIP is provided below. As of December 31, 2007, no awards had been made under the LTIP to any of the Company’s executive officers.
Shares Available for Issuance. The LTIP authorizes a share pool of 7,500,000 shares of the Company’s common stock, 1,000,000 of which may be issued in respect of incentive stock options. Whenever any outstanding award granted under the LTIP expires, is canceled, is settled in cash or is otherwise terminated for any reason without having been exercised or payment having been made in respect of the entire award, the number of shares available for issuance under the LTIP shall be increased by the number of shares previously allocable to the expired, canceled, settled or otherwise terminated portion of the award. As of December 31, 2007, 7,463,600 shares of common stock were available for issuance under the LTIP.
On October 24, 2007, 17,500 shares of non-vested stock having a fair value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights on these shares from the date of grant. The fair value of each share of non-vested stock was measured based on the market price of the common stock as of the date of grant and will be amortized over the respective vesting periods. One-third will vest on October 24, 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. Options to purchase 8,600 common shares at an exercise price of $24.73 per share were granted to outside directors on December 21, 2007.
A summary of the status of CVR’s non-vested shares as of December 31, 2007 and changes during the year ended December 31, 2007 is presented below:
| | | | | | | | | |
| | | | | | Weighted
| |
| | | | | | Average
| |
| | | | | | Grant-Date
| |
Non-Vested Shares | | Shares | | | Fair Value | |
| | | (In 000’s) | | | | |
| |
| Non-vested at December 31, 2006 | | $ | — | | | $ | — | |
| Granted | | | 18 | | | | 20.88 | |
| Vested | | | — | | | | — | |
| Forfeited | | | — | | | | — | |
| | | | | | | | | |
| Non-vested at December 31, 2007 | | $ | 18 | | | $ | 20.88 | |
| | | | | | | | | |
As of December 31, 2007, there was approximately $0.3 million of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately one year. Total compensation expense recorded in 2007 related to the nonvested stock was $42,000.
F-32
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Activity and price information regarding CVR’s stock options granted are summarized as follows:
| | | | | | | | | | | | | |
| | | | | | | | | Weighted
| |
| | | | | | Weighted
| | | Average
| |
| | | | | | Average
| | | Remaining
| |
| | | | | | Exercise
| | | Contractual
| |
Options | | Shares | | | Price | | | Term | |
| | | (In 000’s) | | | | | | | |
| |
| Outstanding, December 31, 2006 | | | — | | | $ | — | | | | — | |
| Granted | | | 19 | | | $ | 21.61 | | | | 9.89 | |
| Exercised | | | — | | | | — | | | | | |
| Forfeited | | | — | | | | — | | | | | |
| Expired | | | — | | | | — | | | | | |
| Outstanding, December 31, 2007 | | | 19 | | | $ | 21.61 | | | | 9.89 | |
| Vested or expected to vest at December 31, 2007 | | | — | | | | — | | | | | |
| Exercisable at December 31, 2007 | | | — | | | | — | | | | | |
The weighted average grant-date fair value of options granted during the year ended December 31, 2007 was $12.47 per share. Total compensation expense recorded in 2007 related to the stock options was $15,000.
Inventories consisted of the following (in thousands):
| | | | | | | | | | |
| | | | | | | | | | | Successor | |
| | | Immediate
| | | | | | | December 31,
| | December 31,
| |
| | | Predecessor | | | | Successor | | | 2006 | | 2007 | |
| | | December 31,
| | | | December 31,
| | | | | As restated(†) | |
| | | 2004 | | | | 2005 | |
| Finished goods | | $ | 24,704 | | | | $ | 58,513 | | | $ | 59,722 | | | $ | 109,394 | |
| Raw materials and catalysts | | | 26,136 | | | | | 47,437 | | | | 60,810 | | | | 92,104 | |
| In-process inventories | | | 14,059 | | | | | 33,397 | | | | 18,441 | | | | 29,817 | |
| Parts and supplies | | | 15,524 | | | | | 14,929 | | | | 22,460 | | | | 23,340 | |
| | | | | | | | | | | | | |
| | | $ | 80,423 | | | | $ | 154,276 | | | $ | 161,433 | | | $ | 254,655 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
F-33
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| |
| (6) | Property, Plant, and Equipment |
A summary of costs for property, plant, and equipment is as follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | | | | Successor | |
| | | Predecessor | | | | Successor | | | December 31,
| | December 31,
| |
| | | December 31,
| | | | December 31,
| | | 2006 | | 2007 | |
| | | 2004 | | | | 2005 | |
| Land and improvements | | $ | 1,061 | | | | $ | 9,346 | | | $ | 11,028 | | | $ | 13,058 | |
| Buildings | | | 768 | | | | | 10,306 | | | | 11,042 | | | | 17,541 | |
| Machinery and equipment | | | 39,617 | | | | | 715,381 | | | | 864,140 | | | | 1,108,858 | |
| Automotive equipment | | | 660 | | | | | 3,396 | | | | 4,175 | | | | 5,171 | |
| Furniture and fixtures | | | 1,372 | | | | | 271 | | | | 5,364 | | | | 6,304 | |
| Leasehold improvements | | | | 887 | | | | 929 | |
| Construction in progress | | | 8,738 | | | | | 57,382 | | | | 184,531 | | | | 182,046 | |
| | | | | | | | | | | | | |
| | | | 52,216 | | | | | 796,082 | | | | 1,081,167 | | | | 1,333,907 | |
| Accumulated depreciation | | | 2,210 | | | | | 23,569 | | | | 74,011 | | | | 141,733 | |
| | | | | | | | | | | | | |
| | | $ | 50,006 | | | | $ | 772,513 | | | $ | 1,007,156 | | | $ | 1,192,174 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | |
Construction in progress of $2,067,869 and $26,977,642 as of December 31, 2004 and 2005, respectively, related to capital improvements for compliance with EPA regulations intended to limit amounts of sulfur in diesel and gasoline.
Capitalized interest recognized as a reduction in interest expense for the174-day period ended June 23, 2005 and the233-day period years ended December 31, 2005,2006, and December 31, 2007 totaled approximately $297,694$11,613,000 and $831,264,$12,049,000, respectively.
F-20
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
| (7) | Goodwill and Intangible Assets |
In connection with the Subsequent Acquisition described in noteNote 1, Successor recorded goodwill of $83,774,885.$83,775,000. SFAS No. 142,Goodwill and Other Intangible Assets, provides that goodwill and other intangible assets with indefinite lives shall not be amortized but shall be tested for impairment on an annual basis. In accordance with SFAS 142, Successor completed its annual test for impairment of goodwill as of November 1, 2005.2006 and 2007. Based on the results of the test, no impairment of goodwill was recorded as of December 31, 2005.2006 or December 31, 2007. The annual review of impairment is performed by comparing the carrying value of the applicable reporting unit to its estimated fair value using a combination of the discounted cash flow analysis and market approach. CVR’s reporting units are defined as operating segments, as such all goodwill impairment testing is done at each operating segment.
Contractual agreements with a fair market value of $1,322,000 were acquired in the Subsequent Acquisition described in noteNote 1. The intangible value of these agreements is amortized over the life of the agreements through June 2025. Accumulated amortization was $313,453 at December 31, 2005. Amortization expense of $313,000, $370,000, and $165,000 was recorded in depreciation and amortization for the233-days ended December 31, 2005, of $202,303 was reported as cost of goods sold and $111,150 was reported as selling, general,the years ended December 31, 2006, and administrative expenses.December 31, 2007, respectively.
Estimated amortization of the contractual agreements is as follows (in thousands):
| | | | | | | | | |
| | | Contractual
| | | Contractual
| |
Year Ending December 31, | | Agreements | | | Agreements | |
| |
| 2006 | | $ | 370 | | |
| 2007 | | | 165 | | |
| 2008 | | | 64 | | | | 64 | |
| 2009 | | | 33 | | | | 33 | |
| 2010 | | | 33 | | | | 33 | |
| 2011 | | | | 33 | |
| 2012 | | | | 28 | |
| Thereafter | | | 344 | | | | 282 | |
| | | | | | | |
| | | | 1,009 | | | | 473 | |
| | | | | | | |
F-34
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| |
| (8) | Deferred Financing Costs |
Deferred financing costs of $6,300,727$10,009,000 were paid in the Initial Acquisition describedconjunction with a debt financing in note 1. Additional2004. The unamortized amount of these deferred financing costs of $10,009,193 were paid with the debt refinancing on May 10, 2004, as described in notes 4 and 10. The unamortized deferred financing costs of $6,071,110 related to the Initial Acquisition financing were written off when the related debt was extinguished and refinanced with the existing credit facility and these costs were included in loss on extinguishment of debt for the 304 days ended December 31, 2004. A prepayment penalty of $1,095,000 on the previous credit facility was also paid and expensed and included in loss on extinguishment of debt for the 304 days ended December 31, 2004. The unamortized deferred financing costs of $8,093,754$8,094,000 related to the May 10, 2004 refinancing were written off when the related debt was extinguished upon the Subsequent Acquisition described in noteNote 1 and these costs were included in loss on extinguishment of debt for the 174 days ended June 23, 2005. For the 304 days ended December 31, 2004 and for the 174 days ended June 23, 2005, amortization of deferred financing costs reported as interest expense and other financing costs was $1,332,890 and $812,166, respectively,$812,000, using the effective-interest amortization method.
Deferred financing costs of $24,628,315$24,628,000 were paid in the Subsequent Acquisition described in Note 1. Effective December 28, 2006, the Company amended and will berestated its credit agreement with a consortium of banks, additionally capitalizing $8,462,000 in debt issuance costs. This amendment and restatement was within the scope of theEITF 96-19,Debtor’s Accounting for Modification or Exchange of Debt Instruments, as well asEITF 98-14,Debtor’s Accounting for Changes inLine-of-Credit or Revolving-Debt Arrangements. In accordance with that guidance, a portion of the unamortized loan costs of $16,959,000 from the original credit facility as well as additional finance and legal charges associated with the second amended and restated credit facility of $901,000 were included in loss on extinguishment of debt for the year December 31, 2006. The remaining costs are being amortized through June 2013.over the life of the related debt instrument. Additionally, a prepayment penalty of $5,500,000 on the previous credit facility was also paid and expensed and included in loss on extinguishment of debt for the year ended December 31, 2006. For the 233 days ended December 31, 2005, the years ended December 31, 2006, and December 31, 2007, amortization of deferred financing costs reported as interest expense and other financing costs totaled $1,751,041$1,751,000, $3,337,000, and $1,947,000, respectively, using the effective-interest amortization method for the term debt and the straight-line method for the letter of credit facility and revolving loan facility.
Deferred financing costs of $2,088,000 were paid in conjunction with three new credit facilities entered into August 2007 as a result of the flood and crude oil discharge. The unamortized amount of these deferred financing costs of $1,258,000 were written off when the related debt was extinguished upon the consummation of the initial public offering and these costs were included in loss on extinguishment of debt for the year ended December 31, 2007. Amortization of deferred financing costs reported as interest expense and other financing costs was $831,000 using the effective-interest amortization method.
F-21
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Deferred financing costs consisted of the following (in thousands):
| | | | | | | | | | |
| | | Immediate
| | | | | | | | | | | | | |
| | | Predecessor | | | | Successor | | | December 31,
| | December 31,
| |
| | | December 31,
| | | | December 31,
| | | 2006 | | 2007 | |
| | | 2004 | | | | 2005 | |
| Deferred financing costs | | $ | 10,009 | | | | $ | 24,628 | | | $ | 11,065 | | | $ | 12,278 | |
| Less accumulated amortization | | | 1,103 | | | | | 1,751 | | | | 21 | | | | 2,778 | |
| | | | | | | | | | | | | |
| Unamortized deferred financing costs | | | 8,906 | | | | | 22,877 | | | | 11,044 | | | | 9,500 | |
| Less current portion | | | 1,699 | | | | | 3,352 | | | | 1,916 | | | | 1,985 | |
| | | | | | | | | | | | | |
| | | $ | 7,207 | | | | $ | 19,525 | | | $ | 9,128 | | | $ | 7,515 | |
| | | | | | | | | | | | | |
F-35
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Estimated amortization of deferred financing costs is as follows (in thousands):
| | | | | | | | | |
| | | Deferred
| | | Deferred
| |
Year Ending December 31, | | Financing | | | Financing | |
| |
| 2006 | | $ | 3,352 | | |
| 2007 | | | 3,337 | | |
| 2008 | | | 3,332 | | | $ | 1,985 | |
| 2009 | | | 3,308 | | | | 1,968 | |
| 2010 | | | 3,293 | | | | 1,953 | |
| 2011 | | | | 1,436 | |
| 2012 | | | | 1,426 | |
| Thereafter | | | 6,255 | | | | 732 | |
| | | | | | | |
| | | $ | 22,877 | | | $ | 9,500 | |
| | | | | | | |
| |
| (9) | Other Long-Term AssetsNote Payable and Capital Lease Obligations |
Other long-term assets consistedThe Company entered into an insurance premium finance agreement in July 2007 to finance the purchase of the following (in thousands):
| | | | | | | | | | |
| | | Immediate
| | | | | |
| | | Predecessor | | | | Successor | |
| | | December 31,
| | | | December 31,
| |
| | | 2004 | | | | 2005 | |
| Restricted cash held for debt repayment | | $ | 3,500 | | | | $ | — | |
| Prepaid insurance charges | | | 3,047 | | | | | 2,447 | |
| Non-current receivables | | | — | | | | | 4,889 | |
| Other assets | | | 400 | | | | | 1,082 | |
| | | | | | | | | | |
| | | $ | 6,947 | | | | $ | 8,418 | |
| | | | | | | | | | |
its property, liability, cargo and terrorism policies. The approximately $3.4 million note will be repaid in equal monthly installments of $0.8 million with final payment in April 2008.
Non-current receivables consistThe Company entered into two capital leases in 2007 to lease platinum required in the manufacturing of unsettledmark-to-market gainsa new catalyst. The leases will terminate on derivatives relatingthe date an equal amount of platinum is returned to each lessor with the interest rate swap agreements described in notes 14 & 15.
CVR has prepaid two environmental insurance policies. One policy covers environmental site protection, and the other is a cost cap remediation policy for costsdifference to be incurred beyondpaid in cash. At December 31, 2007 the next twelve months. See note 13 for a further description oflease obligations were recorded at approximately $8.2 million on the environmental commitments and contingencies.
F-22
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Estimated amortization of prepaid insurance is as follows (in thousands):
| | | | | |
| | | Prepaid
| |
Year Ending December 31, | | Insurance | |
| |
| 2006 | | $ | 1,062 | |
| 2007 | | | 394 | |
| 2008 | | | 333 | |
| 2009 | | | 333 | |
| 2010 | | | 333 | |
| Thereafter | | | 1,054 | |
| | | | | |
| | | | 3,509 | |
| Less current portion | | | (1,062 | ) |
| | | | | |
| Total long-term | | $ | 2,447 | |
| | | | | |
consolidated balance sheet.
At March 3,On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. As a result, the Company’s refinery and nitrogen fertilizer plant were severely flooded resulting in significant damage to the refinery assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The Company maintains property damage insurance which includes damage caused by a flood of up to $300 million per occurrence subject to deductibles and other limitations. The deductible associated with the property damage is $2.5 million.
Management is working closely with the Company’s insurance carriers and claims adjusters to ascertain the full amount of insurance proceeds due to the Company as a result of the damages and losses. The Company has recognized a receivable of approximately $85.3 million from insurance at December 31, 2007 which management believes is probable of recovery from the insurance carriers. While management believes that the Company’s property insurance should cover substantially all of the estimated total physical damage to the property, the Company’s insurance carriers have cited potential coverage limitations and defenses that might preclude such a result.
The Company’s insurance policies also provide coverage for interruption to the business, including lost profits, and reimbursement for other expenses and costs the Company has incurred relating to the damages and losses suffered for business interruption. This coverage, however, only applies to losses incurred after a business interruption of 45 days. Because the fertilizer plant was restored to operation within this45-day period and the refinery restarted its last operating unit in 48 days, a substantial portion of the lost profits incurred because of the flood cannot be claimed under insurance. The Company is assessing its policies to determine how much, if any, of its lost profits after the45-day period are recoverable. No amounts for recovery of lost profits under the Company’s business interruption policy have been recorded in the accompanying consolidated financial statements.
As of December 31, 2007, the Company has recorded pretax costs of approximately $41.5 million associated with the flood and related crude oil discharge as discussed in Note 15, “Commitments and Contingent Liabilities”, including $7.2 million in the fourth quarter of 2007. These amounts were net of
F-36
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
anticipated insurance recoveries of approximately $105.3 million. The components of the net costs as of December 31, 2007 include $3.6 million for uninsured losses within the Company’s insurance deductibles; $7.6 million for depreciation for the temporarily idled facilities; $6.8 million as a result of other uninsured expenses incurred which included salaries of $1.2 million, professional fees of $1.9 million and other miscellaneous amounts of $3.7 million. The $41.5 million net costs also included approximately $23.5 million recorded with respect to the environmental remediation and property damage as discussed in Note 15, “Commitments and Contingent Liabilities”. These costs are reported in “Net costs associated with flood” in the Consolidated Statements of Operations.
Total gross costs recorded due to the flood and related oil discharge that were included in the statement of operations for the year ended December 31, 2007 were approximately $146.8 million. Of these gross costs for the year ended December 31, 2007, approximately $101.9 million were associated with repair and other matters as a result of the flood damage to the Company’s facilities. Included in this cost was $7.6 million of depreciation for temporarily idled facilities, $6.1 million of salaries, $2.2 million of professional fees and $86.0 million for other repair and related costs. There were approximately $44.9 million costs recorded for the year ended December 31, 2007 related to the third party and property damage remediation as a result of the crude oil discharge. Total anticipated insurance recoveries of approximately $105.3 million were recorded and netted with the gross costs as of December 31, 2007. As of December 31, 2007, CVR had received insurance proceeds of $10.0 million under its property insurance policy, and an additional $10.0 million under its environmental policies related to the recovery of certain costs associated with the crude oil discharge. Subsequent to December 31, 2007, CVR received insurance proceeds of $1.5 million under the Builder’s Risk Insurance Policy. See Note 15, “Commitments and Contingent Liabilities” for additional information regarding environmental and other contingencies relating to the crude oil discharge that occurred on July 1, 2007. Accounts receivable from insurers for flood related matters approximated $85.3 million at December 31, 2007, for which we believe collection is probable, including $11.4 million related to the crude oil discharge and $73.9 million as a result of the flood damage to the Company’s facilities.
The Company anticipates that approximately $6.0 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods. Although the Company believes that it will recover substantial sums under its insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company ultimately receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements.
F-37
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Income tax expense (benefit) is comprised of the following (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | | |
| | | Predecessor | | | | Successor | |
| | | 174 Days
| | | | 233 Days
| | | Year
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| | | | | | | | | | | | | As restated(†) | |
| Current | | | | | | | | | | | | | | | | | |
| Federal | | $ | 26,145 | | | | $ | 29,000 | | | $ | 26,096 | | | $ | (26,814 | ) |
| State | | | 6,099 | | | | | 6,457 | | | | 6,974 | | | | (4,017 | ) |
| | | | | | | | | | | | | | | | | | |
| Total current | | | 32,244 | | | | | 35,457 | | | | 33,070 | | | | (30,831 | ) |
| | | | | | | | | | | | | | | | | | |
| Deferred | | | | | | | | | | | | | | | | | |
| Federal | | | 3,083 | | | | | (80,500 | ) | | | 69,836 | | | | (21,434 | ) |
| State | | | 721 | | | | | (17,925 | ) | | | 16,934 | | | | (36,250 | ) |
| | | | | | | | | | | | | | | | | | |
| Total deferred | | | 3,804 | | | | | (98,425 | ) | | | 86,770 | | | | (57,684 | ) |
| | | | | | | | | | | | | | | | | | |
| Total income tax expense (benefit) | | $ | 36,048 | | | | $ | (62,968 | ) | | $ | 119,840 | | | $ | (88,515 | ) |
| | | | | | | | | | | | | | | | | | |
The following is a reconciliation of total income tax expense (benefit) to income tax expense (benefit) computed by applying the statutory federal income tax rate (35%) to income before income tax expense (benefit) (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | | |
| | | Predecessor | | | | Successor | |
| | | 174 Days
| | | | 233 Days
| | | Year
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| | | | | | | | | | | | | As restated(†) | |
| Tax computed at federal statutory rate | | $ | 30,956 | | | | $ | (63,744 | ) | | $ | 108,994 | | | $ | (54,720 | ) |
| State income taxes, net of federal tax benefit (expense) | | | 4,433 | | | | | (7,454 | ) | | | 15,618 | | | | (6,382 | ) |
| State tax incentives, net of deferred federal tax expense | | | — | | | | | — | | | | (78 | ) | | | (19,792 | ) |
| Manufacturing activities deduction | | | (825 | ) | | | | (897 | ) | | | (1,089 | ) | | | — | |
| Federal tax credit for production of ultra-low sulfur diesel fuel | | | — | | | | | — | | | | (4,462 | ) | | | (17,259 | ) |
| Loss on unexercised option agreements with no tax benefit to Successor | | | — | | | | | 8,750 | | | | — | | | | — | |
| Non-deductible share based compensation | | | 1,395 | | | | | 349 | | | | 649 | | | | 8,771 | |
| Other, net | | | 89 | | | | | 28 | | | | 208 | | | | 867 | |
| | | | | | | | | | | | | | | | | | |
| Total income tax expense (benefit) | | $ | 36,048 | | | | $ | (62,968 | ) | | $ | 119,840 | | | $ | (88,515 | ) |
| | | | | | | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
F-38
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Certain provisions of the American Jobs Creation Act of 2004 Immediate Predecessor entered into(the Act) are providing federal income tax benefits to CVR. The Act created Internal Revenue Code section 199 which provides an agreement with a financial institutionincome tax benefit to domestic manufacturers. CVR recognized an income tax benefit related to this manufacturing deduction of approximately $825,000, $897,000, $1,089,000, and $0 for the 174 days ended June 23, 2005, the 233 days ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.
The Act also provides for a term loan of $21,900,000 with$0.05 per gallon income tax credit on compliant diesel fuel produced up to an interest rate based onamount equal to the greaterremaining 25% of the Index Rate (the greaterqualified capital costs. CVR recognized an income tax benefit of primeapproximately $4,462,000 and $17,259,000 on a credit of approximately $6,865,000 and $26,552,000 related to the production of ultra low sulfur diesel for the years ended December 31, 2006, and December 31, 2007, respectively.
The loss on unexercised option agreements of $25,000,000 in 2005 occurred at Coffeyville Acquisition LLC, and the tax deduction related to the loss was passed through to the partners of Coffeyville Acquisition LLC in the 233 days ended December 31, 2005.
The income tax effect of temporary differences that give rise to significant portions of the deferred income tax assets and deferred income tax liabilities at December 31, 2006 and 2007 are as follows:
| | | | | | | | | |
| | | December 31,
| | | December 31,
| |
| | | 2006 | | | 2007 | |
| | | | | | As restated(†) | |
| | | (in thousands) | |
| |
| Deferred income tax assets: | | | | | | | | |
| Allowance for doubtful accounts | | $ | 150 | | | $ | 156 | |
| Personnel accruals | | | 5,072 | | | | 12,757 | |
| Inventories | | | 673 | | | | 671 | |
| Unrealized derivative losses, net | | | 40,389 | | | | 85,650 | |
| Low sulfur diesel fuel credit carry forward | | | — | | | | 17,860 | |
| State net operating loss carry forwards, net of federal expense | | | — | | | | 4,158 | |
| Accrued expenses | | | 249 | | | | 1,713 | |
| Deferred revenue | | | — | | | | 3,403 | |
| State tax credit carryforward, net of federal expense | | | — | | | | 17,475 | |
| Other | | | — | | | | 353 | |
| | | | | | | | | |
| Total Gross deferred income tax assets | | | 46,533 | | | | 144,196 | |
| | | | | | | | | |
| Deferred income tax liabilities: | | | | | | | | |
| Property, plant, and equipment | | | (309,472 | ) | | | (348,902 | ) |
| Prepaid Expenses | | | (1,140 | ) | | | (3,233 | ) |
| Other | | | (1,155 | ) | | | — | |
| | | | | | | | | |
| Total Gross deferred income tax liabilities | | | (311,767 | ) | | | (352,135 | ) |
| | | | | | | | | |
| Net deferred income tax liabilities | | $ | (265,234 | ) | | $ | (207,939 | ) |
| | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
At December 31, 2007, CVR has net operating loss carryforwards for state income tax purposes of approximately $86.9 million, which are available to offset future state taxable income. The net operating loss carryforwards, if not utilized, will expire between 2012 and 2027.
F-39
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
At December 31, 2007, CVR has federal tax credit carryforwards related to the production of low sulfur diesel fuel of approximately $17.9 million, which are available to reduce future federal regular income taxes. These credits, if not used, will expire in 2027. CVR also has Kansas state income tax credits of approximately $26.9 million, which are available to reduce future Kansas state regular income taxes. These credits, if not used, will expire in 2017.
In assessing the realizability of deferred tax assets including net operating loss and credit carryforwards, management considers whether it is more likely than not that some portion or all of the federal funds rate plus 50 basis points per annum) plus 4.5%deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that CVR will realize the benefits of these deductible differences. Therefore, CVR has not recorded any valuation allowances against deferred tax assets as of December 31, 2006 or 9%December 31, 2007.
CVR adopted FIN 48 effective January 1, 2007. FIN 48 clarifies the accounting for uncertainty in income taxes recognized in the financial statements. If the probability of sustaining a tax position is at least more likely than not, then the tax position is warranted and a $100,000,000 revolving credit facility with interestrecognition should be at the borrower’s electionhighest amount which is greater than 50% likely of either the Index Rate plus 3% or the LIBOR rate plus 3.5%. Amounts totaling $21,900,000being realized upon ultimate settlement. As of the term loan borrowingsdate of adoption of FIN 48 and $38,821,970at December 31, 2007, CVR did not believe it had any tax positions that met the criteria for uncertain tax positions. As a result, no amounts were recognized as a liability for uncertain tax positions.
CVR recognizes interest and penalties on uncertain tax positions and income tax deficiencies in income tax expense. CVR did not recognize any interest or penalties in 2007 for uncertain tax positions or income tax deficiencies. At December 31, 2007, CVR’s tax returns are open to examination for federal and various states for the 2004 to 2007 tax years.
A reconciliation of the revolving credit facility were used to financeunrecognized tax benefits for the Initial Acquisition on March 3, 2004year ended December 31, 2007, is as described in note 1. Outstanding borrowings on May 10, 2004 were repaid in connection with the refinancing described below.follows:
| | | | | |
| Balance as of January 1, 2007 | | $ | 0 | |
| Increase and decrease in prior year tax positions | | | — | |
| Increases and decrease in current year tax positions | | | — | |
| Settlements | | | — | |
| Reductions related to expirations of statute of limitations | | | — | |
| | | | | |
| Balance as of December 31, 2007 | | $ | 0 | |
| | | | | |
Effective May 10, 2004, Immediate Predecessor entered into a term loan of $150,000,000 and a $75,000,000 revolving loan facility with a syndicate of banks, financial institutions, and institutional lenders. Both loans were secured by substantially all of the Immediate Predecessor’s real and personal property, including receivables, contract rights, general intangibles, inventories, equipment, and financial assets. There were outstanding borrowings of $148,875,000 and $56,510 at December 31, 2004, respectively. Outstanding borrowings on June 23, 2005 were repaid in connection with the Subsequent Acquisition as described in noteNote 1.
Effective June 24, 2005, Successor entered into a first lien credit facility and a guaranty agreement with two banks and one related party institutional lender (see note 15)Note 17). The credit facility iswas in an aggregate amount not to exceed $525,000,000, consisting of $225,000,000 Tranche B Term Loans; $50,000,000 of Delayed Draw Term Loans available for the first 18 months of the agreement and subject to accelerated payment terms; a $100,000,000 Revolving Loan Facility; and a Funded
F-40
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Letters of Credit Facility (Funded Facility) of $150,000,000. The credit facility iswas secured by substantially all of Successor’s assets. AtOutstanding borrowings on December 31, 2005, $224,437,500 of Tranche B Term Loans was outstanding, and there was no outstanding balance on28, 2006 were repaid in connection with the Revolving Loan Facility or the Delayed Draw Term Loans. At December 31, 2005, Successor had $150,000,000 in Funded Letters of Credit outstanding to secure payment obligations under derivative financial instruments (see note 14).refinancing described below.
The Term Loans and Revolving Loan Facility provideprovided CVR the option of a3-month LIBOR rate plus 2.5% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 1.5%). Interest iswas paid quarterly when using the Index Rate and at the expiration of the LIBOR term selected when using the LIBOR rate; interest variesvaried with the Index
F-23
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Rate or LIBOR rate in effect at the time of the borrowing. The interest rate on December 31, 2005 was 7.06%. The annual fee for the Funded Facility iswas 2.725% of outstanding Funded Letters of Credit.
Effective June 24, 2005, Successor entered into a second lien $275,000,000 term loan and guaranty agreement with a bank and a related party institutional lender (see note 15) with the entire amount outstanding at December 31, 2005.Note 17). CVR hashad the option of a3-month LIBOR rate plus 6.75% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 5.75%). The interest rate on December 31, 2005loan was 11.31%. The loan is secured by a second lien on substantially all of CVR’s assets. Outstanding borrowings on December 28, 2006 were repaid in connection with the refinancing described below.
On December 28, 2006, Successor entered into a second amended and restated credit and guaranty agreement (the credit and guaranty agreement) with two banks and one related party institutional lender (see Note 17). The credit facility was in an aggregate amount not to exceed $1,075,000,000, consisting of $775,000,000 Tranche D Term Loans; a $150,000,000 Revolving Loan Facility; and a Funded Facility of $150,000,000. The credit facility was secured by substantially all of CVR’s assets. At December 31, 2006, and December 31, 2007, $775,000,000 and $489,202,000 of Tranche D Term Loans was outstanding, and there was no outstanding balance on the Revolving Loan Facility. At December 31, 2006, and December 31, 2007, Successor had $150,000,000 in Funded Letters of Credit outstanding to secure payment obligations under derivative financial instruments (see Note 16).
At December 31, 2006, the Term Loan and Revolving Loan Facility provided CVR the option of a3-month LIBOR rate plus 3.0% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 2.0%). At December 31, 2007, the Term Loan and Revolving Loan Facility provide CVR the option of a3-month LIBOR rate plus 2.75% per annum (rounded up to the next whole multiple of 1/16 of 1%) or an Index Rate (to be based on the current prime rate plus 1.75%). Interest is paid quarterly when using the Index Rate and at the expiration of the LIBOR term selected when using the LIBOR rate; interest varies with the Index Rate or LIBOR rate in effect at the time of the borrowing. The interest rate on December 31, 2006 and December 31, 2007 was 8.36%and 7.98%, respectively. The annual fee for the Funded Facility was 3.225% and 2.975%, respectively at December 31, 2006 and December 31, 2007 of outstanding Funded Letters of Credit.
F-41
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
The loan and security agreements contain customary restrictive covenants applicable to CVR, including limitations on the level of additional indebtedness, commodity agreements, capital expenditures, payment of dividends, creation of liens, and sale of assets. These covenants also require CVR to maintain specified financial ratios as follows:
First Lien Credit Facility
| | | | | | | | | | | | |
| | | Second Lien CreditMinimum
|
First Lien Credit Facility | | Facility |
| | | | | Maximum
| | Maximum
|
| | | Minimum Interest
| | | LeverageMaximum
| | Leverage
|
Fiscal Quarter Ending | | Coverage Ratio | | | Leverage Ratio | | Ratio
|
|
March 31, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
June 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
September 30, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
December 31, 2006 | | | 2.25:1.00 | | | | 5.00:1.00 | | | | 5.25:1.00 | |
March 31, 2007 | | | 2.25:1.00 | | | | 4.75:1.00 | | | | 5.00:1.00 | |
June 30, 2007 | | | 2.50:1.00 | | | | 4.50:1.00 | | | | 4.75:1.00 | |
September 30, 2007 | | | 2.75:1.00 | | | | 4.25:1.00 | | | | 4.75:1.00 | |
December 31, 2007 | | | 3.00:1.00 | | | | 3.50:1.00 | | | | 4.00:1.00 | |
| March 31, 2008 | | | 3.25:1.00 | | | | 3.50:1.00 | | | | 4.00:3.25:1.00 | |
| June 30, 2008 | | | 3.25:1.00 | | | | 3.25:1.00 | | | | 3.75:3.00:1.00 | |
| September 30, 2008 | | | 3.25:1.00 | | | | 3.00:1.00 | | | | 3.50:2.75:1.00 | |
| December 31, 2008 | | | 3.25:1.00 | | | | 2.75:1.00 | | | | 3.25:2.50:1.00 | |
March 31, 2009 and thereafter— December 31, 2009 | | | 3.50:3.75:1.00 | | | | 2.50:2.25:1.00 | |
| March 31, 2010 and thereafter | | | 3.75:1.00 | | | | 3.00:2.00:1.00 | |
Failure to comply with the various restrictive and affirmative covenants of the loan agreements could negatively affect CVR’s ability to incur additional indebtednessand/or pay required distributions. Successor is required to measure its compliance with these financial ratios and covenants quarterly and was in compliance with all covenants and reporting requirements under the terms of the agreement at December 31, 2005.2006 and December 31, 2007. As required by the debt agreements, CVR has entered into interest rate swap agreements (as described in note 14)Note 16) that are required to be held for a minimumthe remainder of four years.the stated term.
F-24
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
Long-term debt at December 31, 2007 consisted of the following at December 31, 2005:future maturities (in thousands):
| | | | | |
| First lien Tranche B term loans; principal payments of .25% of the principal balance due quarterly commencing October 2005, increasing to 23.5% of the principal balance due quarterly commencing October 2011, with a final payment of the aggregate remaining unpaid principal balance due July 2012 | | $ | 224,437,500 | |
| Second lien term loan, due in full June 2013 | | | 275,000,000 | |
| | | | | |
| | | | 499,437,500 | |
| Less current portion | | | 2,235,973 | |
| | | | | |
| | | $ | 497,201,527 | |
| | | | | |
| | | | | | | | | |
| | | Year Ending
| | | | |
| | | December 31, | | | Amount | |
| |
| First lien Tranche D term loans; principal payments | | | 2008 | | | $ | 4,874 | |
| of .25% of the principal balance due quarterly | | | 2009 | | | | 4,825 | |
| commencing April 2007, increasing to 23.5% of the | | | 2010 | | | | 4,777 | |
| principal balance due quarterly commencing April 2013, | | | 2011 | | | | 4,730 | |
| with a final payment of the aggregate remaining unpaid | | | 2012 | | | | 4,682 | |
| principal balance due December 2013 | | | Thereafter | | | | 465,314 | |
| | | | | | | | | |
| | | | | | | $ | 489,202 | |
| | | | | | | | | |
Future maturitiesCommencing with fiscal year 2007, CVR shall prepay the loans in an aggregate amount equal to 75% of long-term debt are as follows:
| | | | | |
Year Ending December 31, | | Amount | |
| |
| 2006 | | $ | 2,235,973 | |
| 2007 | | | 2,213,697 | |
| 2008 | | | 2,191,642 | |
| 2009 | | | 2,169,808 | |
| 2010 | | | 2,148,191 | |
| Thereafter | | | 488,478,189 | |
| | | | | |
| | | $ | 499,437,500 | |
| | | | | |
Consolidated Excess Cash Flow (as defined in the credit and guaranty agreement, which includes a formulaic calculation consisting of many financial statement items, starting with consolidated Earnings Before Interest Taxes Depreciation and Amortization) less 100% of voluntary prepayments made during that fiscal year. Commencing with fiscal year 2008, the aggregate amount changes to 50% of Consolidated Excess Cash Flow provided the total leverage ratio is less than 1:50:1:00 or 25% of Consolidated Excess Cash Flow provided the total leverage ratio is less than 1:00:1:00.
At December 31, 2005,2007, Successor had $3.2$5.8 million in letters of credit outstanding to collateralize its environmental obligations, and state motor fuels tax obligations. The$30.6 million in letters of credit expire in July and August 2006. At December 31, 2005, Successor had a $22.6 million letter of credit outstanding to secure the purchasetransportation services for crude oil, and $3.0 million in support of crude oil. The letter of credit expired January 2006.surety bonds in place to support state and federal excise tax for refined fuels. These letters of credit were outstanding against the December 28, 2006 Revolving Loan Facility. The fee for the revolving letters of credit is 2.75%3.00%.
F-42
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
The Revolving Loan Facility has a current expiration date of December 28, 2012. The Funded Facility has a current expiration date of December 28, 2010.
As a result of the flood and crude oil discharge, the Company’s subsidiaries entered into three new credit facilities in August 2007. Coffeyville Resources, LLC entered into a $25 million senior secured term loan (the $25 million secured facility). The facility was secured by the same collateral that secures the Company’s existing Credit Facility. Interest was payable in cash, at the Company’s option, at the base rate plus 1.00% or at the reserve adjusted Eurodollar rate plus 2.00%. Coffeyville Resources, LLC also entered into a $25 million senior unsecured term loan (the $25 million unsecured facility). Interest was payable in cash, at the Company’s option, at the base rate plus 1.00% or at the reserve adjusted Eurodollar rate plus 2.00%. A subsidiary of Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., entered into a $75 million senior unsecured term loan (the $75 million unsecured facility). Drawings could be made from time to time in amounts of at least $5 million. Interest accrued, at the Company’s option, at the base rate plus 1.50% or at the reserve adjusted Eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued and was paid by adding such fees to the principal amount of loans outstanding.
All indebtedness outstanding under the $25 million secured facility and the $25 million unsecured facility was repaid in October 2007 with the proceeds of the Company’s initial public offering, and all three facilities were terminated at that time.
| |
(11)(13) | Pro Forma Earnings Per Share |
On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of its common stock. Also, in connection with the initial public offering, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of the subsidiaries of CALLC and CALLC II and all of its refinery and fertilizer assets. This reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholder, in conjunction with the merger of two newly formed direct subsidiaries of CVR. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding any non-vested shares issued. See Note 1, “Organization and History of Company”.
The computation of basic and diluted earnings per share for the years ended December 31, 2006 and December 31, 2007 are calculated on a pro forma basis assuming the capital structure in place after the completion of the offering was in place for the entire year for both 2006 and 2007.
F-43
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Pro forma earnings (loss) per share for the years ended December 31, 2006 and December 31, 2007 is calculated as noted below. For the year ended December 31, 2007, 17,500 non-vested common shares and 18,900 of common stock options have been excluded from the calculation of pro-forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive:
| | | | | | | | | |
| | | December 31 | |
| | | 2006 | | | 2007 | |
| | | (unaudited) | | | (unaudited)
| |
| | | | | | (As restated)(†) | |
| | | (in thousands) | |
| |
| Net income (loss) | | $ | 191,571 | | | $ | (67,618 | ) |
| Pro forma weighted average shares outstanding: | | | | | | | | |
| Original CVR common shares | | | 100 | | | | 100 | |
| Effect of 628,667.20 to 1 stock split | | | 62,866,620 | | | | 62,866,620 | |
| Issuance of common shares to management in exchange for subsidiary shares | | | 247,471 | | | | 247,471 | |
| Issuance of common shares to employees | | | 27,100 | | | | 27,100 | |
| Issuance of common shares in the initial public offering | | | 23,000,000 | | | | 23,000,000 | |
| | | | | | | | | |
| Basic weighted average shares outstanding | | | 86,141,291 | | | | 86,141,291 | |
| Dilutive securities — issuance of nonvested common shares to board of directors | | | 17,500 | | | | — | |
| | | | | | | | | |
| Diluted weighted average shares outstanding | | | 86,158,791 | | | | 86,141,291 | |
| | | | | | | | | |
| Pro forma basic earnings (loss) per share | | $ | 2.22 | | | $ | (0.78 | ) |
| Pro forma dilutive earnings (loss) per share | | $ | 2.22 | | | $ | (0.78 | ) |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
CVR sponsors two defined-contribution 401(k) plans (the Plans) for all employees. Participants in the Plans may elect to contribute up to 50% of their annual salaries, and up to 100% of their annual income sharing. CVR matches up to 75% of the first 6% of the participant’s contribution for the nonunion plan and 50% of the first 6% of the participant’s contribution for the union plan. Both plans are administered by CVR and contributions for the union plan are determined in accordance with provisions of negotiated labor contracts. Participants in both Plans are immediately vested in their individual contributions. Both Plans have a three year vesting schedule for CVR’s matching funds and contain a provision to count service with any predecessor organization. Successor’s contributions under the Plans were $647,054, $661,922,$662,000, $447,000, $1,375,000, and $446,753$1,513,000 for the 304 days ended December 31, 2004, the 174 days ended June 23, 2005, and the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively.
Coffeyville Acquisition LLC sponsors share-based compensation plans that participate in profit distributions, as described in note 4.
F-25F-44
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
Income tax expense (benefit) is summarized below (in thousands):
| | | | | | | | | | | | | | |
| | | Immediate Predecessor | | | | Successor | |
| | | 304 Days
| | | 174 Days
| | | | 229 Days
| |
| | | Ended
| | | Ended
| | | | Ended
| |
| | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2004 | | | 2005 | | | | 2005 | |
| Current — Federal | | $ | 27,902 | | | $ | 26,145 | | | | $ | 29,000 | |
| State | | | 6,519 | | | | 6,099 | | | | | 6,457 | |
| | | | | | | | | | | | | | |
| | | | 34,421 | | | | 32,244 | | | | | 35,457 | |
| | | | | | | | | | | | | | |
| Deferred — Federal | | | (499 | ) | | | 3,083 | | | | | (80,500 | ) |
| State | | | (117 | ) | | | 721 | | | | | (17,925 | ) |
| | | | | | | | | | | | | | |
| | | | (616 | ) | | | 3,804 | | | | | (98,425 | ) |
| | | | | | | | | | | | | | |
| Total income taxes | | $ | 33,805 | | | $ | 36,048 | | | | $ | (62,968 | ) |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Income tax expense differed from the expected income tax (computed by applying the federal income tax rate of 35% to income before income taxes) as follows (in thousands):
| | | | | | | | | | | | | | |
| | | Immediate Predecessor | | | | Successor | |
| | | 304 Days
| | | 174 Days
| | | | 229 Days
| |
| | | Ended
| | | Ended
| | | | Ended
| |
| | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2004 | | | 2005 | | | | 2005 | |
| Computed expected taxes | | $ | 29,230 | | | $ | 30,956 | | | | $ | (63,744 | ) |
| Loss on unexercised option agreements with no tax benefit to Successor | | | — | | | | — | | | | | 8,750 | |
| State taxes, net of federal benefit | | | 4,162 | | | | 4,433 | | | | | (7,454 | ) |
| Manufacturing deduction | | | — | | | | (825 | ) | | | | (897 | ) |
| Other, net | | | 413 | | | | 1,484 | | | | | 377 | |
| | | | | | | | | | | | | | |
| Total income tax expense | | $ | 33,805 | | | $ | 36,048 | | | | $ | (62,968 | ) |
| | | | | | | | | | | | | | |
As more fully described in note 14, the loss on unexercised option agreements of $25,000,000 occurred at Coffeyville Acquisition LLC, and the tax deduction related to the loss was passed through to the partners of Coffeyville Acquisition LLC.
The provision for income taxes for the year ended December 31, 2005 reflects an estimated benefit from a provision of the American Jobs Creation Act of 2004 (“the Act”). The Act created the new Internal Revenue Code section 199 which provides an income tax benefit to domestic manufacturers. The Company recognized an income tax benefit related to this manufacturing deduction of $825,011 and $896,890 for the 174 days ended June 23, 2005 and the 233 days ended December 31, 2005, respectively.
F-26
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
The income tax effect of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are summarized below (in thousands):
| | | | | | | | | | |
| | | Immediate
| | | | | |
| | | Predecessor | | | | Successor | |
| | | December 31,
| | | | December 31,
| |
| | | 2004 | | | | 2005 | |
| Deferred tax assets: | | | | | | | | | |
| Allowance for doubtful accounts | | $ | 74 | | | | $ | 109 | |
| Personnel accruals | | | 342 | | | | | 483 | |
| Inventories | | | 215 | | | | | 560 | |
| Environmental obligations | | | 166 | | | | | — | |
| Electricity contract | | | 229 | | | | | — | |
| Unrealized derivative losses | | | — | | | | | 91,226 | |
| | | | | | | | | | |
| Deferred tax assets | | | 1,026 | | | | | 92,378 | |
| | | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | | |
| Unrealized derivative gains | | | 326 | | | | | — | |
| Property, plant, and equipment | | | 84 | | | | | 269,462 | |
| Environmental obligations | | | — | | | | | 1,238 | |
| Other | | | — | | | | | 142 | |
| | | | | | | | | | |
| Deferred tax liabilities | | | 410 | | | | | 270,842 | |
| | | | | | | | | | |
| Net deferred tax assets (liabilities) | | $ | 616 | | | | $ | (178,464 | ) |
| | | | | | | | | | |
| | | | | | | | | | |
In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the level of historical taxable income and projections for future taxable income over the periods in which the deferred tax assets are deductible, management believes it is more likely than not that CVR will realize the benefits of these deductible differences. Therefore, Successor has not recorded any valuation allowances against deferred tax assets as of December 31, 2004 or 2005.
F-27
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| |
(13)(15) | Commitments and Contingent Liabilities |
The minimum required payments for CVR’s lease agreements and unconditional purchase obligations are as follows:follows (in thousands):
| | | | | | | | | | | | | | | | | |
Year Ending
| | Operating
| | Unconditional
| | |
December 31, | | Leases | | Purchase Obligations | | |
| | | Operating
| | Unconditional
| |
| 2006 | | $ | 3,654,956 | | | $ | 22,462,157 | | |
| 2007 | | | 3,445,287 | | | | 22,840,325 | | |
Year Ending December 31, | | | Leases | | Purchase Obligations | |
| | |
| 2008 | | | 3,354,004 | | | | 18,716,401 | | | | 4,207 | | | | 25,235 | |
| 2009 | | | 2,595,539 | | | | 18,685,325 | | | | 3,271 | | | | 25,249 | |
| 2010 | | | 1,259,805 | | | | 16,293,845 | | | | 1,679 | | | | 52,781 | |
| 2011 | | | | 947 | | | | 50,958 | |
| 2012 | | | | 195 | | | | 48,352 | |
| Thereafter | | | 644,669 | | | | 153,877,335 | | | | 10 | | | | 366,363 | |
| | | | | | | | | | | |
| | | $ | 14,954,260 | | | $ | 252,875,388 | | | $ | 10,309 | | | $ | 568,938 | |
| | | | | | | | | | | |
CVR leases various equipment and real properties under long-term operating leases. For the year ended December 31, 2003, the62-day period ended March 2, 2004, the304-day period ended December 31, 2004, the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, lease expense totaled approximately $2,985,022, $518,918, $2,531,823, $1,754,564,$1,755,000, $1,737,000, $3,822,000, and $1,737,373,$3,854,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
CVR licenses a gasification process from a third party associated with gasifier equipment used in the Nitrogen Fertilizer segment. The royalty fees for this license are incurred as the equipment is used and are subject to a cap which is expected to bewas paid in full by June 2007 at an estimated total cost of $5.5 million.in 2007. At December 31, 2006, approximately $1,615,000 was included in accounts payable for this agreement. Royalty fee expense reflected in costdirect operating expenses (exclusive of goods solddepreciation and amortization) for the304-day period ended December 31, 2004, the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 was $1,403,304, $1,042,286,$1,042,000, $915,000, $2,135,000, and $914,878,$1,035,000, respectively.
Coffeyville Resources Nitrogen Fertilizers LLC (CRNF)CRNF has an agreement with the City of Coffeyville pursuant to which it must make a series of future payments for electrical generation transmission and city margin. As of December 31, 2005,2007, the remaining obligations of CRNF totaled $31.8$19.6 million through December 31, 2019. Total minimum annual committed contractual payments under the agreement will be $5.7 million for each of the fiscal years 2006 and 2007 and $1.7 million per year for each subsequent year. Successor is contractually liable for payments to Farmland, as part of deferred purchase consideration related to the electricity contract with the City of Coffeyville. As of December 31, 2005, approximately $750,000 remains to be paid in equal monthly installments of approximately $83,000 each through September 2006.million.
Coffeyville Resources Refining and Marketing, LLC (CRRM)CRRM has a Pipeline Construction, Operation and Transportation Commitment Agreement with Plains Pipeline, L.P. (Plains Pipeline) pursuant to which Plains Pipeline constructed a crude oil pipeline from Cushing, Oklahoma to Caney, Kansas. The term of the agreement is 20 years from when the pipeline became operational on March 1, 2005. Pursuant to the agreement, CRRM must transport approximately 80,000 barrels per day of its crude oil requirements for the Coffeyville refinery at a fixed charge per barrel for the first five years of the agreement. For the final fifteen years of the agreement, CRRM must transport all of its non-gathered crude oil up to the capacity of the Plains Pipeline. The rate is subject to a Federal Energy Regulatory Commission (FERC) tariff and is subject to change on an annual basis per the agreement. Lease expense associated with this agreement and included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the
F-28
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 totaled approximately $2,603,066$2,603,000, $4,372,000, $8,751,000, and $4,372,115,$7,214,000, respectively.
During 1997, Farmland (subsequently assigned to CRRM)CRP) entered into an Agreement of Capacity Lease and Operating Agreement with Williams Pipe Line Company (subsequently assigned to Magellan Pipe Line Company, L.P. (Magellan)) pursuant to which CRRMCRP leases pipeline capacity in certain pipelines between Coffeyville, Kansas and Caney, Kansas and between Coffeyville, Kansas and Independence,
F-45
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Kansas. Pursuant to this agreement, CRRM isCRP was obligated to pay a fixed monthly charge to Magellan for annual leased capacity of 6,300,000 barrels until the scheduled expiration of the agreement on April 30, 2007. Lease expense associated with this agreement and included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 totaled approximately $232,500$233,000, $194,000, $504,000, and $193,750,$116,000, respectively.
During 2005, CRRM amended a Pipeline Capacity Lease Agreement withMid-America Pipeline Company (MAPL) pursuant to which CRRM leases pipeline capacity in an outbound MAPL-operated pipeline between Coffeyville, Kansas and El Dorado, Kansas for the transportation of natural gas liquids (NGLs) and refined petroleum products. Pursuant to this agreement, CRRM is obligated to make fixed monthly lease payments. The agreement also obligates CRRM to reimburse MAPL a portion of certain permitted costs associated with obligations imposed by certain governmental laws. Lease expense associated with this agreement, included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $156,271,$156,000, $208,000, $800,000, and $208,316,$800,000, respectively. The lease expires September 30, 2011.
During 2005, CRRM entered into a Pipeage Contract with MAPL pursuant to which CRRM agreed to ship a minimum quantity of NGLs on an inbound pipeline operated by MAPL between Conway, Kansas and Coffeyville, Kansas. Pursuant to the contract, CRRM is obligated to ship 2,000,000 barrels (Minimum Commitment) of NGLs per year at a fixed rate per barrel through the expiration of the contract on September 30, 2011. All barrels above the Minimum Commitment are at a different fixed rate per barrel. The rates are subject to a tariff approved by the Kansas Corporation Commission (KCC) and are subject to change throughout the term of this contract as ordered by the KCC. Lease expense associated with this contract agreement and included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $172,525.$173,000, $1,613,000, and $1,400,000, respectively.
During 2004, CRRM entered into a Pipeline Capacity Lease Agreement with ONEOK Field Services (OFS) and Frontier El Dorado Refining Company (Frontier) pursuant to which CRRM leases capacity in pipelines operated by OFS between Conway, Kansas and El Dorado, Kansas. Prior to the completion of a planned expansion project specified in the agreement, CRRM will be obligated to pay a fixed monthly charge which will increase after the expansion is complete. The lease expires September 30, 2011. It is estimatedLease expense associated with this contract agreement and included in cost of product sold (exclusive of depreciation and amortization) for the pipeline will be operational in the second quarter of 2006.year ended December 31, 2007 totaled approximately $444,000.
During 2004, CRRM entered into a Transportation Services Agreement with CCPS Transportation, LLC (CCPS) pursuant to which CCPS reconfigured an existing pipeline (Spearhead Pipeline) to transport Canadian sourced crude oil to Cushing, Oklahoma. The term of the agreement is 10 years from the time the pipeline becomes operational, which occurred March 1, 2006. Pursuant to the agreement and pursuant to options for increased capacity which CRRM has exercised, CRRM is obligated to pay an incentive tariff, which is a fixed rate per barrel for a minimum of 10,000 barrels per day. Lease expense associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled approximately $4,609,000 and $6,980,000, respectively.
During 2004, CRRM entered into a Terminalling Agreement with Plains Marketing, LP (Plains) whereby CRRM has the exclusive storage rights for working storage, blending, and terminalling services at several Plains tanks in Cushing, Oklahoma. During 2007, CRRM entered into an Amended
F-46
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
and Restated Terminalling Agreement with Plains that replaced the 2004 agreement. Pursuant to the agreement,Amended and Restated Terminalling Agreement, CRRM is obligated to pay fees on a minimum throughput volume commitment of 29,200,000 barrels per year. This rate
F-29
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
isFees are subject to change annually based on changes in the Consumer Price Index (CPI-U) and the Producer Price Index (PPI-NG). Expenses associated with this agreement, included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, totaled approximately $811,815$812,000, $1,251,000, $2,406,000, and $1,251,087,$2,396,000, respectively. The agreementoriginal term of the Amended and Restated Terminalling Agreement expires December 31, 2009.2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement. Concurrently with the above-described Amended and Restated Terminalling Agreement, CRRM entered into a separate Terminalling Agreement with Plains whereby CRRM has obtained additional exclusive storage rights for working storage and terminalling services at several Plains tanks in Cushing, Oklahoma. CRRM is obligated to pay Plains fees based on the storage capacity of the tanks involved, and such fees are subject to change annually based on changes in the Producer Price Index (PPI-FG and PPI-NG). The term of the Terminalling Agreement is split up into two periods based on the tanks at issue, with the term for half of the tanks commencing once they are placed in service (but no later than January 1, 2008), and the term for the remaining half of the tanks commencing October 1, 2008. The original term of the Terminalling Agreement for both sets of tanks expires December 31, 2014, but is subject to annual automatic extensions of one year beginning two years and one day following the effective date of the agreement, and successively every year thereafter unless either party elects not to extend the agreement.
During 2005 CRNF entered into athe Amended and Restatedon-siteOn-Site product supply agreementProduct Supply Agreement with the BOC Group, Inc.The Linde Group. Pursuant to the agreement, which expires in 2020, CRNF paysis required to take as available and pay approximately $300,000 per month, which amount is subject to annual inflation adjustments, for the supply of oxygen and nitrogen to the fertilizer operation. Expenses associated with this agreement, included in direct operating expenses (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007, totaled approximately $3,521,000 and $3,136,000, respectively.
EffectiveDuring 2006, CRRM entered into a Lease Storage Agreement with TEPPCO Crude Pipeline, L.P. (TEPPCO) whereby CRRM leases 400,000 barrels of shell capacity at TEPPCO’s Cushing tank farm in Cushing, Oklahoma. In September 2006, CRRM exercised its option to increase the shell capacity leased at the facility subject to this agreement from 400,000 barrels to 550,000 barrels. Pursuant to the agreement, CRRM is obligated to pay a monthly per barrel fee regardless of the number of barrels of crude oil actually stored at the leased facilities. Expenses associated with this agreement included in cost of product sold (exclusive of depreciation and amortization) for the year ended December 31, 2005,2007 totaled approximately $1,110,000.
During 2006, CRCT entered into a crude oil SupplyPipeline Lease Agreement with Magellan whereby CRCT leases sixty-two miles of eight inch pipeline extending from Humboldt, Kansas to CRCT’s facilities located in Broome, Kansas. Pursuant to the lease agreement, CRCT agrees to operate and maintain the leased pipeline and agrees to pay Magellan a fixed annual rental in advance. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled approximately $76,000 and $183,000, respectively. Pursuant to an amendment entered into in 2007, the lease agreement expires on July 31, 2009 with, at the Company’s option, up to two one year extensions.
During 2006, CRRM entered into a Transfer Agreement with Magellan pursuant to which CRRM obtained the right to capacity in a pipeline operated by Magellan between Coffeyville, Kansas and El
F-47
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Dorado, Kansas. Pursuant to the agreement, CRRM is obligated to pay a fixed monthly charge for the right to transfer up to 1,000,000 barrels per year through the pipeline. The initial term of the agreement expires on July 14, 2009; however the agreement contains two successive one year additional terms unless CRRM or Magellan provides termination notice as required in the agreement. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciation and amortization) for the year ended December 31, 2007 totaled approximately $79,000.
During 2007, CRRM executed a Petroleum Transportation Service Agreement with TransCanada Keystone Pipeline, LP (TransCanada). TransCanada is proposing to construct, own and operate a pipeline system and a related extension and expansion of the capacity that would terminate near Cushing, Oklahoma. TransCanada has agreed to transport a contracted volume amount of at least 25,000 barrels per day with a Cushing Delivery Point as the contract point of delivery. The contract term is a 10 year period which will commence upon the completion of the pipeline system. The expected date of commencement is March 2010 with termination of the transportation agreement estimated to be February 2020. The Company will pay a fixed and variable toll rate beginning during the month of commencement.
CRNF entered into a sales agreement with Supplier A expiredCominco Fertilizer Partnership on November 20, 2007 to purchase equipment and was replaced bymaterials which comprise a new crude oil supply agreement with Supplier B (see note 17). Supplier A has initiated discussions with CRRM concerning alleged certain crude oil losses and other charges which Supplier A claims were eligiblenitric acid plant. CRNF’s obligation related to be passed through to CRRM under the termsexecution of the expired agreement. Supplier A has not filed a formal claim and CRRM does not believe based on current information thatagreement in 2007 for the losses and other charges can be passed through to CRRM. Accordingly, a liability has not been recognized for these losses and other charges aspurchase of the assets was $3,500,000. As of December 31, 2005.2007, $250,000 had been paid with $3,250,000 remaining as an accrued current obligation. Additionally, $3,000,000 was accrued related to the obligation to dismantle the unit. These amounts incurred are included inconstruction-in-progress at December 31, 2007. The total unpaid obligation at December 31, 2007 of $6,250,000 is included in other current liabilities on the Consolidated Balance Sheet.
As a result of the adoption of FIN 47 in 2005, CVR recorded a net asset retirement obligation of $636,000 which was included in other current liabilities at December 31, 2006 and December 31, 2007.
From time to time, CVR is involved in various lawsuits arising in the normal course of business, including matters such as those described below under, “Environmental, Health, and Safety Matters,” and those described above. Liabilities related to such litigation are recognized when the related costs are probable and can be reasonably estimated. Management believes the company has accrued for losses for which it may ultimately be responsible. It is possible management’s estimates of the outcomes will change within the next year due to uncertainties inherent in litigation and settlement negotiations. In the opinion of management, the ultimate resolution of any other litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements.
Crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. As a result of the crude oil discharge, two putative class action lawsuits (one federal and one state) were filed seeking unspecified damages with class certification under applicable law for all residents, domiciliaries and property owners of Coffeyville, Kansas who were impacted by the oil release.
The Company filed a motion to dismiss the federal suit for lack of subject matter jurisdiction. On November 6, 2007, the judge in the federal class action lawsuit granted the Company’s motion to dismiss for lack of subject matter jurisdiction and no appeal was taken.
The District Court of Montgomery County, Kansas conducted an evidentiary hearing on the issue of class certification on October 24 and 25, 2007 and ruled against the class certification leaving only the original two plaintiffs. To date no other lawsuits have been filed as a result of flood related damages.
As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (the Consent Order) with the EPA on July 10, 2007. As set forth in
F-48
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
the Consent Order, the EPA concluded that the discharge of oil from the Company’s refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The Company is currently remediating the crude oil discharge and expects its remedial actions to continue until May 2008.
The Company engaged experts to assess and test the areas affected by the crude oil spill. The Company commenced a program on July 19, 2007 to purchase approximately 330 homes and other commercial properties in connection with the flood and the crude oil release. The costs recorded as of December 31, 2007 related to the obligation of the homes being purchased, were approximately $13.1 million, and are included in “Net Costs Associated With Flood” in the accompanying consolidated statement of operations. Costs recorded related to personal property claims were approximately $1.7 million as of December 31, 2007. The costs recorded related to estimated commercial property to be purchased and associated claims were approximately $3.6 million as of December 31, 2007. The total amount of gross costs recorded for the twelve months ended December 31, 2007 related to the residential and commercial purchase and property claims program were approximately $18.4 million.
As of December 31, 2007, the total gross costs recorded for obligations other than the purchase of homes, commercial properties, and related personal property claims, approximated $26.5 million. The Company has recorded as of December 31, 2007, total costs (net of anticipated insurance recoveries recorded of $21.4 million) associated with remediation and third party property damage claims resolution of approximately $23.5 million. The Company has not estimated or accrued for, because management does not believe it is probable that there will be any, potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from class action lawsuits related to the flood.
It is difficult to estimate the ultimate cost of environmental remediation resulting from the crude oil discharge or the cost of third party property damage that the Company will ultimately be required to pay. The costs and damages that the Company will ultimately pay may be greater than the amounts described and projected above. Such excess costs and damages could be material to the consolidated financial statements.
The Company is seeking insurance coverage for this release and for the ultimate costs for remediation, property damage claims, cleanup, resolution of class action lawsuits, and other claims brought by regulatory authorities. Although the Company believes that it will recover substantial sums under its environmental and liability insurance policies, the Company is not sure of the ultimate amount or timing of such recovery because of the difficulty inherent in projecting the ultimate resolution of the Company’s claims. The difference between what the Company receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements. The Company has received $10 million of insurance proceeds under its environmental insurance policy as of December 31, 2007.
As a result of the 2007 flood the refinery was not able to meet the annual average sulfur standard required in its “hardship waiver.” Management had provided timely notice to the EPA that the Company would not be able to meet the waiver requirement for 2007. Ordinarily, a refiner would purchase sulfur credits to meet the standard requirement. However, the Company’s “hardship waiver” does not allow sulfur credits to be used in 2006 and 2007. The Company has been working with the EPA to resolve the matter. In anticipation of settlement, the refinery purchased $3.6 million worth of sulfur credits that would equal the amount of sulfur by which the Company exceeded the limit imposed by the “hardship waiver.” The Company will either use the credits by applying them towards its gasoline pool account or it will permanently retire the credits as part of the settlement. Because of the extraordinary nature of the 2007 flood, management does not anticipate the imposition of fines or penalties to resolve this matter.
F-49
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Environmental, Health, and Safety (EHS) Matters
CVR is subject to various stringent federal, state, and local EHS rules and regulations. Liabilities related to EHS matters are recognized when the related costs are probable and can be reasonably estimated. Estimates of these costs are based upon currently available facts, existing technology, site-specific costs, and currently enacted laws and regulations. In reporting EHS liabilities, no offset is made for potential recoveries. Such liabilities include estimates of CVR’s share of costs attributable to potentially responsible parties which are insolvent or otherwise unable to pay. All liabilities are monitored and adjusted regularly as new facts emerge or changes in law or technology occur.
CVR ownsand/or operates manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.
Through an Administrative Order issued to Original Predecessor under the Resource Conservation and Recovery Act, as amended (RCRA), CVR is a potential party responsible for conducting corrective actions at its Coffeyville, Kansas and Phillipsburg, Kansas facilities. In 2005, Coffeyville Resources Nitrogen Fertilizers, LLCCRNF 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, 20042006 and 2005,December 31, 2007, environmental accruals of $10,310,600$7,223,000 and $8,220,338,$7,646,000, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Order and the VCPRP, including amounts totaling $1,209,663$1,828,000 and $1,211,000,
F-30
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
$2,802,000, respectively, included in other current liabilities. The Immediate Predecessor and Successor accruals were determined based on an estimate of payment costs through 2033, which scope of remediation was arranged with the Environmental Protection Agency (the EPA)EPA and are discounted at the appropriate risk free rates at December 31, 20042006 and 2005,December 31, 2007, respectively. The accruals include estimated closure and post-closure costs of $1,975,100$1,857,000 and $1,812,000$1,549,000 for two landfills at December 31, 20042006 and 2005,December 31, 2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):
| | | | | | | | | |
Year Ending December 31, | | Amount | | | Amount | |
| |
| 2006 | | $ | 1,211 | | |
| 2007 | | | 1,712 | | |
| 2008 | | | 616 | | | $ | 2,802 | |
| 2009 | | | 508 | | | | 687 | |
| 2010 | | | 473 | | | | 1,556 | |
| 2011 | | | | 313 | |
| 2012 | | | | 313 | |
| Thereafter | | | 6,798 | | | | 3,282 | |
| | | | | | | |
| Undiscounted total | | | 11,318 | | | | 8,953 | |
| Less amounts representing interest at 4.51% | | | 3,098 | | |
| Less amounts representing interest at 3.90% | | | | 1,307 | |
| | | | | | | |
| Accrued environmental liabilities at December 31, 2005 | | $ | 8,220 | | |
| Accrued environmental liabilities at December 31, 2007 | | | $ | 7,646 | |
| | | | | | | |
CVR has purchased insurance (see note 9) to cover costs above accrued amounts related to this contaminated property. Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of sulfur in diesel and gasoline. The EPA has granted Original Predecessor’s petition for a technical hardship waiver with respect to the date for compliance in meeting the sulfur-lowering standards. Immediate Predecessor and Successor spent approximately $2 million in 2004 and $27 million in 2005, $79 million in 2006, and $17 million in 2007, and based on information currently available, CVR anticipates spending approximately $83$29 million in 2006, $22008, $11 million in 2007,2009, and $6
F-50
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
$6 million in 20082010 to comply with the low-sulfur rules. The entire amounts are expected to be capitalized.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the year ended December 31, 2003, the62-day period ended March 2, 2004, the304-day period ended December 31, 2004, the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007 capital expenditures were approximately $334,235, $0, $2,563,295, $6,065,713,$6,066,000, $20,165,000, $144,794,000, and $20,165,483,$122,341,000, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.
CVR believes it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the business, financial condition, or results of operations.
| |
(14)(16) | Derivative Financial Instruments |
Gain (loss) on derivatives consisted of the following (in thousands):
| | | | | | | | | | | | | | | | | | |
| | | Predecessor | | | | Successor | |
| | | 174 Days
| | | | 233 Days
| | | Year
| |
| | | Ended June 23, | | | | Ended December 31, | | | Ended December 31, | |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| Realized loss on swap agreements | | $ | — | | | | $ | (59,301 | ) | | $ | (46,769 | ) | | $ | (157,239 | ) |
| Unrealized gain (loss) on swap agreements | | | — | | | | | (235,852 | ) | | | 126,771 | | | | (103,212 | ) |
| Loss on termination of swap | | | — | | | | | (25,000 | ) | | | — | | | | — | |
| Realized gain (loss) on other agreements | | | (7,665 | ) | | | | (1,868 | ) | | | 8,361 | | | | (15,346 | ) |
| Unrealized gain (loss) on other agreements | | | — | | | | | (1,696 | ) | | | 2,412 | | | | (1,348 | ) |
| Realized gain (loss) on interest rate swap agreements | | | — | | | | | (104 | ) | | | 4,398 | | | | 4,115 | |
| Unrealized gain (loss) on interest rate swap agreements | | | — | | | | | 7,759 | | | | (680 | ) | | | (8,948 | ) |
| | | | | | | | | | | | | | | | | | |
| Total gain (loss) on derivatives | | $ | (7,665 | ) | | | $ | (316,062 | ) | | $ | 94,493 | | | $ | (281,978 | ) |
| | | | | | | | | | | | | | | | | | |
CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil and other inventories and to fix margins on certain future production, the EntitiesCompany may enter into various derivative transactions. In addition, the Successor, as further described below, entered into certain
F-31
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
commodity derivate contracts and an interest rate swap as required by the long-term debt agreements.
For purposes of these financial statements, CVR has adopted Statement of Financial Accounting StandardsSFAS No. 133,Accounting for Derivative Instruments and Hedging Activities, (SFAS 133). SFAS 133which 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, certainover-the-counter forward swap agreements, and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss) on derivatives.
F-51
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
At December 31, 2005, Successor’s2007, CVR’s Petroleum Segment held commodity derivative contracts (swap agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see note 15)Note 17). The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of the Immediate Predecessor and required under the terms of the long-term debt agreements. The notional quantities on the date of execution were 100,911,000 barrels of crude oil; 2,348,802,750 gallons of heating oilunleaded gasoline and 1,889,459,250 gallons of unleaded gasoline.heating oil. The swap agreements were executed at the prevailing market rate at the time of execution and Management believes the swap agreements provide an economic hedge on future transactions. At December 31, 20052007 the notional open amounts under the swap agreements were 88,951,00042,309,750 barrels of crude oil; 2,097,642,750888,504,750 gallons of unleaded gasoline and 888,504,750 gallons of heating oil and 1,638,229,250 gallons of unleaded gasoline. At December 31, 2005, theseoil. These positions resulted in unrealized lossesgains (losses) for the233-day period ended December 31, 2005 and the years ended December 31, 2006 and December 31, 2007 of $235,851,568$(235,852,000), $126,771,000 and $(103,212,000), respectively, using a valuation method that utilizes quoted market prices and assumptions for the estimated forward yield curves of the related commodities in periods when quoted market prices are unavailable. DuringThe Petroleum Segment recorded $(59,301,000), $(46,769,000) and $(157,239,000) in realized (losses) on these swap agreements for the 233 days233-day period ended December 31, 2005, and the Petroleum Segment recorded $59,300,670 in realized losses on these swap agreements.years ended December 31, 2006 and December 31, 2007, respectively.
Successor entered certain crude oil, heating oil, and gasoline option agreements with a related party (see notesNotes 1 and 15)17) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 233 days ended December 31, 2005.
CVR has recorded margin account balances in cash and cash equivalents of $8,373,417 and $1,540,952 at December 31, 2004 and 2005, respectively. The Petroleum Segment also recordedmark-to-market net gains (losses), exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, in gain (loss) on derivatives of $303,742, $0 $(7,665,000), $546,604, $(7,664,725)$(3,564,000), $10,773,000, and $(3,565,153),$(16,694,000) for the year ended December 31, 2003, the62-day period ended March 2, 2004, the304-day period ended December 31, 2004, the174-day period ended June 23, 2005, and the233-day period ended December 31, 2005, the years ended December 31, 2006, and December 31, 2007, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.
At December 31, 2005, Successor2007, CVR held derivative contracts known as interest rate swap agreements that converted Successor’s floating-rate bank debt (see note 10)Note 12) into 3.835%4.195% fixed-rate debt on a notional amount of $375,000,000. Half of the agreements are held with a related party (as
F-32
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
described in note 15)Note 17), and the other half are held with a financial institution that is a lender under CVR’s long-term debt agreements. The swap agreements carry the following terms:
| | | | | | | | | |
| | | Notional
| | | Fixed
| |
Period Covered | | Amount | | | Interest Rate |
| |
June 30, 2005 to June 30, 2006 | | $ | 375 million | | | | 3.835 | % |
June 30, 2006 to June 30, 2007 | | | 325 million | | | | 4.038 | % |
| June 30, 2007 to March 31, 2008 | | | 325 million | | | | 4.195 | % |
| March 31, 2008 to March 31, 2009 | | | 250 million | | | | 4.195 | % |
| March 31, 2009 to March 31, 2010 | | | 180 million | | | | 4.195 | % |
| March 31, 2010 to June 30, 2010 | | | 110 million | | | | 4.195 | % |
CVR pays the fixed rates listed above and receives a floating rate based on three-month LIBOR rates, with payments calculated on the notional amounts listed above. The notional amounts do not represent actual amounts exchanged by the parties but instead represent the amounts on which the contracts are based. The swap is settled quarterly and marked to market at each reporting date, and all unrealized gains and losses are currently recognized in income. Transactions related to the interest rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments.Mark-to-market net gains (losses) on derivatives and quarterly settlements were $7,655,280$7,655,000, $3,718,000 and $(4,833,000) for the233-day period ended December 31, 2005.2005 and the years ended December 31, 2006 and December 31, 2007, respectively.
F-52
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| |
(15)(17) | Related Party Transactions |
Pegasus Partners II, L.P. (Pegasus) was a majority owner of Immediate Predecessor.
On March 3, 2004, Immediate Predecessor entered into a management services agreement with an affiliate company of Pegasus, Pegasus Capital Advisors, L.P. (Affiliate) pursuant to which Affiliate provided Immediate Predecessor with managerial and advisory services. AmountsAn amount totaling approximately $545,000 and $1,000,000 relating to the agreement were expensed in selling, general, and administrative expenses for the 304 days ended December 31, 2004(exclusive of depreciation and amortization) for the 174 days ended June 23, 2005, respectively. Immediate Predecessor expensed approximately $455,000 in selling, general and administrative expenses for legal fees paid on behalf of Affiliate in lieu of the remaining amounts owed under the management services agreement for the 304 days ended December 31, 2004.
Immediate Predecessor paid Affiliate a $4.0 million transaction fee upon closing of the Initial Acquisition referred to in note 1. The transaction fee relates to a $2.5 million finder’s fee included in the cost of the Initial Acquisition and $1.5 million in deferred financing costs. The deferred financing cost was subsequently written off in May 2004 as part of the refinancing. In conjunction with the debt refinancing on May 10, 2004, a $1.25 million fee was paid to Affiliate as a deferred financing cost and was subsequently written-off immediately prior to the Subsequent Acquisition.2005.
GS Capital Partners V Fund, L.P. and related entities (GS or Goldman Sachs Funds) and Kelso Investment Associates VII, L.P. and related entity (Kelso or Kelso Funds) are majority owners of Successor.CVR.
SuccessorCVR paid companies related to GS and Kelso each equal amounts totaling $6.0 million for transaction fees related to the Subsequent Acquisition, as well as an additional $0.7 million paid to GS for reimbursed expenses related to the Subsequent Acquisition. These expenditures were included in the cost of the Subsequent Acquisition referred to in noteNote 1.
F-33
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
An affiliate of GS is one of the lenders in conjunction with the financing of the Subsequent Acquisition. SuccessorThe Company paid this affiliate of GS a $22.1 million fee included in deferred financing costs. For the 233 days ended December 31, 2005, Successor made interest payments of $1.8 million recorded in interest expense and other financial costs and paid letter of credit fees of approximately $155,000 recorded in selling, general, and administrative expenses (exclusive of depreciation and amortization), to this affiliate of GS. Additionally, a fee in the amount of $125,000 was paid to this affiliate of GS for assistance with modification of the credit facility in June 2006.
An affiliate of GS is one of the lenders in conjunction with the refinancing that occurred on December 28, 2006. The Company paid this affiliate of GS a $8,063,000 million fee and expense reimbursements of $78,000 included in deferred financing costs.
On June 24, 2005, SuccessorCALLC entered into a management services agreementagreements with each of GS and Kelso pursuant to which GS and Kelso agreed to provide SuccessorCALLC with managerial and advisory services. In consideration for these services, an annual fee of $1.0 million each iswas paid to GS and Kelso, plus reimbursement for anyout-of-pocket expenses. The agreement hasagreements had a term ending on the date GS and Kelso ceaseceased to own any interests in Successor.CALLC. Relating to the agreement, $1,310,416 wasagreements, $1,310,000, $2,316,000 and $1,704,000 were expensed in selling, general, and administrative expenses (exclusive of depreciation and amortization) for the 233 days ended December 31, 2005. In addition, $1,046,575 was included in other current liabilities2005, and approximately $78,671 was included in accounts payable atthe years ended December 31, 2005.2006 and December 31, 2007, respectively. The agreements terminated upon consummation of CVR’s initial public offering on October 26, 2007. The Company paid a one-time fee of $5 million to each of GS and Kelso by reason of such termination on October 26, 2007.
SuccessorCALLC entered into certain crude oil, heating oil, and gasoline swap agreements with a subsidiary of GS. The original swap agreements were entered into on May 16, 2005 (as described in note 1) and were terminated on June 16, 2005, resulting in a $25 million loss on termination of swap agreements for the 233 days ended December 31, 2005. Additional swap agreements with this subsidiary of GS were entered into on June 16, 2005, with an expiration date of June 30, 2010 (as described in note 14)Note 16). Amounts totaling $297,010,762$(297,011,000), $80,002,000, and $(260,451,000) were expensedreflected in gain (loss) on derivatives related to these swap agreements for the 233 days ended December 31, 2005, and are reflected in loss on derivatives.the years ended December 31, 2006 and December 31, 2007, respectively. In addition, the consolidated balance sheet at December 31, 20052006 and December 31, 2007 includes liabilities of $96,688,956$36,895,000 and $262,415,000 included in current payable to swap counterparty and $160,033,333$72,806,000 and $88,230,000 included in long-term payable to swap counterparty, respectively.
On June 26, 2007, the Company entered into a letter agreement with the subsidiary of GS to defer a $45.0 million payment owed on July 8, 2007 to the GS subsidiary for the period ended
F-53
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
September 30, 2007 until August 7, 2007. Interest accrued on the deferred amount of $45.0 million at the rate of LIBOR plus 3.25%.
As a result of the flood and the related temporary cessation of business operations, the Company entered into a subsequent letter agreement on July 11, 2007 in which the GS subsidiary agreed to defer an additional $43.7 million of the balance owed for the period ending June 30, 2007. This deferral was entered into on the conditions that each of GS and Kelso each agreed to guarantee one half of the payment and that interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter agreement in which the GS subsidiary agreed to defer to September 7, 2007 both the $45.0 million payment due August 7, 2007 along with accrued interest and the $43.7 million payment due July 25, 2007 with the related accrued interest. These payments were deferred on the conditions that GS and Kelso each agreed to guarantee one half of the payments. Additionally, interest accrues on the amount from July 26, 2007 to the date of payment at the rate of LIBOR plus 1.50%.
On August 23, 2007, the Company entered into an additional letter agreement in which the GS subsidiary agreed to further defer both deferred payment amounts and the related accrued interest with payment being due on January 31, 2008. Additionally, it was further agreed that the $35 million payment to settle hedged volumes through August 15, 2007 would be deferred with payment being due on January 31, 2008. Interest accrues on all deferral amounts through the payment due date at LIBOR plus 1.50%. GS and Kelso have each agreed to guarantee one half of all payment deferrals. The GS Subsidiary further agreed to defer these payment amounts to August 31, 2008 if the Company closed an initial public offering prior to January 31, 2008. Due to the consummation of the initial public offering on October 26, 2007, these payment amounts are now deferred until August 31, 2008; however, the company is required to use 37.5% of its consolidated excess cash flow for any quarter after January 31, 2008 to prepay the deferral amounts.
These deferred payment amounts are included in the consolidated balance sheet at December 31, 2007 in current payable to swap counterparty. Interest relating to the deferred payment amounts reflected in interest expense and other financial costs for the year ended December 31, 2007 was $3,625,000. $3,625,000 is also included in other current liabilities at December 31, 2007.
On June 30, 2005, SuccessorCVR entered into three interest-rate swap agreements with the same subsidiary of GS (as described in note 14)Note 16). Amounts totaling $3,826,342 of income$3,826,000, $1,858,000, and $(2,405,000) were recognized related to these swap agreements for the 233 days ended December 31, 2005, and the years ended December 31, 2006 and December 31, 2007, respectively, and are reflected in gain (loss) on derivatives. In addition, the consolidated balance sheet at December 31, 20052006 and December 31, 2007 includes $1,441,697$1,534,000 and $0 in prepaid expenses and other current assets, $2,015,000 and $2,441,216$0 in other long-term assets, $0 and $371,000 in other current liabilities and $0 and $557,000 in other long-term liabilities related to the same agreements.agreements, respectively.
Effective December 30, 2005, SuccessorCVR entered into a crude oil supply agreement with a subsidiary of GS (Supplier). This agreement replaces a similar contract held with an independent party (see note 17). Both parties will negotiate the cost of each barrel of crude oil to be purchased from a third party. SuccessorCVR will pay Supplier a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is adjusted further using a spread adjustment calculation based on the time period the crude oil is estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The monthly spread quantity for any delivery month at any time shall not exceed approximately 3.1 million barrels. The initial term of the agreement iswas to December 31, 20062006. CVR and it continuesSupplier agreed to extend the term of the Supply Agreement for onean additional year unless either party terminates it effective12 month period, January 1, 2007 through December 31, 2006. $1,290,731 was2007 and in connection with the extension amended certain terms and conditions of the Supply Agreement. On December 31, 2007,
F-54
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
CVR and supplier entered into an amended and restated crude oil supply agreement. The terms of the agreement remained substantially the same. $1,623,000 and $360,000 were recorded on the consolidated balance sheet at December 31, 20052006 and December 31, 2007, respectively, in prepaid expenses and other current assets for prepayment of crude oil. In addition, $31,751,000 and $43,773,000 were recorded in inventory and $13,459,000 and $42,666,000 were recorded in accounts payable at December 31, 2006 and December 31, 2007, respectively. Expenses associated with this agreement, included in cost of product sold (exclusive of depreciated and amortization) for the years ended December 31, 2006 and December 31, 2007 totaled $1,591,120,000 and $1,476,811,000 respectively. Interest expense associated with this agreement for the years ended December 31, 2006 and December 31, 2007 totaled $0 and $(376,000), respectively.
The Company had a note receivable with an executive member of management. During the period ended December 31, 2006, the board of directors approved to forgive the note receivable and related accrued interest receivable. The balance of the note receivable forgiven was $350,000. Accrued interest receivable forgiven was approximately $18,000. The total amount was charged to compensation expense.
On August 23, 2007, the Company entered into three new credit facilities, consisting of a $25 million secured facility, a $25 million unsecured facility and a $75 million unsecured facility. A subsidiary of GS was the sole lead arranger and sole bookrunner for each of these new credit facilities. These credit facilities and their arrangements are more fully described in Note 12, “Long-Term Debt”. The Company paid the subsidiary of GS a $1.3 million fee included in deferred financing costs. For the year ended December 31, 2007, interest expenses relating to these agreements were $867,000. The secured and unsecured facilities were paid in full on October 26, 2007 with proceeds from CVR’s initial public offering, see Note 1, “Organization and History of Company”, and both facilities terminated. Additionally, in connection with the consummation of the initial public offering, the $75 million unsecured facility also terminated.
As a result of the refinery turnaround in early 2007, CVR needed to delay the processing of quantities of crude oil that it purchased from various small independent producers. In order to facilitate this anticipated delay, CVR entered into a purchase, storage and sale agreement for gathered crude oil, dated March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant to the terms of the agreement, J. Aron agreed to purchase gathered crude oil from CVR, store the gathered crude oil and sell CVR the gathered crude oil on a forward basis. As of December 31, 2007, there were no longer any open commitments with regard to the agreement. Interest expense associated with this agreement included in interest expense and other financing costs was $196,000.
Goldman, Sachs & Co. was the lead underwriter of CVR’s initial public offering in October 2007. As lead underwriter, they were paid a customary underwriting discount of approximately $14.7 million, which includes $0.7 million of expense reimbursement.
On October 24, 2007, CVR paid a cash dividend, to its shareholders, including approximately $5.23 million that was ultimately distributed from CALLC II (Goldman Sachs Funds) and approximately $5.15 million distributed from CALLC to the Kelso Funds. Management collectively received approximately $0.13 million.
| |
(16)(18) | Business Segments |
CVR measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in Statement of Financial Accounting StandardsSFAS No. 131,Disclosures About Segments of an Enterprise and Related Information.Information. All operations of the segments are located in the United States.
F-34F-55
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
CVR changed its corporate selling, general and administrative allocation method to the operating segments in 2007. The effect of the change on operating income for174-day period ended June 23, 2005, the233-day period ended December 31, 2005 and the year ended December 31, 2006 would have been a decrease of $1.0 million, $1.4 million and $6.0 million, respectively, to the petroleum segment, an increase of $1.2 million, $1.4 million and $6.0 million, respectively, to the nitrogen fertilizer segment and a decrease of $0.2 million, $0.0 million and $0.0 million, respectively, to the other segment.
Petroleum
Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products including coke. CVR uses the coke in the manufacture of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For(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 goodsproduct sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment.Segment through October 24, 2007.) After October 24, 2007, intercompany sales are recorded according to the interconnect agreement (see Note 1). The intercompany transactions are eliminated in the Other Segment. For Original Predecessor, the coke was transferred from theIntercompany sales included in Petroleum Segment to the Nitrogen Fertilizer Segment at zero value such that nonet sales revenue on the part of the Petroleum Segment or corresponding cost of goods soldwere $2,445,000, $2,782,000, $5,340,000, and $5,195,000 for the Nitrogen Fertilizer Segment was recorded. Because Original Predecessor did not record these transfers in its segment results174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the information to restate these segment results in Original Predecessor periods is not available, financial results from those periods have not been restated. As a result, the results of operations for Original Predecessor periods are not comparable with those of Immediate Predecessor or Successor periods.years ended December 31, 2006, and December 31, 2007, respectively.
Nitrogen Fertilizer
The principal product of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Nitrogen fertilizer sales increased throughoutIntercompany cost of product sold (exclusive of depreciation and amortization) for the periods presented ascoke transfer described above was $2,778,000, $2,575,000, $5,242,000, and $4,528,000 for the on stream factor improved.174-day period ended June 23, 2005, the233-day period ended December 31, 2005, and the years ended December 31, 2006, and December 31, 2007, respectively.
F-56
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Other Segment
The Other Segment reflects intercompany eliminations, cash and cash equivalents, all debt related activities, income tax activities and other corporate activities that are not allocated to the operating segments.
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Original Predecessor | | | | Immediate Predecessor | | | | Successor | |
| | | Year
| | | 62-Day Period
| | | | 304-Day Period
| | | 174-Day Period
| | | | 233-Day Period
| |
| | | Ended
| | | Ended
| | | | Ended
| | | Ended
| | | | Ended
| |
| | | December 31,
| | | March 2,
| | | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2003 | | | 2004 | | | | 2004 | | | 2005 | | | | 2005 | |
| Net sales | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | $ | 1,161,287,249 | | | $ | 241,640,365 | | | | $ | 1,390,768,126 | | | $ | 903,802,983 | | | | $ | 1,363,390,142 | |
| Nitrogen Fertilizer | | | 100,909,645 | | | | 19,446,164 | | | | | 93,422,503 | | | | 79,347,843 | | | | | 93,651,855 | |
| Other | | | — | | | | — | | | | | (4,297,440 | ) | | | (2,444,565 | ) | | | | (2,782,455 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 1,262,196,894 | | | $ | 261,086,529 | | | | $ | 1,479,893,189 | | | $ | 980,706,261 | | | | $ | 1,454,259,542 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Depreciation and amortization | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | $ | 2,094,627 | | | $ | 271,284 | | | | $ | 1,522,464 | | | $ | 770,728 | | | | $ | 15,566,987 | |
| Nitrogen Fertilizer | | | 1,218,899 | | | | 160,719 | | | | | 855,289 | | | | 316,446 | | | | | 8,360,911 | |
| Other | | | — | | | | — | | | | | 68,208 | | | | 40,831 | | | | | 26,133 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 3,313,526 | | | $ | 432,003 | | | | $ | 2,445,961 | | | $ | 1,128,005 | | | | $ | 23,954,031 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | $ | 21,544,374 | | | $ | 7,687,745 | | | | $ | 77,094,034 | | | $ | 76,654,428 | | | | $ | 123,044,854 | |
| Nitrogen Fertilizer | | | 7,813,708 | | | | 3,514,997 | | | | | 22,874,227 | | | | 35,267,752 | | | | | 35,731,056 | |
| Other | | | — | | | | — | | | | | 3,076 | | | | 333,514 | | | | | (240,848 | ) |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 29,358,082 | | | $ | 11,202,742 | | | | $ | 99,971,337 | | | $ | 112,255,694 | | | | $ | 158,535,062 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | Successor | |
| | | Predecessor | | | | | | | | |
| | | 174 Days
| | | | 233 Days
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | |
| | | (in thousands) | |
| Net sales | | | | | | | | | | | | | |
| Petroleum | | $ | 903,803 | | | | $ | 1,363,390 | | | $ | 2,880,442 | |
| Nitrogen Fertilizer | | | 79,348 | | | | | 93,652 | | | | 162,465 | |
| Other | | | — | | | | | — | | | | — | |
| Intersegment elimination | | | (2,445 | ) | | | | (2,782 | ) | | | (5,340 | ) |
| | | | | | | | | | | | | | |
| Total | | $ | 980,706 | | | | $ | 1,454,260 | | | $ | 3,037,567 | |
| | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | | | | | | | | | | | |
| Petroleum | | $ | 761,719 | | | | $ | 1,156,208 | | | $ | 2,422,718 | |
| Nitrogen Fertilizer | | | 9,126 | | | | | 14,504 | | | | 25,898 | |
| Other | | | — | | | | | — | | | | — | |
| Intersegment elimination | | | (2,778 | ) | | | | (2,575 | ) | | | (5,242 | ) |
| | | | | | | | | | | | | | |
| Total | | $ | 768,067 | | | | $ | 1,168,137 | | | $ | 2,443,374 | |
| | | | | | | | | | | | | | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | | | | | | | | | | | |
| Petroleum | | $ | 52,611 | | | | $ | 56,159 | | | $ | 135,297 | |
| Nitrogen Fertilizer | | $ | 28,303 | | | | | 29,154 | | | | 63,683 | |
| Other | | | — | | | | | — | | | | — | |
| | | | | | | | | | | | | | |
| Total | | $ | 80,914 | | | | $ | 85,313 | | | $ | 198,980 | |
| | | | | | | | | | | | | | |
| Depreciation and amortization | | | | | | | | | | | | | |
| Petroleum | | $ | 771 | | | | $ | 15,567 | | | $ | 33,017 | |
| Nitrogen Fertilizer | | | 316 | | | | | 8,361 | | | | 17,126 | |
| Other | | | 41 | | | | | 26 | | | | 862 | |
| | | | | | | | | | | | | | |
| Total | | $ | 1,128 | | | | $ | 23,954 | | | $ | 51,005 | |
| | | | | | | | | | | | | | |
| Operating income (loss) | | | | | | | | | | | | | |
| Petroleum | | $ | 76,654 | | | | $ | 123,045 | | | $ | 245,578 | |
| Nitrogen Fertilizer | | | 35,268 | | | | | 35,731 | | | | 36,842 | |
| Other | | | 333 | | | | | (240 | ) | | | (812 | ) |
| | | | | | | | | | | | | | |
| Total | | $ | 112,255 | | | | $ | 158,536 | | | $ | 281,608 | |
| | | | | | | | | | | | | | |
F-35
CVR Energy, Inc. and Subsidiaries
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Original Predecessor | | | | Immediate Predecessor | | | | Successor | |
| | | Year
| | | 62-Day Period
| | | | 304-Day Period
| | | 174-Day Period
| | | | 233-Day Period
| |
| | | Ended
| | | Ended
| | | | Ended
| | | Ended
| | | | Ended
| |
| | | December 31,
| | | March 2,
| | | | December 31,
| | | June 23,
| | | | December 31,
| |
| | | 2003 | | | 2004 | | | | 2004 | | | 2005 | | | | 2005 | |
| Capital expenditures | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | $ | 489,083 | | | $ | — | | | | $ | 11,267,244 | | | $ | 10,790,042 | | | | $ | 42,107,751 | |
| Nitrogen fertilizer | | | 324,679 | | | | — | | | | | 2,697,852 | | | | 1,434,921 | | | | | 2,017,385 | |
| Other | | | — | | | | — | | | | | 195,184 | | | | 31,830 | | | | | 1,046,998 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 813,762 | | | $ | — | | | | $ | 14,160,280 | | | $ | 12,256,793 | | | | $ | 45,172,134 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Reorganization expenses — | | | | | | | | | | | | | | | | | | | | | | |
| Impairment of property, plant, and equipment | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | $ | 3,950,519 | | | $ | — | | | | $ | — | | | $ | — | | | | $ | — | |
| Nitrogen fertilizer | | | 5,688,107 | | | | — | | | | | — | | | | — | | | | | — | |
| Other | | | — | | | | — | | | | | — | | | | — | | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | $ | 9,638,626 | | | $ | — | | | | $ | — | | | $ | — | | | | $ | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total assets | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | 145,861,715 | | | | | | | | $ | 664,870,240 | |
| Nitrogen Fertilizer | | | | | | | | | | | | 83,561,149 | | | | | | | | | 425,333,621 | |
| Other | | | | | | | | | | | | (265,527 | ) | | | | | | | | 131,344,042 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | 229,157,337 | | | | | | | | $ | 1,221,547,903 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Goodwill | | | | | | | | | | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | — | | | | | | | | $ | 42,806,422 | |
| Nitrogen Fertilizer | | | | | | | | | | | | — | | | | | | | | | 40,968,463 | |
| Other | | | | | | | | | | | | — | | | | | | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | — | | | | | | | | $ | 83,774,885 | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
F-36F-57
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTSNotes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | | |
| | | | | | | Successor | |
| | | Predecessor | | | | | | | | |
| | | 174 Days
| | | | 233 Days
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | |
| | | (in thousands) | |
| Capital expenditures | | | | | | | | | | | | | |
| Petroleum | | $ | 10,790 | | | | $ | 42,108 | | | $ | 223,552 | |
| Nitrogen fertilizer | | | 1,435 | | | | | 2,017 | | | | 13,258 | |
| Other | | | 32 | | | | | 1,047 | | | | 3,415 | |
| | | | | | | | | | | | | | |
| Total | | $ | 12,257 | | | | $ | 45,172 | | | $ | 240,225 | |
| | | | | | | | | | | | | | |
| Total assets | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | 907,315 | |
| Nitrogen Fertilizer | | | | | | | | | | | | 417,657 | |
| Other | | | | | | | | | | | | 124,508 | |
| | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | 1,449,480 | |
| | | | | | | | | | | | | | |
| Goodwill | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | 42,806 | |
| Nitrogen Fertilizer | | | | | | | | | | | | 40,969 | |
| Other | | | | | | | | | | | | — | |
| | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | 83,775 | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | Successor | |
| | | Year Ended December 31, 2007 | |
| | | Previously
| | | | | | | |
| | | Reported | | | Adjustment | | | As Restated(†) | |
| | | (in thousands) | |
| Net sales | | | | | | | | | | | | |
| Petroleum | | $ | 2,806,205 | | | $ | — | | | $ | 2,806,205 | |
| Nitrogen Fertilizer | | | 165,855 | | | | — | | | | 165,855 | |
| Other | | | — | | | | — | | | | — | |
| Intersegment elimination | | | (5,195 | ) | | | — | | | | (5,195 | ) |
| | | | | | | | | | | | | |
| Total | | $ | 2,966,865 | | | $ | — | | | $ | 2,966,865 | |
| | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | | | | | | | | | | |
| Petroleum | | $ | 2,282,555 | | | $ | 17,671 | | | $ | 2,300,226 | |
| Nitrogen Fertilizer | | | 13,042 | | | | — | | | | 13,042 | |
| Other | | | — | | | | — | | | | — | |
| Intersegment elimination | | | (4,528 | ) | | | — | | | | (4,528 | ) |
| | | | | | | | | | | | | |
| Total | | $ | 2,291,069 | | | $ | 17,671 | | | $ | 2,308,740 | |
| | | | | | | | | | | | | |
F-58
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | |
| | | Successor | |
| | | Year Ended December 31, 2007 | |
| | | Previously
| | | | | | | |
| | | Reported | | | Adjustment | | | As Restated(†) | |
| | | (in thousands) | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | | | | | | | | | | |
| Petroleum | | $ | 209,475 | | | $ | — | | | $ | 209,475 | |
| Nitrogen Fertilizer | | | 66,663 | | | | — | | | | 66,663 | |
| Other | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | $ | 276,138 | | | $ | — | | | $ | 276,138 | |
| | | | | | | | | | | | | |
| Net costs associated with flood | | | | | | | | | | | | |
| Petroleum | | $ | 36,669 | | | $ | — | | | $ | 36,669 | |
| Nitrogen Fertilizer | | | 2,432 | | | | — | | | | 2,432 | |
| Other | | | 2,422 | | | | — | | | | 2,422 | |
| | | | | | | | | | | | | |
| Total | | $ | 41,523 | | | $ | — | | | $ | 41,523 | |
| | | | | | | | | | | | | |
| Depreciation and amortization | | | | | | | | | | | | |
| Petroleum | | $ | 43,040 | | | $ | — | | | $ | 43,040 | |
| Nitrogen Fertilizer | | | 16,819 | | | | — | | | | 16,819 | |
| Other | | | 920 | | | | — | | | | 920 | |
| | | | | | | | | | | | | |
| Total | | $ | 60,779 | | | $ | — | | | $ | 60,779 | |
| | | | | | | | | | | | | |
| Operating income (loss) | | | | | | | | | | | | |
| Petroleum | | $ | 162,547 | | | $ | (17,671 | ) | | $ | 144,876 | |
| Nitrogen Fertilizer | | | 46,593 | | | | — | | | | 46,593 | |
| Other | | | (4,906 | ) | | | — | | | | (4,906 | ) |
| | | | | | | | | | | | | |
| Total | | $ | 204,234 | | | $ | (17,671 | ) | | $ | 186,563 | |
| | | | | | | | | | | | | |
| Capital expenditures | | | | | | | | | | | | |
| Petroleum | | $ | 261,562 | | | $ | — | | | $ | 261,562 | |
| Nitrogen Fertilizer | | | 6,488 | | | | — | | | | 6,488 | |
| Other | | | 543 | | | | — | | | | 543 | |
| | | | | | | | | | | | | |
| Total | | $ | 268,593 | | | $ | — | | | $ | 268,593 | |
| | | | | | | | | | | | | |
| Total assets | | | | | | | | | | | | |
| Petroleum | | $ | 1,271,712 | | | $ | 5,412 | | | $ | 1,277,124 | |
| Nitrogen Fertilizer | | | 446,763 | | | | — | | | | 446,763 | |
| Other | | | 137,593 | | | | 6,876 | | | | 144,469 | |
| | | | | | | | | | | | | |
| Total | | $ | 1,856,068 | | | $ | 12,288 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
| Goodwill | | | | | | | | | | | | |
| Petroleum | | $ | 42,806 | | | $ | — | | | $ | 42,806 | |
| Nitrogen Fertilizer | | | 40,969 | | | | — | | | | 40,969 | |
| Other | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | |
| Total | | $ | 83,775 | | | $ | — | | | $ | 83,775 | |
| | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
F-59
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| |
(17)(19) | Major Customers and Suppliers |
Sales to major customers were as follows:
| | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | Successor | |
| | | Original Predecessor | | | Immediate Predecessor | | | Successor | | Predecessor | | | | | | | | | |
| | | Year
| | 62-Day Period
| | | 304-Day Period
| | 174-Day Period
| | | 233-Day Period
| | 174 Days
| | | | 233 Days
| | Year
| | Year
| |
| | | Ended
| | Ended
| | | Ended
| | Ended
| | | Ended
| | Ended
| | | | Ended
| | Ended
| | Ended
| |
| | | December 31,
| | March 2,
| | | December 31,
| | June 23,
| | | December 31,
| | June 23,
| | | | December 31,
| | December 31,
| | December 31,
| |
| | | 2003 | | 2004 | | | 2004 | | 2005 | | | 2005 | | 2005 | | | | 2005 | | 2006 | | 2007 | |
Petroleum | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Customer A | | | 89 | % | | | 10 | % | | | | 18 | % | | | 17 | % | | | | 16 | % | | | 17 | % | | | | 16 | % | | | 2 | % | | | 3 | % |
| Customer B | | | 3 | % | | | 25 | % | | | | 10 | % | | | 5 | % | | | | 6 | % | | | 5 | % | | | | 6 | % | | | 5 | % | | | 5 | % |
| Customer C | | | 1 | % | | | 18 | % | | | | 17 | % | | | 17 | % | | | | 15 | % | | | 17 | % | | | | 15 | % | | | 15 | % | | | 12 | % |
| Customer D | | | — | | | | — | | | | | 8 | % | | | 14 | % | | | | 17 | % | | | 14 | % | | | | 17 | % | | | 10 | % | | | 7 | % |
| Customer E | | | 1 | % | | | 9 | % | | | | 15 | % | | | 11 | % | | | | 11 | % | | | 11 | % | | | | 11 | % | | | 10 | % | | | 9 | % |
| Customer F | | | | 8 | % | | | | 7 | % | | | 9 | % | | | 10 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 94 | % | | | 62 | % | | | | 68 | % | | | 64 | % | | | | 65 | % | | | 72 | % | | | | 72 | % | | | 51 | % | | | 46 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nitrogen Fertilizer | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Customer F | | | 66 | % | | | 48 | % | | | | 24 | % | | | 16 | % | | | | 10 | % | |
| Customer G | | | 0 | % | | | 0 | % | | | | 5 | % | | | 9 | % | | | | 10 | % | | | 16 | % | | | | 10 | % | | | 5 | % | | | 3 | % |
| Customer H | | | | 9 | % | | | | 10 | % | | | 7 | % | | | 18 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 66 | % | | | 48 | % | | | | 29 | % | | | 25 | % | | | | 20 | % | | | 25 | % | | | | 20 | % | | | 12 | % | | | 21 | % |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
The Petroleum Segment maintains long-term contracts with one supplier for the purchase of its crude oil. The agreement with Supplier A expired in December 2005, at which time Successor entered into a similar arrangement with Supplier B, a related party (as described in note 15)Note 17). Purchases contracted as a percentage of the total cost of goodsproduct sold (exclusive of depreciation and amortization) for each of the periods were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Original Predecessor | | | Immediate Predecessor | | | Successor |
| | | Year
| | 62-Day Period
| | | 304-Day Period
| | 174-Day Period
| | | 233-Day Period
|
| | | Ended
| | Ended
| | | Ended
| | Ended
| | | Ended
|
| | | December 31,
| | March 2,
| | | December 31,
| | June 23,
| | | December 31,
|
| | | 2003 | | 2004 | | | 2004 | | 2005 | | | 2005 |
| Supplier A | | | 28 | % | | | 32 | % | | | | 68 | % | | | 77 | % | | | | 69 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | Successor | |
| | | Predecessor | | | | | | | | | | | |
| | | 174 Days
| | | | 233 Days
| | | Year
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| | | | | | | | | | | | | As restated(†) | |
| Supplier A | | | 82 | % | | | | 73 | % | | | — | | | | — | |
| Supplier B | | | — | | | | | — | | | | 67 | % | | | 63 | % |
| | | | | | | | | | | | | | | | | | |
| | | | 82 | % | | | | 73 | % | | | 67 | % | | | 63 | % |
| | | | | | | | | | | | | | | | | | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
The Nitrogen Fertilizer Segment maintains long-term contracts with one supplier. Purchases from this supplier as a percentage of the total costdirect operating expenses (exclusive of goods solddepreciation and amortization) were as follows:
| | | | | | | | | | | | | | | | | | | | | | | |
| | | Original Predecessor | | | Immediate Predecessor | | | Successor |
| | | Year
| | 62-Day Period
| | | 304-Day Period
| | 174-Day Period
| | | 233-Day Period
|
| | | Ended
| | Ended
| | | Ended
| | Ended
| | | Ended
|
| | | December 31,
| | March 2,
| | | December 31,
| | June 23,
| | | December 31,
|
| | | 2003 | | 2004 | | | 2004 | | 2005 | | | 2005 |
| Supplier | | | 1 | % | | | 2 | % | | | | 3 | % | | | 3 | % | | | | 3 | % |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| | | | | | | Successor | |
| | | Predecessor | | | | | | | | | | | |
| | | 174 Days
| | | | 233 Days
| | | Year
| | | Year
| |
| | | Ended
| | | | Ended
| | | Ended
| | | Ended
| |
| | | June 23,
| | | | December 31,
| | | December 31,
| | | December 31,
| |
| | | 2005 | | | | 2005 | | | 2006 | | | 2007 | |
| Supplier | | | 4 | % | | | | 5 | % | | | 8 | % | | | 5 | % |
| | | | | | | | | | | | | | | | | | |
F-60
CVR ENERGY, INC. AND SUBSIDIARIES
F-37
Notes to Consolidated Financial Statements — (Continued)
| |
| (20) | Selected Quarterly Financial and Information (Unaudited) |
Summarized quarterly financial data for the December 31, 2006 and 2007.
| | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2006 | | | | |
| | | Quarter | | | | |
| | | First | | | Second | | | Third | | | Fourth | | | | |
| | | (in thousands except share amounts) | | | | |
| |
| Net sales | | $ | 669,727 | | | $ | 880,839 | | | $ | 778,587 | | | $ | 708,414 | | | | | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 539,539 | | | | 663,910 | | | | 644,627 | | | | 595,298 | | | | | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | 44,288 | | | | 43,478 | | | | 56,696 | | | | 54,518 | | | | | |
| Selling, general and administrative (exclusive of depreciation and amortization) | | | 8,493 | | | | 11,976 | | | | 12,327 | | | | 29,804 | | | | | |
| Net costs associated with flood | | | — | | | | — | | | | — | | | | — | | | | | |
| Depreciation and amortization | | | 12,004 | | | | 12,018 | | | | 12,788 | | | | 14,195 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total operating costs and expenses | | | 604,324 | | | | 731,382 | | | | 726,438 | | | | 693,815 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | 65,403 | | | | 149,457 | | | | 52,149 | | | | 14,599 | | | | | |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | |
| Interest expense and other financing costs | | | (12,207 | ) | | | (10,129 | ) | | | (10,681 | ) | | | (10,863 | ) | | | | |
| Interest income | | | 590 | | | | 1,093 | | | | 1,091 | | | | 676 | | | | | |
| Gain (loss) on derivatives | | | (17,615 | ) | | | (108,847 | ) | | | 171,209 | | | | 49,746 | | | | | |
| Loss on extinguishment of debt | | | — | | | | — | | | | — | | | | (23,360 | ) | | | | |
| Other income (expense) | | | 58 | | | | (320 | ) | | | 573 | | | | (1,211 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | (29,174 | ) | | | (118,203 | ) | | | 162,192 | | | | 14,988 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Income before income taxes and minority interest | | | 36,229 | | | | 31,254 | | | | 214,341 | | | | 29,587 | | | | | |
| Income tax expense (benefit) | | | 14,106 | | | | 11,620 | | | | 85,302 | | | | 8,812 | | | | | |
| Minority interest in (income) loss of subsidiaries | | | — | | | | — | | | | — | | | | — | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 22,123 | | | $ | 19,634 | | | $ | 129,039 | | | $ | 20,775 | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 13) | | | | | | | | | | | | | | | | | | | | |
| Net earnings per share | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.26 | | | $ | 0.23 | | | $ | 1.50 | | | $ | 0.24 | | | | | |
| Diluted | | $ | 0.26 | | | $ | 0.23 | | | $ | 1.50 | | | $ | 0.24 | | | | | |
| Weighted average common shares outstanding | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 86,141,291 | | | | 86,141,291 | | | | 86,141,291 | | | | 86,141,291 | | | | | |
| Diluted | | | 86,158,791 | | | | 86,158,791 | | | | 86,158,791 | | | | 86,158,791 | | | | | |
F-61
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
Quarterly Financial Information (Unaudited)
| | | | | | | | | |
| | | Year Ended December 31, 2007 | |
| | | Quarter | |
| | | First | | | Second | |
| | | (in thousands except share amounts) | |
| |
| Net sales | | $ | 390,483 | | | $ | 843,413 | |
| Operating costs and expenses: | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 303,670 | | | | 569,623 | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | 113,412 | | | | 60,955 | |
| Selling, general and administrative (exclusive of depreciation and amortization) | | | 13,150 | | | | 14,937 | |
| Net costs associated with flood | | | — | | | | 2,139 | |
| Depreciation and amortization | | | 14,235 | | | | 17,957 | |
| | | | | | | | | |
| Total operating costs and expenses | | | 444,467 | | | | 665,611 | |
| | | | | | | | | |
| Operating income (loss) | | | (53,984 | ) | | | 177,802 | |
| Other income (expense): | | | | | | | | |
| Interest expense and other financing costs | | | (11,857 | ) | | | (15,763 | ) |
| Interest income | | | 452 | | | | 161 | |
| Gain (loss) on derivatives | | | (136,959 | ) | | | (155,485 | ) |
| Loss on extinguishment of debt | | | — | | | | — | |
| Other income (expense) | | | 1 | | | | 101 | |
| | | | | | | | | |
| Total other income (expense) | | | (148,363 | ) | | | (170,986 | ) |
| | | | | | | | | |
| Income (loss) before income taxes and minority interest | | | (202,347 | ) | | | 6,816 | |
| Income tax expense (benefit) | | | (47,298 | ) | | | (93,669 | ) |
| Minority interest in (income) loss of subsidiaries | | | 676 | | | | (419 | ) |
| | | | | | | | | |
| Net income (loss) | | $ | (154,373 | ) | | $ | 100,066 | |
| | | | | | | | | |
| Unaudited Pro Forma Information (Note 13) | | | | | | | | |
| Net earnings (loss) per share | | | | | | | | |
| Basic | | $ | (1.79 | ) | | $ | 1.16 | |
| Diluted | | $ | (1.79 | ) | | $ | 1.16 | |
| Weighted average common shares outstanding | | | | | | | | |
| Basic | | | 86,141,291 | | | | 86,141,291 | |
| Diluted | | | 86,141,291 | | | | 86,158,791 | |
F-62
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Year Ended December 31, 2007 | |
| | | Quarter | |
| | | Third | | | Fourth | |
| | | Previously
| | | | | | As
| | | Previously
| | | | | | As
| |
| | | Reported | | | Adjustment | | | Restated(†) | | | Reported | | | Adjustment | | | Restated(†) | |
| | | (in thousands except share amounts) | |
| |
| Net sales | | $ | 585,978 | | | $ | — | | | $ | 585,978 | | | $ | 1,146,991 | | | $ | — | | | $ | 1,146,991 | |
| Operating costs and expenses: | | | | | | | | | | | | | | | | | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 446,170 | | | | 7,072 | | | | 453,242 | | | | 971,606 | | | | 10,599 | | | | 982,205 | |
Direct operating expenses
(exclusive of depreciation and amortization) | | | 44,440 | | | | — | | | | 44,440 | | | | 57,331 | | | | — | | | | 57,331 | |
Selling, general and administrative
(exclusive of depreciation and amortization) | | | 14,035 | | | | — | | | | 14,035 | | | | 51,000 | | | | — | | | | 51,000 | |
| Net costs associated with flood | | | 32,192 | | | | — | | | | 32,192 | | | | 7,192 | | | | — | | | | 7,192 | |
| Depreciation and amortization | | | 10,481 | | | | — | | | | 10,481 | | | | 18,106 | | | | — | | | | 18,106 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total operating costs and expenses | | | 547,318 | | | | 7,072 | | | | 554,390 | | | | 1,105,235 | | | | 10,599 | | | | 1,115,834 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | 38,660 | | | | (7,072 | ) | | | 31,588 | | | | 41,756 | | | | (10,599 | ) | | | 31,157 | |
| Other income (expense): | | | | | | | | | | | | | | | | | | | | | | | | |
| Interest expense and other financing costs | | | (18,340 | ) | | | — | | | | (18,340 | ) | | | (15,166 | ) | | | — | | | | (15,166 | ) |
| Interest income | | | 151 | | | | — | | | | 151 | | | | 336 | | | | — | | | | 336 | |
| Gain (loss) on derivatives | | | 40,532 | | | | — | | | | 40,532 | | | | (30,066 | ) | | | — | | | | (30,066 | ) |
| Loss on extinguishment of debt | | | — | | | | — | | | | — | | | | (1,258 | ) | | | — | | | | (1,258 | ) |
| Other income (expense) | | | 53 | | | | — | | | | 53 | | | | 201 | | | | — | | | | 201 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | 22,396 | | | | — | | | | 22,396 | | | | (45,953 | ) | | | — | | | | (45,953 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Income (loss) before income taxes
and minority interest | | | 61,056 | | | | (7,072 | ) | | | 53,984 | | | | (4,197 | ) | | | (10,599 | ) | | | (14,796 | ) |
| Income tax expense (benefit) | | | 47,610 | | | | (4,879 | ) | | | 42,731 | | | | 11,718 | | | | (1,997 | ) | | | 9,721 | |
| Minority interest in (income) loss of subsidiaries | | | (47 | ) | | | — | | | | (47 | ) | | | — | | | | — | | | | — | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 13,399 | | | $ | (2,193 | ) | | $ | 11,206 | | | $ | (15,915 | ) | | $ | (8,602 | ) | | $ | (24,517 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 13) | | | | | | | | | | | | | | | | | | | | | | | | |
| Net earnings (loss) per share | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | $ | 0.16 | | | $ | (0.03 | ) | | $ | 0.13 | | | $ | (0.18 | ) | | $ | (0.10 | ) | | $ | (0.28 | ) |
| Diluted | | $ | 0.16 | | | $ | (0.03 | ) | | $ | 0.13 | | | $ | (0.18 | ) | | $ | (0.10 | ) | | $ | (0.28 | ) |
| Weighted average common shares outstanding | | | | | | | | | | | | | | | | | | | | | | | | |
| Basic | | | 86,141,291 | | | | | | | | 86,141,291 | | | | 86,141,291 | | | | | | | | 86,141,291 | |
| Diluted | | | 86,158,791 | | | | | | | | 86,158,791 | | | | 86,141,291 | | | | | | | | 86,141,291 | |
| | |
| (†) | | See Note 2 to consolidated financial statements. |
F-63
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Consolidated Financial Statements — (Continued)
(21) Subsequent Events (unaudited)
On June 13, 2008, the Company announced that the managing general partner of the Partnership had decided to postpone indefinitely the Partnership’s initial public offering. The Partnership has notified the SEC that it intends to withdraw the registration statement it filed in February 2008.
F-64
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
| | | | | | | | | | | | | | |
| | | | | | | Pro Forma
| | |
| | | Successor | | Successor | | Successor | | | | | | | | | |
| | | December 31,
| | June 30,
| | June 30,
| | | March 31,
| | December 31,
| |
| | | 2005 | | 2006 | | 2006 | | | 2008 | | 2007 | |
| | | | | (unaudited) | | (unaudited)
| | | (unaudited) | | | |
| | | | | | | (note 3) | | | (in thousands of dollars) | |
| |
ASSETS | | | | | | | | | | | | | ASSETS |
| Current assets: | | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents | | $ | 64,703,524 | | | $ | 127,867,055 | | | $ | — | | | $ | 25,179 | | | $ | 30,509 | |
| Accounts receivable, net of allowance for doubtful accounts of $275,188 and $354,904, respectively | | | 71,560,052 | | | | 63,504,465 | | | | | | |
| Accounts receivable, net of allowance for doubtful accounts of $597 and $391, respectively | | | | 117,033 | | | | 86,546 | |
| Inventories | | | 154,275,818 | | | | 179,658,465 | | | | | | | | 288,415 | | | | 254,655 | |
| Prepaid expenses and other current assets | | | 14,709,309 | | | | 15,208,697 | | | | | | | | 13,071 | | | | 14,186 | |
| Insurance receivable | | | | 74,275 | | | | 73,860 | |
| Income tax receivable | | | | 26,166 | | | | 31,367 | |
| Deferred income taxes | | | 31,059,748 | | | | 46,419,549 | | | | | | | | 78,325 | | | | 79,047 | |
| | | | | | | | | | | | | |
| Total current assets | | | 336,308,451 | | | | 432,658,231 | | | | — | | | | 622,464 | | | | 570,170 | |
| Property, plant, and equipment, net of accumulated depreciation | | | 772,512,884 | | | | 859,664,720 | | | | | | | | 1,192,542 | | | | 1,192,174 | |
| Intangible assets | | | 1,008,547 | | | | 823,502 | | | | | | |
| Intangible assets, net | | | | 450 | | | | 473 | |
| Goodwill | | | 83,774,885 | | | | 83,774,885 | | | | | | | | 83,775 | | | | 83,775 | |
| Deferred financing costs | | | 19,524,839 | | | | 17,867,958 | | | | | | |
| Deferred financing costs, net | | | | 7,028 | | | | 7,515 | |
| Insurance receivable | | | | 11,400 | | | | 11,400 | |
| Other long-term assets | | | 8,418,297 | | | | 11,353,121 | | | | | | | | 5,932 | | | | 2,849 | |
| | | | | | | | | | | | | |
| Total assets | | $ | 1,221,547,903 | | | $ | 1,406,142,417 | | | $ | — | | | $ | 1,923,591 | | | $ | 1,868,356 | |
| | | | | | | | | | | | | |
| | | | | | | | |
LIABILITIES AND EQUITY | | | | | | | | | | | | | LIABILITIES AND EQUITY |
| Current liabilities: | | | | | | | | | | | | | | | | | | | | |
| Current portion of long-term debt | | $ | 2,235,973 | | | $ | 2,224,807 | | | $ | — | | | $ | 4,862 | | | $ | 4,874 | |
| Revolving debt | | | — | | | | — | | | | | | |
| Note payable and capital lease obligations | | | | 11,209 | | | | 11,640 | |
| Payable to swap counterparty | | | | 294,984 | | | | 262,415 | |
| Accounts payable | | | 87,914,833 | | | | 109,844,255 | | | | | | | | 170,194 | | | | 182,225 | |
| Personnel accruals | | | 10,796,896 | | | | 7,428,667 | | | | | | | | 34,954 | | | | 36,659 | |
| Accrued taxes other than income taxes | | | 4,841,234 | | | | 5,186,288 | | | | | | | | 22,073 | | | | 14,732 | |
| Accrued income taxes | | | 4,939,614 | | | | 11,294,389 | | | | | | |
| Payable to swap counterparty | | | 96,688,956 | | | | 150,506,479 | | | | | | |
| Deferred revenue | | | 12,029,987 | | | | 1,554,313 | | | | | | | | 29,784 | | | | 13,161 | |
| Other current liabilities | | | 8,831,937 | | | | 4,915,415 | | | | | | | | 32,953 | | | | 33,820 | |
| | | | | | | | | | | | | |
| Total current liabilities | | | 228,279,430 | | | | 292,954,613 | | | | — | | | | 601,013 | | | | 559,526 | |
| Long-term liabilities: | | | | | | | | | | | | | | | | | | | | |
| Long-term debt, less current portion | | | 497,201,527 | | | | 506,091,909 | | | | | | | | 483,117 | | | | 484,328 | |
| Accrued environmental liabilities | | | 7,009,388 | | | | 6,083,488 | | | | | | | | 4,924 | | | | 4,844 | |
| Deferred income taxes | | | 209,523,747 | | | | 198,758,629 | | | | | | | | 287,974 | | | | 286,986 | |
| Other long-term liabilities | | | | 4,447 | | | | 1,122 | |
| Payable to swap counterparty | | | 160,033,333 | | | | 218,462,243 | | | | | | | | 76,411 | | | | 88,230 | |
| Other long-term liabilities | | | — | | | | 1,471,269 | | | | | | |
| | | | | | | | | | | | | |
| Total long-term liabilities | | | 873,767,995 | | | | 930,867,538 | | | | — | | | | 856,873 | | | | 865,510 | |
| Management voting common units subject to redemption | | | 4,172,350 | | | | 12,553,450 | | | | | | |
| Less: note receivable from management unitholder | | | (500,000 | ) | | | (350,000 | ) | | | | | |
| Commitments and contingencies | | | | | | | | | |
| Minority interest in subsidiaries | | | | 10,600 | | | | 10,600 | |
| Stockholders’ equity | | | | | | | | | |
| Common stock $0.01 par value per share; 350,000,000 shares authorized; 86,141,291 shares issued and outstanding | | | | 861 | | | | 861 | |
Additionalpaid-in-capital | | | | 458,523 | | | | 458,359 | |
| Retained earning (deficit) | | | | (4,279 | ) | | | (26,500 | ) |
| | | | | | | | | | | | | |
| Total management voting common units subject to redemption, net | | | 3,672,350 | | | | 12,203,450 | | | | — | | |
| Members’ equity: | | | | | | | | | | | | | |
| Voting common units | | | 114,830,560 | | | | 168,206,669 | | | | | | |
| Management nonvoting override units | | | 997,568 | | | | 1,910,147 | | | | | | |
| Total stockholders’ equity | | | | 455,105 | | | | 432,720 | |
| | | | | | | | | | | | | |
| Total members’ equity | | | 115,828,128 | | | | 170,116,816 | | | | — | | |
| Total liabilities and stockholders’ equity | | | $ | 1,923,591 | | | $ | 1,868,356 | |
| | | | | | | | | | | | |
| | | | | | | | | | | | | | |
PRO FORMA STOCKHOLDERS’ EQUITY | | | | | | | | | | | | | |
| Stockholders’ equity: | | | | | | | | | | | | | |
| Common stock, $0.01 par value, shares authorized; shares issued and outstanding | | | | | | | | | | | | | |
| Additional paid-in capital | | | | | | | | | | | | | |
| Retained earnings | | | | | | | | | | | | | |
| Total pro forma stockholders’ equity | | | | | | | | | | | | | |
| Commitments and contingencies | | | | | | | | | | | | | |
| | | | | | | | | |
| Total liabilities and equity | | $ | 1,221,547,903 | | | $ | 1,406,142,417 | | | $ | — | | |
| | | | | | | | | |
See accompanying notes to the condensed consolidated financial statements.
F-38F-65
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
| | | | | | | | | | | | | | | | | | |
| | | Immediate
| | | | | | | | |
| | | Predecessor | | | | Successor | | | | |
| | | 174 Days Ended
| | | | 49 Days Ended
| | | Six Months Ended
| | | | |
| | | June 23,
| | | | June 30,
| | | June 30,
| | | | |
| | | 2005 | | | | 2005 | | | 2006 | | | | |
| | | | | | | (unaudited) | | | (unaudited) | | | | |
| Net sales | | $ | 980,706,261 | | | | $ | 49,692,475 | | | $ | 1,550,566,629 | | | | | |
| Cost of goods sold | | | 850,037,564 | | | | | 62,526,529 | | | | 1,315,084,162 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Gross profit (loss) | | | 130,668,697 | | | | | (12,834,054 | ) | | | 235,482,467 | | | | | |
| Operating expenses: | | | | | | | | | | | | | | | | | |
| Selling, general and administrative expenses | | | 18,413,003 | | | | | 757,946 | | | | 20,622,332 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Total operating expenses | | | 18,413,003 | | | | | 757,946 | | | | 20,622,332 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Operating income (loss) | | | 112,255,694 | | | | | (13,592,000 | ) | | | 214,860,135 | | | | | |
| Other income (expense): | | | | | | | | | | | | | | | | | |
| Interest expense | | | (7,801,821 | ) | | | | (955,583 | ) | | | (22,335,620 | ) | | | | |
| Interest income | | | 511,687 | | | | | 2,150 | | | | 1,683,157 | | | | | |
| Loss on derivatives | | | (7,664,725 | ) | | | | (151,780,732 | ) | | | (126,462,043 | ) | | | | |
| Loss on extinguishment of debt | | | (8,093,754 | ) | | | | — | | | | — | | | | | |
| Other income (expense) | | | (762,616 | ) | | | | 1,304 | | | | (262,864 | ) | | | | |
| | | | | | | | | | | | | | | | | | |
| Total other income (expense) | | | (23,811,229 | ) | | | | (152,732,861 | ) | | | (147,377,370 | ) | | | | |
| | | | | | | | | | | | | | | | | | |
| Income (loss) before provision for income taxes | | | 88,444,465 | | | | | (166,324,861 | ) | | | 67,482,765 | | | | | |
| Income tax expense (benefit) | | | 36,047,516 | | | | | (56,076,520 | ) | | | 25,725,556 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Net income (loss) | | $ | 52,396,949 | | | | $ | (110,248,341 | ) | | $ | 41,757,209 | | | | | |
| | | | | | | | | | | | | | | | | | |
| Unaudited Pro Forma Information (Note 3) | | | | | | | | | | | | | | | | | |
| Basic and diluted earnings per common share | | | | | | | | | | | $ | — | | | | | |
| Basic and diluted weighted average common shares outstanding | | | | | | | | | | | | — | | | | | |
| | | | | | | | | |
| | | Three Months Ended
| |
| | | March 31, | |
| | | 2008 | | | 2007 | |
| | | (unaudited) | |
| | | (in thousands except share amounts) | |
| |
| Net sales | | $ | 1,223,003 | | | $ | 390,483 | |
| Operating costs and expenses: | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) | | | 1,036,194 | | | | 303,670 | |
| Direct operating expenses (exclusive of depreciation and amortization) | | | 60,556 | | | | 113,412 | |
| Selling, general and administrative expenses (exclusive of depreciation and amortization) | | | 13,497 | | | | 13,150 | |
| Net costs associated with flood | | | 5,763 | | | | — | |
| Depreciation and amortization | | | 19,635 | | | | 14,235 | |
| | | | | | | | | |
| Total operating costs and expenses | | | 1,135,645 | | | | 444,467 | |
| | | | | | | | | |
| Operating income (loss) | | | 87,358 | | | | (53,984 | ) |
| Other income (expense): | | | | | | | | |
| Interest expense and other financing costs | | | (11,298 | ) | | | (11,857 | ) |
| Interest income | | | 702 | | | | 452 | |
| Loss on derivatives, net | | | (47,871 | ) | | | (136,959 | ) |
| Other income, net | | | 179 | | | | 1 | |
| | | | | | | | | |
| Total other income (expense) | | | (58,288 | ) | | | (148,363 | ) |
| | | | | | | | | |
| Income (loss) before income taxes and minority interest in subsidiaries | | | 29,070 | | | | (202,347 | ) |
| Income tax expense (benefit) | | | 6,849 | | | | (47,298 | ) |
| Minority interest in loss of subsidiaries | | | — | | | | 676 | |
| | | | | | | | | |
| Net income (loss) | | $ | 22,221 | | | $ | (154,373 | ) |
| | | | | | | | | |
| Net earnings per share | | | | | | | | |
| Basic | | $ | 0.26 | | | | | |
| Diluted | | $ | 0.26 | | | | | |
| Weighted average common shares outstanding | | | | | | | | |
| Basic | | | 86,141,291 | | | | | |
| Diluted | | | 86,158,791 | | | | | |
| Pro Forma Information (note 11) | | | | | | | | |
| Net (loss) per share | | | | | | | | |
| Basic | | | | | | $ | (1.79 | ) |
| Diluted | | | | | | $ | (1.79 | ) |
| Weighted average common shares outstanding | | | | | | | | |
| Basic | | | | | | | 86,141,291 | |
| Diluted | | | | | | | 86,141,291 | |
See accompanying notes to the condensed consolidated financial statements.
F-39F-66
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
(unaudited)
| | | | | | | | | | | | | | | | | | | | | |
| | | Management Voting Common
| | | Note Receivable
| | | | | | | |
| | | Units Subject to Redemption | | | from Management
| | | | | | Total | |
| | | Units | | | Dollars | | | Unit Holder | | | | | | Dollars | |
| |
For the six months ended June 30, 2006 | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 227,500 | | | $ | 4,172,350 | | | $ | (500,000 | ) | | | | | | $ | 3,672,350 | |
| Payment of note receivable | | | | | | | — | | | | 150,000 | | | | | | | | 150,000 | |
| Adjustment to fair value for management common units | | | | | | | 8,013,120 | | | | — | | | | | | | | 8,013,120 | |
| Net income allocated to management common units | | | | | | | 367,980 | | | | — | | | | | | | | 367,980 | |
| | | | | | | | | | | | | | | | | | | | | |
| Balance at June 30, 2006 | | | 227,500 | | | $ | 12,553,450 | | | $ | (350,000 | ) | | | | | | $ | 12,203,450 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Management
| | | Management
| | | | |
| | | | | | Nonvoting Override
| | | Nonvoting Override
| | | | |
| | | Voting Common Units | | | Operating Units | | | Value Units | | | Total | |
| | | Units | | | Dollars | | | Units | | | Dollars | | | Units | | | Dollars | | | Dollars | |
| |
For the six months ended June 30, 2006 | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2005 | | | 23,588,500 | | | $ | 114,830,560 | | | | 919,630 | | | $ | 602,381 | | | | 1,839,265 | | | $ | 395,187 | | | $ | 115,828,128 | |
| Issuance of 2,000,000 common units for cash | | | 2,000,000 | | | | 20,000,000 | | | | | | | | — | | | | | | | | — | | | | 20,000,000 | |
| Recognition of share-based compensation expense related to override units | | | | | | | — | | | | | | | | 573,848 | | | | | | | | 338,731 | | | | 912,579 | |
| Adjustment to fair value for management common units | | | | | | | (8,013,120 | ) | | | | | | | — | | | | | | | | — | | | | (8,013,120 | ) |
| Net income allocated to management common units | | | | | | | 41,389,229 | | | | — | | | | — | | | | | | | | — | | | | 41,389,229 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at June 30, 2006 | | | 25,588,500 | | | $ | 168,206,669 | | | | 919,630 | | | $ | 1,176,229 | | | | 1,839,265 | | | $ | 733,918 | | | $ | 170,116,816 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| | | Three Months Ended
| |
| | | March 31, | |
| | | 2008 | | | 2007 | |
| | | (unaudited) | |
| | | (in thousands of dollars) | |
| |
| Cash flows from operating activities: | | | | | | | | |
| Net income (loss) | | $ | 22,221 | | | $ | (154,373 | ) |
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | | | | |
| Depreciation and amortization | | | 19,635 | | | | 14,235 | |
| Provision for doubtful accounts | | | 206 | | | | (235 | ) |
| Amortization of deferred financing costs | | | 495 | | | | 473 | |
| Loss on disposition of fixed assets | | | 16 | | | | 24 | |
| Share-based compensation | | | (383 | ) | | | 3,742 | |
| Minority interest in loss of subsidiaries | | | — | | | | (676 | ) |
| Changes in assets and liabilities: | | | | | | | | |
| Accounts receivable | | | (30,693 | ) | | | 44,627 | |
| Inventories | | | (31,642 | ) | | | (22,986 | ) |
| Prepaid expenses and other current assets | | | 75 | | | | 31 | |
| Insurance receivable | | | 1,085 | | | | — | |
| Insurance proceeds from flood | | | (1,500 | ) | | | — | |
| Other long-term assets | | | (3,159 | ) | | | 923 | |
| Accounts payable | | | (5,166 | ) | | | 46,357 | |
| Accrued income taxes | | | 5,201 | | | | 14,888 | |
| Deferred revenue | | | 16,623 | | | | 5,067 | |
| Other current liabilities | | | 5,315 | | | | 3,470 | |
| Payable to swap counterparty | | | 20,750 | | | | 129,344 | |
| Accrued environmental liabilities | | | 80 | | | | 485 | |
| Other long-term liabilities | | | 3,325 | | | | — | |
| Deferred income taxes | | | 1,710 | | | | (41,291 | ) |
| | | | | | | | | |
| Net cash provided by operating activities | | | 24,194 | | | | 44,105 | |
| | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | |
| Capital expenditures | | | (26,156 | ) | | | (107,363 | ) |
| | | | | | | | | |
| Net cash used in investing activities | | | (26,156 | ) | | | (107,363 | ) |
| | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | |
| Revolving debt payments | | | (123,000 | ) | | | — | |
| Revolving debt borrowings | | | 123,000 | | | | 29,500 | |
| Principal payments on long-term debt | | | (1,223 | ) | | | — | |
| Deferred costs of CVR Energy, Inc. initial public offering | | | — | | | | (553 | ) |
| Deferred costs of CVR Partners, LP initial public offering | | | (2,145 | ) | | | — | |
| | | | | | | | | |
| Net cash (used in) provided by financing activities | | | (3,368 | ) | | | 28,947 | |
| | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (5,330 | ) | | | (34,311 | ) |
| Cash and cash equivalents, beginning of period | | | 30,509 | | | | 41,919 | |
| | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 25,179 | | | $ | 7,608 | |
| | | | | | | | | |
| Supplemental disclosures: | | | | | | | | |
| Cash paid for income taxes, net of refunds (received) | | $ | (63 | ) | | $ | (20,895 | ) |
| Cash paid for interest | | | 11,841 | | | | 39 | |
| Non-cash investing and financing activities: | | | | | | | | |
| Accrual of construction in progress additions | | | (6,237 | ) | | | 13,204 | |
See accompanying notes to the condensed consolidated financial statements.
F-40F-67
CVR Energy, Inc. and Subsidiaries
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
| | | | | | | | | | | | | | |
| | | Immediate
| | | | | |
| | | Predecessor | | | | Successor | |
| | | 174 Days Ended
| | | | 49 Days Ended
| | | Six Months Ended
| |
| | | June 23,
| | | | June 30,
| | | June 30,
| |
| | | 2005 | | | | 2005 | | | 2006 | |
| | | | | | | (unaudited) | | | (unaudited) | |
| Cash flows from operating activities: | | | | | | | | | | | | | |
| Net income (loss) | | $ | 52,396,949 | | | | $ | (110,248,341 | ) | | $ | 41,757,209 | |
| Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities: | | | | | | | | | | | | | |
| Depreciation and amortization | | | 1,128,005 | | | | | 914,595 | | | | 24,022,108 | |
| Provision for doubtful accounts | | | (190,468 | ) | | | | 285,514 | | | | 79,716 | |
| Amortization of deferred financing costs | | | 812,166 | | | | | 53,119 | | | | 1,664,316 | |
| Loss on extinguishment of debt | | | 8,093,754 | | | | | — | | | | — | |
| Loss on disposition of fixed assets | | | — | | | | | — | | | | 437,952 | |
| Share-based compensation | | | 3,985,991 | | | | | 75,478 | | | | 912,579 | |
| Changes in assets and liabilities, net of effect of acquisition: | | | | | | | | | | | | | |
| Accounts receivable | | | (11,334,177 | ) | | | | (2,399,054 | ) | | | 7,975,871 | |
| Inventories | | | (59,045,550 | ) | | | | 15,442,988 | | | | (25,382,647 | ) |
| Prepaid expenses and other current assets | | | (937,543 | ) | | | | (3,450,145 | ) | | | (594,392 | ) |
| Other long-term assets | | | 3,036,659 | | | | | 12,561 | | | | (2,990,407 | ) |
| Accounts payable | | | 16,124,794 | | | | | 2,911,211 | | | | (3,179,621 | ) |
| Accrued income taxes | | | 4,503,574 | | | | | 371,747 | | | | 6,354,775 | |
| Deferred revenue | | | (9,073,050 | ) | | | | (22,651 | ) | | | (10,475,674 | ) |
| Other current liabilities | | | 1,254,196 | | | | | 2,915,659 | | | | (6,939,698 | ) |
| Payable to swap counterparty | | | — | | | | | 127,220,262 | | | | 112,246,434 | |
| Accrued environmental liabilities | | | (1,553,184 | ) | | | | — | | | | (925,900 | ) |
| Other long-term liabilities | | | (297,105 | ) | | | | — | | | | 1,471,269 | |
| Deferred income taxes | | | 3,803,937 | | | | | (56,448,266 | ) | | | (26,124,919 | ) |
| | | | | | | | | | | | | | |
| Net cash provided by (used in) operating activities | | | 12,708,948 | | | | | (22,365,323 | ) | | | 120,308,971 | |
| | | | | | | | | | | | | | |
| Cash flows from investing activities: | | | | | | | | | | | | | |
| Cash paid for acquisition of Immediate Predecessor, net of cash acquired | | | — | | | | | (685,125,669 | ) | | | — | |
| Capital expenditures | | | (12,256,793 | ) | | | | (352,385 | ) | | | (86,174,655 | ) |
| | | | | | | | | | | | | | |
| Net cash used in investing activities | | | (12,256,793 | ) | | | | (685,478,054 | ) | | | (86,174,655 | ) |
| | | | | | | | | | | | | | |
| Cash flows from financing activities: | | | | | | | | | | | | | |
| Revolving debt payments | | | (343,449 | ) | | | | (10,000,000 | ) | | | — | |
| Revolving debt borrowings | | | 492,308 | | | | | 25,686,016 | | | | — | |
| Proceeds from issuance of long-term debt | | | — | | | | | 500,000,000 | | | | 10,000,000 | |
| Principal payments on long-term debt | | | (375,000 | ) | | | | — | | | | (1,120,785 | ) |
| Payment of deferred financing costs | | | — | | | | | (23,645,890 | ) | | | — | |
| Issuance of members’ equity | | | — | | | | | 225,635,000 | | | | 20,000,000 | |
| Payment of note receivable | | | — | | | | | — | | | | 150,000 | |
| Distribution of members’ equity | | | (52,211,493 | ) | | | | — | | | | — | |
| | | | | | | | | | | | | | |
| Net cash provided by (used in) financing activities | | | (52,437,634 | ) | | | | 717,675,126 | | | | 29,029,215 | |
| | | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (51,985,479 | ) | | | | 9,831,749 | | | | 63,163,531 | |
| Cash and cash equivalents, beginning of period | | | 52,651,952 | | | | | — | | | | 64,703,524 | |
| | | | | | | | | | | | | | |
| Cash and cash equivalents, end of period | | $ | 666,473 | | | | $ | 9,831,749 | | | $ | 127,867,055 | |
| | | | | | | | | | | | | | |
| Supplemental disclosures | | | | | | | | | | | | | |
| Cash paid for income taxes | | $ | 27,040,000 | | | | $ | — | | | $ | 45,495,700 | |
| Cash paid for interest | | $ | 7,287,351 | | | | $ | — | | | $ | 24,712,898 | |
| Non-cash investing and financing activities: | | | | | | | | | | | | | |
| Accrual of construction in progress additions | | | | | | | | | | | $ | 25,109,043 | |
| Contributed capital through Leiber tax savings | | $ | 728,724 | | | | $ | — | | | $ | — | |
See accompanying notes to condensed consolidated financial statements.
F-41
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
March 31, 2008
(Unaudited)(unaudited)
| |
| (1) | Organization and History of the Company and Basis of Presentation |
Organization
The “Company” or “CVR” may be used to refer to CVR Energy, Inc. and, unless the context otherwise requires, its subsidiaries. Any references to the “Company” as of a date after June 24, 2005 and prior to October 16, 2007 (the date of the restructuring as further discussed in this note) are to Coffeyville Acquisition LLC (CALLC) and its subsidiaries.
The Company, through its wholly-owned subsidiaries, acts as an independent petroleum refiner and marketer in the mid-continental United States and a producer and marketer of upgraded nitrogen fertilizer products in North America. The Company’s operations include two business segments: the petroleum segment and the nitrogen fertilizer segment.
CALLC formed CVR Energy, Inc. as a wholly owned subsidiary, incorporated in Delaware in September 2006, in order to effect an initial public offering. 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 $280.0 million of term debt under the Company’s credit facility and to repay all indebtedness under the Company’s $25.0 million unsecured facility and $25.0 million secured facility, including related accrued interest through the date of repayment of approximately $5.9 million. Additionally, $50.0 million of net proceeds were used to repay outstanding revolving loan indebtedness under the Company’s credit facility.
In connection with the initial public offering, CVR became the indirect owner of the subsidiaries of CALLC and CALLC II. This was accomplished by CVR issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with the 628,667.20 for 1 stock split of CVR’s common stock and the mergers of two newly formed direct subsidiaries of CVR into Coffeyville Refining & Marketing Holdings, Inc. (Refining Holdco) and Coffeyville Nitrogen Fertilizers, Inc. (CNF). Concurrent with the merger of the subsidiaries and in accordance with a previously executed agreement, the Company’s chief executive officer received 247,471 shares of CVR common stock in exchange for shares that he owned of Refining Holdco and CNF. The shares were fully vested and were exchanged at fair market value.
The Company also issued 27,100 shares of common stock to its employees on October 24, 2007 in connection with the initial public offering. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, which does not include the non-vested shares noted below.
On October 24, 2007, 17,500 shares of non-vested common stock having a value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights with respect to these shares from the date of grant. The fair value of each share of non-vested stock was
F-68
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
measured based on the market price of the common stock as of the date of grant and is being amortized over the respective vesting periods. One-third of the non-vested award will vest on October 24, 2008, one-third will vest on October 24, 2009, and the final one-third will vest on October 24, 2010. Options to purchase 10,300 shares of common stock at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. These awards will vest over a three year service period. Fair value was measured using an option-pricing model at the date of grant.
Nitrogen Fertilizer Limited Partnership
In conjunction with the consummation of CVR’s initial public offering, CVR transferred Coffeyville Resources Nitrogen Fertilizer, LLC (CRNF), its nitrogen fertilizer business, to a newly created limited partnership (Partnership) in exchange for a managing general partner interest (managing GP interest), a special general partner interest (special GP interest, represented by special GP units) and a de minimis limited partner interest (LP interest, represented by special LP units). This transfer was not considered a business combination as it was a transfer of assets among entities under common control and, accordingly, balances were transferred at their historical cost. CVR concurrently sold the managing GP interest to Coffeyville Acquisition LLC III (CALLC III), an entity owned by CVR’s controlling stockholders and senior management at fair market value. The board of directors of CVR determined, after consultation with management, that the fair market value of the managing general partner interest was $10.6 million. This interest has been reflected as minority interest in the Consolidated Balance Sheet.
CVR owns all of the interests in the Partnership (other than the managing general partner interest and the associated incentive distribution rights (IDRs)) and is entitled to all cash distributed by the Partnership. The managing general partner is not entitled to participate in Partnership distributions except with respect to its IDRs, which entitle the managing general partner to receive increasing percentages (up to 48%) of the cash the Partnership distributes in excess of $0.4313 per unit in a quarter. However, the Partnership is not permitted to make any distributions with respect to the IDRs until the aggregate Adjusted Operating Surplus, as defined in the amended and restated partnership agreement, generated by the Partnership through December 31, 2009 has been distributed in respect of the units held by CVR and any common units issued in the Partnership’s initial public offering. The Partnership and its subsidiaries are currently guarantors under the credit facility of Coffeyville Resources, LLC (CRLLC), a wholly-owned subsidiary of CVR.
The Partnership is operated by CVR’s senior management pursuant to a services agreement among CVR, the managing general partner, and the Partnership. The Partnership is managed by the managing general partner and, to the extent described below, CVR, as special general partner. As special general partner of the Partnership, CVR has joint management rights regarding the appointment, termination, and compensation of the chief executive officer and chief financial officer of the managing general partner, has the right to designate two members of the board of directors of the managing general partner, and has joint management rights regarding specified major business decisions relating to the Partnership. CVR, the Partnership, the managing general partner and various of their subsidiaries also entered into a number of agreements to regulate certain business relations between the parties.
At March 31, 2008, the Partnership had 30,333 special LP units outstanding, representing 0.1% of the total Partnership units outstanding, and 30,303,000 special GP interests outstanding, representing 99.9% of the total Partnership units outstanding. In addition, the managing general partner owned the managing general partner interest and the IDRs. The managing general partner contributed 1% of CRNF’s interest to the Partnership in exchange for its managing general partner interest and the IDRs.
On February 28, 2008, the Partnership filed a registration statement with the Securities and Exchange Commission (SEC) to effect the contemplated initial public offering of its common units
F-69
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
representing limited partner interests. The registration statement provided that upon consummation of the Partnership’s initial public offering, CVR will indirectly own the Partnership’s special general partner and approximately 87% of the outstanding units of the Partnership. There can be no assurance that any such offering will be consummated on the terms described in the registration statement or at all. The offering is under review by the SEC and as a result the terms and resulting structure disclosed below could be materially different.
In connection with the Partnership’s initial public offering, CRLLC will contribute all of its special LP units to the Partnership’s special general partner and all of the Partnership’s special general partner interests and special limited partner interests will be converted into a combination of GP units and subordinated GP units. Following the initial public offering, as currently structured, the Partnership is expected to have the following partnership interests outstanding:
| | |
| • | 5,250,000 common units representing limited partner interests, all of which the Partnership will sell in the initial public offering; |
|
| • | 18,750,000 GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner; |
|
| • | 18,000,000 subordinated GP units representing special general partner interests, all of which will be held by the Partnership’s special general partner; and |
|
| • | a managing general partner interest, which is not entitled to any distributions, which is held by the Partnership’s managing general partner, and incentive distribution rights representing limited partner interests, all of which will be held by the Partnership’s managing general partner. |
Effective with the Partnership’s initial public offering, the partnership agreement will require that the Partnership distribute all of its cash on hand at the end of each quarter, less reserves established by its managing general partner, subject to a sustainability requirement in the event the Partnership elects to increase the quarterly distribution amount. The amount of available cash may be greater or less than the aggregate amount necessary to make the minimum quarterly distribution on all common units, GP units and subordinated units.
Subsequent to the initial public offering, as currently structured, the Partnership expects to make minimum quarterly distributions of $0.375 per common unit ($1.50 per common unit on an annualized basis) to the extent the Partnership has sufficient available cash. In general, cash distributions will be made each quarter as follows:
| | |
| • | First, to the holders of common units and GP units until each common unit and GP unit has received a minimum quarterly distribution of $0.375 plus any arrearages from prior quarters; |
|
| • | Second, to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.375; and |
|
| • | Third, to all unitholders, pro rata, until each unit has received a quarterly distribution of $0.4313. |
If cash distributions exceed $0.4313 per unit in a quarter, the Partnership’s managing general partner, as holder of the IDRs, will receive increasing percentages, up to 48%, of the cash the Partnership distributes in excess of $0.4313 per unit. However, the managing general partner will not be entitled to receive any distributions in respect of the IDRs until the Partnership has made cash distributions in an aggregate amount equal to the Partnership’s adjusted operating surplus generated during the period from the closing of the Partnership’s initial public offering until December 31, 2009.
During the subordination period, the subordinated units will not be entitled to receive any distributions until the common units and GP units have received the minimum quarterly distribution of
F-70
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
$0.375 per unit plus any arrearages from prior quarters. The subordination period begins on the closing date of the Partnership’s initial public offering and will end once the Partnership meets the financial tests in the partnership agreement. When the subordination period ends, all subordinated units will convert into GP units or common units on a one-for-one basis, and the common units and GP units will no longer be entitled to arrearages.
If the Partnership meets the financial tests in the partnership agreement for any three consecutive four-quarter periods ending on or after the first quarter whose last day is at least three years after the closing of Partnership Offering, 25% of the subordinated GP units will convert into GP units on a one-for-one basis. If the Partnership meets these financial tests for any three consecutive four-quarter periods ending on or after the first quarter whose last day is at least four years after the closing of the Partnership Offering, an additional 25% of the subordinated GP units will convert into GP units on a one-for-one basis. The early conversion of the second 25% of the subordinated GP units may not occur until at least one year following the end of the last four-quarter period in respect of which the first 25% of the subordinated GP units were converted. If the subordinated GP units have converted into subordinated LP units at the time the financial tests are met they will convert into common units, rather than GP units. In addition, the subordination period will end if the managing general partner is removed as the managing general partner where “cause” (as defined in the partnership agreement) does not exist and no units held by any holder of subordinated units or its affiliates are voted in favor of that removal.
The partnership agreement authorizes the Partnership to issue an unlimited number of additional units and rights to buy units for the consideration and on the terms and conditions determined by the managing general partner without the approval of the unitholders.
The Partnership will distribute all cash received by it or its subsidiaries in respect of accounts receivable existing as of the closing of the initial public offering exclusively to its special general partner.
The managing general partner, together with the special general partner, manages and operates the Partnership. Common unitholders will only have limited voting rights on matters affecting the Partnership. In addition, common unitholders will have no right to elect either of the general partners or the managing general partner’s directors on an annual or other continuing basis.
If at any time the managing general partner and its affiliates own more than 80% of the common units, the managing general partner will have the right, but not the obligation, to purchase all of the remaining common units at a purchase price equal to the greater of (x) the average of the daily closing price of the common units over the 20 trading days preceding the date three days before notice of exercise of the call right is first mailed and (y) the highestper-unit price paid by the managing general partner or any of its affiliates for common units during the90-day period preceding the date such notice is first mailed.
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 Exhange Commission.SEC. The consolidated financial statements include the accounts of CVR Energy, Inc. and its majority-owned direct and indirect subsidiaries. The ownership interests of minority investors in its subsidiaries (CVR or the Company).are recorded as minority interest. All significant intercompany accounts and transactions have been eliminated in consolidation. Certain information and footnotes required for the complete financial statements under U.S. generally accepted accounting principlesGAAP have not been includedcondensed or omitted pursuant to such rules and regulations. These unaudited condensed consolidated financial statements should be read in conjunction with the December 31, 20052007 audited consolidated financial statements and notes thereto of CVR.included in CVR’s Annual Report onForm 10-K/A for the year ended December 31, 2007.
F-71
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
In the opinion of the Company’s management, the accompanying unaudited condensed consolidated financial statements reflect all adjustments (consisting only of normal recurring adjustments) that are necessary to fairly present the financial position of the Company as of March 31, 2008 and December 31, 2005 and June 30, 2006, and2007, the results of operations for the three months ended March 31, 2008 and 2007, and the cash flows for the 174 days ended June 23, 2005, the 49 days ended June 30, 2005 and the sixthree months ended June 30, 2006.March 31, 2008 and 2007.
Results of operations and cash flows for the interim periods presented are not necessarily indicative of the results that will be realized for the year ending December 31, 20062008 or any other interim period. The preparation of financial statements in conformity with accounting principlesU.S. generally accepted in the United Statesaccounting principles requires management to make estimates and assumptions that affectedaffect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from those estimates.
In connection with CVR’s initial public offering, $0.5 million of deferred offering costs for the three months ended March 31, 2007 were previously presented in operating activities in the interim financial statements. Such amounts have now been reflected as financing activities for the three months ended March 31, 2007 in the accompanying Consolidated Statements of Cash Flows. The impact on the prior financial statements of this revision is not considered material.
| |
| (2) | Organization and Nature of Business and the AcquisitionsRecent Accounting Pronouncements |
In September 2006, the Financial Accounting Standards Board (FASB) issued Statement on Financial Accounting Standards (SFAS) No. 157,GeneralFair Value Measurements, which establishes a framework for measuring fair value in GAAP and expands disclosures about fair value measurements. SFAS 157 states that fair value is “the price that would be received to sell the asset or paid to transfer the liability (an exit price), not the price that would be paid to acquire the asset or received to assume the liability (an entry price)”. The standard’s provisions for financial assets and financial liabilities, which became effective January 1, 2008, had no material impact on the Company’s financial position or results of operations. At March 31, 2008, the only financial assets and financial liabilities that are measured at fair value on a recurring basis are the Company’s derivative instruments. See Note 14, “Fair Value Measurements”.
CVR Energy, Inc. (CVR) was incorporatedIn February 2008, the FASB issued FASB Staff Position157-2 which defers the effective date of SFAS 157 for nonfinancial assets and nonfinancial liabilities, except for items that are recognized or disclosed at fair value in Delaware in September 2006. CVR has assumed that concurrent with this offering,an entity’s financial statements on a newly formed direct subsidiaryrecurring basis (at least annually). The Company will be required to adopt SFAS 157 for these nonfinancial assets and nonfinancial liabilities as of CVR’sJanuary 1, 2009. Management believes the adoption of SFAS 157 deferral provisions will merge with Coffeyville Refining & Marketing, Inc. (CRM) andnot have a separate newly formed direct subsidiary of CVR’s will merge with Coffeyville Nitrogen Fertilizers, Inc. (CNF) which will make CRM and CNF direct wholly owned subsidiaries of CVR.material impact on the Company’s financial position or earnings.
SuccessorIn February 2007, the FASB issued SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities. Under this standard, an entity is a Delaware limited liability company formed May 13, 2005. Successor, acting through wholly-owned subsidiaries,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 an independent petroleum refinerrequired to display the fair value of those assets and marketerliabilities for which the Company has chosen to use fair value on the face of the balance sheet. This standard does not eliminate the disclosure requirements about fair value measurements included in SFAS No. 107,Disclosures about Fair Value of Financial Instruments. The provisions of SFAS 159 were effective for CVR as of January 1, 2008. The Company did not elect the fair value option under this standard upon adoption. Therefore, the adoption of SFAS 159 did not impact the Company’s consolidated financial statements as of the quarter ended March 31, 2008.
In December 2007, the FASB issued SFAS No. 141(R),Business Combinations. This statement defines the acquirer as the entity that obtains control of one or more businesses in the mid-continental United Statesbusiness combination, establishes the acquisition date as the date that the acquirer achieves control and a producerrequires the acquirer to recognize the assets acquired, liabilities assumed and marketer of upgraded nitrogen fertilizer products in North America.
On June 24, 2005, Coffeyville Acquisition LLC and subsidiaries (Successor) acquired all of the outstanding stock of Coffeyville Refining & Marketing, Inc. (CRM); Coffeyville Nitrogen Fertilizers, Inc. (CNF); Coffeyville Crude Transportation, Inc. (CCT); Coffeyville Pipeline, Inc. (CP); and Coffeyville Terminal, Inc. (CT) (collectively, CRIncs) from Coffeyville Group Holdings, LLC (Immediate Predecessor) (the Subsequent Acquisition). Immediate Predecessor was a Delaware limited liability company formed in October 2003. As a result of this transaction, CRIncs ownership increased to 100% of CL JV Holdings, LLC (CLJV), a Delaware limited liability company formed on September 27, 2004. CRIncs directly and indirectly, through CLJV, collectively own 100% of Coffeyville Resources, LLC (CRLLC) and its wholly owned subsidiaries, Coffeyville Resources Refining & Marketing, LLC (CRRM); Coffeyville Resources Nitrogen Fertilizers, LLC (CRNF); Coffeyville Resources Crude Transportation, LLC (CRCT); Coffeyville Resources Pipeline, LLC (CRP); and Coffeyville Resources Terminal, LLC (CRT).any non-controlling
F-42F-72
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)Notes to the Condensed Consolidated Financial Statements — (Continued)
Successor had no financial statement activity during the period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil, and gasoline option agreements entered into with a related party (see notes 7 and 8)interest at their fair values as of May 16, 2005. These agreements expired unexercisedthe acquisition date. This statement also requires that acquisition-related costs of the acquirer be recognized separately from the business combination and will generally be expensed as incurred. CVR will be required to adopt this statement as of January 1, 2009. The impact of adopting SFAS 141R will be limited to any future business combinations for which the acquisition date is on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying condensed consolidated statements of operations as loss on derivatives for the 49 days ended June 30, 2005.or after January 1, 2009.
SinceIn December 2007, the assetsFASB issued SFAS No. 160,Non-controlling Interests in Consolidated Financial Statements — an amendment of ARB No. 51.SFAS 160 establishes accounting and liabilities of Successor are each presented on a different cost basis than thatreporting standards for the period beforenon-controlling interest in a subsidiary and for the acquisition,deconsolidation of a subsidiary. It clarifies that a non-controlling interest in a subsidiary is an ownership interest in the consolidated entity that should be reported as equity in the consolidated financial informationstatements. SFAS 160 requires retroactive adoption of the presentation and disclosure requirements for Successor and Immediate Predecessor are not comparable.existing minority interests. All other requirements of SFAS 160 must be applied prospectively. SFAS 160 is effective for CVR beginning January 1, 2009. The Company is currently evaluating the potential impact of the adoption of SFAS 160 on its consolidated financial statements.
In March 2008, the FASB issued SFAS No. 161,Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133. This statement will change the disclosure requirements for derivative instruments and hedging activities. Entities are required to provide enhanced disclosures about how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under Statement 133 and its related interpretations, and how derivative instruments and related hedged items affect an entity’s financial position, net earnings, and cash flows. The Subsequent Acquisition
On May 15, 2005, Successor and Immediate Predecessor entered into an agreement whereby Successor acquired 100%Company will be required to adopt this statement as of the outstanding stock of CRIncs with an effective date of June 24, 2005 for $673,273,440, including the assumption of $353,084,637 of liabilities. Successor also paid transaction costs of $12,518,702, which consisted of legal, accounting, and advisory fees of $5,782,740 paid to various parties, and transaction fees of $6,000,000 and $735,962 in expenses related to the acquisition paid to institutional investors (see note 8). Successor’s primary reason for the purchase was the belief that long-term fundamentals for the refining industry were strengthening and the capital requirement was within its desired investment range. The cost of the Subsequent Acquisition was financed through long-term borrowings of approximately $500 million, short-term borrowings of approximately $12.6 million, and the issuance of common units for approximately $227.7 million. The allocation of the purchase price at June 24, 2005, the date of the Subsequent Acquisition, is as follows:
| | | | | |
| Assets acquired | | | | |
| Cash | | $ | 666,473 | |
| Accounts receivable | | | 37,328,997 | |
| Inventories | | | 156,171,291 | |
| Prepaid expenses and other current assets | | | 4,865,241 | |
| Intangibles, contractual agreements | | | 1,322,000 | |
| Goodwill | | | 83,774,885 | |
| Other long-term assets | | | 3,837,647 | |
| Property, plant, and equipment | | | 750,910,245 | |
| | | | | |
| Total assets acquired | | $ | 1,038,876,779 | |
| | | | | |
| Liabilities assumed | | | | |
| Accounts payable | | $ | 47,259,070 | |
| Other current liabilities | | | 16,017,210 | |
| Current income taxes | | | 5,076,012 | |
| Deferred income taxes | | | 276,888,816 | |
| Other long-term liabilities | | | 7,843,529 | |
| | | | | |
| Total liabilities assumed | | $ | 353,084,637 | |
| | | | | |
| Cash paid for acquisition of Immediate Predecessor | | $ | 685,792,142 | |
| | | | | |
F-43
CVR Energy, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
Pro forma revenue would be unchanged for the periods presented. Unaudited pro forma net income (loss) as if the Subsequent Acquisition and subsequent debt refinancing had occurred on January 1, 2005 compared2009. The adoption of SFAS 161 is not expected to historical net income presented below is as follows (in thousands):have a material impact on the Company’s consolidated financial statements.
| | | | | | | | | |
| | | Historical | | Pro Forma |
| | | (non-GAAP) | | |
| |
| six months ended June 30, 2005 | | $ | (57,851 | )(1) | | $ | (73,290 | ) |
| |
(1) | Reflects the sum of the results of operations for the periods ended June 23, 2005 and June 30, 2005. |
| |
| (3) | Unaudited Pro Forma InformationShare Based Compensation |
Earnings per share is calculated on a pro forma basis, based on an assumed number of shares outstanding at the time of thePrior to CVR’s initial public offering, CVR’s subsidiaries were held and operated by CALLC, a limited liability company. Management of CVR holds an equity interest in CALLC. CALLC had issued non-voting override units to certain management members who held common units of CALLC. There were no required capital contributions for the override operating units. In connection with respect to the existing shares. Pro forma earnings per share assumes that in conjunction with theCVR’s initial public offering in October 2007, CALLC was split into two entities: CALLC and CALLC II. In connection with this split, management’s equity interest in CALLC, including both their common units and non-voting override units, was split so that half of management’s equity interest was in CALLC and half was in CALLC II. CALLC was historically the two direct wholly owned subsidiariesprimary reporting company and CVR’s predecessor. In connection with the restructuring of Successor will mergethe Company related to the Partnership, CALLC III issued non-voting override units to certain management members of CALLC III.
CVR, CALLC, CALLC II and CALLC III account for share-based compensation in accordance with twoSFAS No. 123(R),Share-Based PaymentsandEITF 00-12,Accounting by an Investor for Stock-Based Compensation Granted to Employees of an Equity Method Investee. CVR has recorded non-cash share-based compensation expense from CALLC, CALLC II and CALLC III.
In accordance with SFAS 123(R), CVR, CALLC, CALLC II and CALLC III apply a fair value based measurement method in accounting for share-based compensation. In accordance withEITF 00-12, CVR recognizes the costs of the share-based compensation incurred by CALLC, CALLC II and CALLC III on its behalf, primarily in selling, general, and administrative expenses (exclusive of depreciation and amortization), and a corresponding capital contribution, as the costs are incurred on its behalf, following the guidance inEITF 96-18,Accounting for Equity Investments That Are Issued to Other Than Employees for Acquiring, or in Conjunction with Selling Goods or Services, which requires remeasurement at each reporting period. At March 31, 2008, CVR’s direct wholly owned subsidiaries, common stock closing price was utilized to determine the fair value of the override units of CALLC and CALLC II. The estimated fair
F-73
CVR will effectENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
value per unit reflects a -for- stock split priorratio of override units to completion of this offering, and CVR will issue shares of common stock in this offering. No effectstock. The estimated fair value of the override units of CALLC III has been givendetermined using a binomial and probability-weighted expected return method which utilizes CALLC III’s cash flow projections, which are representative of the nature of interests held by CALLC III in the Partnership.
The following describes the share-based compensation plans of CALLC, CALLC II, CALLC III and CRLLC, CVR’s indirect wholly owned subsidiary.
919,630 Override Operating Units at an Adjusted Benchmark Value of $11.31 per Unit
In June 2005, CALLC issued 919,630 non-voting override operating units to any sharescertain management members holding common units of CALLC. There were no required capital contributions for the override operating units.
In accordance with SFAS 123(R),Share Based Compensation, using the Monte Carlo method of valuation, the estimated fair value of the override operating units on June 24, 2005 was $3,605,000. Pursuant to the forfeiture schedule described below, CVR recognized compensation expense over the service period for each separate portion of the award for which the forfeiture restriction lapsed as if the award was, in substance, multiple awards. Compensation expense of $(558,000) and $285,000 was recognized for the three months ending March 31, 2008 and 2007, respectively.
In connection with the split of CALLC into two entities on October 16, 2007, management’s equity interest in CALLC was split so that might behalf of management’s equity interest is in CALLC and half is in CALLC II. The restructuring resulted in a modification of the existing awards under SFAS 123(R). However, because the fair value of the modified award equaled the fair value of the original award before the modification, there was no accounting consequence as a result of the modification. However, due to the restructuring, the employees of CVR and the Partnership no longer hold share-based awards in a parent company. Due to the change in status of the employees related to the awards, CVR recognized compensation expense for the newly measured cost attributable to the remaining vesting (service) period prospectively from the date of the change in status.
Significant assumptions used in the valuation were as follows:
| | | | |
| | | | Remeasurement
|
| | Grant Date | | Date |
|
| Estimated forfeiture rate | | None | | None |
| Explicit service period | | Based on forfeiture
schedule below | | Based on forfeiture
schedule below |
| Grant date fair value | | $5.16 per share | | N/A |
| March 31, 2008 CVR closing stock price | | N/A | | $23.03 |
| March 31, 2008 estimated fair value | | N/A | | $47.88 per share |
| Marketability and minority interest discounts | | 24% discount | | 15% discount |
| Volatility | | 37% | | N/A |
72,492 Override Operating Units at a Benchmark Value of $34.72 per Unit
On December 28, 2006, CALLC issued 72,492 additional non-voting override operating units to a management member who held common units of CALLC. There were no required capital contributions for the override operating units.
In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections resulted in an estimated fair value of the override operating units on December 28, 2006 of $473,000. Management believed that this offeringmethod 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
F-74
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
value of the override units. These override operating units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with the accounting method noted above and pursuant to the exercise byforfeiture schedule described below, CVR recognized compensation expense of $6,000 and $100,000 for the underwriters of their option. The pro forma balance sheet assumesperiods ending March 31, 2008 and 2007, respectively.
Significant assumptions used in the transactions noted above occurred on June 30, 2006.valuation were as follows:
| | | | |
(4) | | | | Remeasurement
|
| | Members’ EquityGrant Date
| | Date |
|
| Estimated forfeiture rate | | None | | None |
| Explicit service period | | Based on forfeiture | | Based on forfeiture |
| | schedule below | | schedule below |
| Grant date fair value | | $8.15 per share | | N/A |
| March 31, 2008 CVR closing stock price | | N/A | | $23.03 |
| March 31, 2008 estimated fair value | | N/A | | $28.68 per share |
| Marketability and minority interest discounts | | 20% discount | | 15% discount |
| Volatility | | 41% | | N/A |
CVR accounts
Override operating units are forfeited upon termination of employment for changes in redemptioncause. In the event of all other terminations of employment, the override operating units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:
| | | | |
| | Forfeiture
| |
Minimum Period Held | | Rate | |
|
| 2 years | | | 75 | % |
| 3 years | | | 50 | % |
| 4 years | | | 25 | % |
| 5 years | | | 0 | % |
On the tenth anniversary of the issuance of override operating units, such units convert into an equivalent number of override value units.
1,839,265 Override Value Units at an Adjusted Benchmark Value of these$11.31 per Unit
In June 2005, CALLC issued 1,839,265 non-voting override value units into certain management members who held common units of CALLC. There were no required capital contributions for the periodoverride value units.
In accordance with SFAS 123(R), using the changes occur and adjustsMonte Carlo method of valuation, the carryingestimated fair value of the Capital Subjectoverride value units on June 24, 2005 was $4,065,000. For the override value units, CVR is recognizing compensation expense ratably over the implied service period of 6 years. These override value units are being accounted for the same as the override operating units with an adjusted benchmark value of $11.31 per unit. In accordance with the accounting method noted above, CVR recognized compensation expense of $533,000 and $169,000 for the three months ending March 31, 2008 and 2007, respectively.
F-75
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to Redemptionthe Condensed Consolidated Financial Statements — (Continued)
Significant assumptions used in the valuation were as follows:
| | | | |
| | | | Remeasurement
|
| | Grant Date | | Date |
|
| Estimated forfeiture rate | | None | | None |
| Derived service period | | 6 years | | 6 years |
| Grant date fair value | | $2.91 per share | | N/A |
| March 31, 2008 CVR closing stock price | | N/A | | $23.03 |
| March 31, 2008 estimated fair value | | N/A | | $47.88 per share |
| Marketability and minority interest discounts | | 24% discount | | 15% discount |
| Volatility | | 37% | | N/A |
144,966 Override Value Units at a Benchmark Value of $34.72 per Unit
On December 28, 2006, CALLC issued 144,966 additional non-voting override value units to equala management member who held common units of CALLC. There were no required capital contributions for the redemptionoverride value units.
In accordance with SFAS 123(R), a combination of a binomial model and a probability-weighted expected return method which utilized CVR’s cash flow projections resulted in an estimated fair value of the override value units on December 28, 2006 of $945,000. Management believed that this method was preferable for the valuation of the override units as it allowed a better integration of the cash flows with other inputs, including the timing of potential exit events that impacted the estimated fair value of the override units. These override value units are being accounted for the same as the override operating units with the adjusted benchmark value of $11.31 per unit. In accordance with the accounting method noted above, CVR recognized compensation expense of $91,000, and $52,000 for the three months ending March 31, 2008 and 2007, respectively.
Significant assumptions used in the valuation were as follows:
| | | | |
| | | | Remeasurement
|
| | Grant Date | | Date |
|
| Estimated forfeiture rate | | None | | None |
| Derived service period | | 6 years | | 6 years |
| Grant date fair value | | $8.15 per share | | N/A |
| March 31, 2008 CVR closing stock price | | N/A | | $23.03 |
| March 31, 2008 estimated fair value | | N/A | | $28.68 per share |
| Marketability and minority interest discounts | | 20% discount | | 15% discount |
| Volatility | | 41% | | N/A |
Unless the compensation committee of the board of directors of CVR takes an action to prevent forfeiture, override value units are forfeited upon termination of employment for any reason except that in the event of termination of employment by reason of death or disability, all override value units are initially subject to forfeiture with the number of units subject to forfeiture reducing as follows:
| | | | |
| | Subject to
| |
| | Forfeiture
| |
Minimum Period Held | | Percentage | |
|
| 2 years | | | 75 | % |
| 3 years | | | 50 | % |
| 4 years | | | 25 | % |
| 5 years | | | 0 | % |
F-76
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
At March 31, 2008, assuming no change in the estimated fair value at March 31, 2008, there was approximately $59.2 million of unrecognized compensation expense related to non-voting override units. This is expected to be recognized over a remaining period of four years as follows (in thousands):
| | | | | | | | | |
| | | Override
| | | Override
| |
| | | Operating Units | | | Value Units | |
| |
| Nine months ending December 31, 2008 | | $ | 4,927 | | | $ | 11,688 | |
| Year ending December 31, 2009 | | | 3,762 | | | | 15,585 | |
| Year ending December 31, 2010 | | | 1,120 | | | | 15,584 | |
| Year ending December 31, 2011 | | | — | | | | 6,569 | |
| | | | | | | | | |
| | | $ | 9,809 | | | $ | 49,426 | |
| | | | | | | | | |
138,281 Override Units with a Benchmark Amount of $10
In October 2007, CALLC III issued 138,281 non-voting override units to certain management members who held common units of CALLC III. There were no required capital contributions for the override units.
In accordance with SFAS 123(R),Share Based Compensation, using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flow projections, the estimated fair value of the operating units at March 31, 2008 was immaterial. CVR recognizes compensation costs for this plan based on the fair value of the awards at the end of each reporting period in accordance with anEITF 00-12 using the guidance inEITF 96-18. In accordance withEITF 00-12, as a noncontributing investor, CVR also recognized income equal and offsetting adjustment to Members’ Equity. Nonethe amount that its interest in the Partnership’s net book value has increased (that is, its percentage share of the Capital Subjectcontributed capital recognized by the investee) as a result of the disproportionate funding of the compensation costs. This amount equaled the compensation expense recognized for these awards for the three months ended March 31, 2008. Pursuant to Redemption was redeemable at Decemberthe forfeiture schedule reflected above, CVR recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed. As of March 31, 2005 or June 30, 2006.2008, these override units are fully vested.
At June 30, 2006,Significant assumptions used in the Capital Subjectvaluation were as follows:
| | |
| Estimated forfeiture rate | | None |
| March 31, 2008 estimated fair value | | $0.004 per share |
| Marketability and minority interest discount | | 15% discount |
| Volatility | | 36.2% |
642,219 Override Units with a Benchmark Amount of $10
On February 15, 2008, CALLC III issued 642,219 non-voting override units to Redemption was revalued through an independent appraisal process,certain management members of CALLC III. There were no required capital contributions for the override units.
In accordance with SFAS 123(R),Share Based Compensation,using a binomial and a probability-weighted expected return method which utilized CALLC III’s cash flows projections, the value was determined to be $55.18 per unit. Accordingly, the carryingestimated fair value of the Capital Subjectoperating units at March 31, 2008 was immaterial. CVR recognizes compensation costs for this plan based on the fair value of the awards at the end of each reporting period in accordance withEITF 00-12 using the guidance inEITF 96-18. In accordance withEITF 00-12, as a noncontributing investor, CVR also recognized income equal to Redemptionthe amount that its interest in the investee’s net book value has increased (that is, its percentage share of the contributed capital recognized by $8,013,120the investee) as a result of the disproportionate funding of the compensation costs. CVR recognized compensation expense of $600 for the six month periodthree months ended June 30, 2006 with an equalMarch 31, 2008. Pursuant to the forfeiture schedule of the amended and offsetting decrease to Members’ Equity.restated partnership agreement of CALLC III,
F-77
CVR ENERGY, INC. AND SUBSIDIARIES
Successor,Notes to the Condensed Consolidated Financial Statements — (Continued)
CVR recognized compensation expense over this service period for each portion of the award for which the forfeiture restriction has lapsed. Of the 642,219��units issued, 109,720 were immediately vested upon issuance and the remaining units are subject to the forfeiture schedule.
Significant assumptions used in the valuation were as follows:
| | |
| Estimated forfeiture rate | | None |
| Derived Service Period | | Based on forfeiture schedule |
| March 31, 2008 estimated fair value | | $0.004 per share |
| Marketability and minority interest discount | | 15% discount |
| Volatility | | 36.2% |
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. The total combined interest of the Phantom Unit Plan and the override units (combined Profits Interest) cannot exceed 15% of the notional and aggregate equity interests of the Company. As of June 30, 2006,March 31, 2008, the issued Profits Interest (combined phantom plan and override units) represented 11.55%15% of combined common unit interest and Profits Interest of the Company.CALLC and CALLC II. The Profits Interest was comprised of 9.45%11.1% and 2.10%3.9% of override interest and phantom interest, respectively. Based onIn accordance with SFAS 123(R), using the March 31, 2008 CVR stock closing price to determine the Company’s equity value, through an independent valuation process, the service phantom interest was valued at $11.57 per point and the performance phantom interest waswere both valued at $9.81$47.88 per point. Based on the vestingCVR has recorded approximately $28,670,000 and forfeiture provision of the Plan, we have recorded $1,471,269$29,217,000 in other long-term liabilitiespersonnel accruals as of June 30, 2006.March 31, 2008 and December 31, 2007, respectively. Compensation expense for the233-day three month periods ending March 31, 2008 and 2007 related to the Phantom Unit Appreciation Plan was $(547,000) and $3,136,000, respectively.
At March 31, 2008, assuming no change in the estimated fair value at March 31, 2008, there was approximately $20.6 million of unrecognized compensation expense related to the Phantom Unit Appreciation Plan. This is expected to be recognized over a remaining period endingof four years.
Long Term Incentive Plan
CVR has a Long Term Incentive Plan. There were no awards granted under this plan in the first quarter of 2008.
On October 24, 2007, 17,500 shares of non-vested common stock having a fair value of $365,000 at the date of grant were issued to outside directors. Although ownership of the shares does not transfer to the recipients until the shares have vested, recipients have dividend and voting rights on these shares from the date of grant. The fair value of each share of non-vested common stock was measured based on the market price of the common stock as of the date of grant and will be amortized over the respective vesting periods. One-third will vest on October 24, 2008, 2009 and 2010, respectively.
Options to purchase 10,300 shares of common stock at an exercise price of $19.00 per share were granted to outside directors on October 22, 2007. Options to purchase 8,600 shares of common stock at an exercise price of $24.73 per share were granted to outside directors on December 21, 2007.
During the quarter there were no issuances, forfeitures or vesting of stock options or non-vested shares.
F-44F-78
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)Notes to the Condensed Consolidated Financial Statements — (Continued)
DecemberAs of March 31, 20052008, there was approximately $0.2 million of total unrecognized compensation cost related to non-vested shares to be recognized over a weighted-average period of approximately one year. Compensation expense recorded for the three month periods ending March 31, 2008 and six month period ended June 30, 20062007 related to the Phantom Unit Plannon-vested stock was $95,019$56,000 and $1,376,250,$0, respectively. Compensation expense for the three month periods ending March 31, 2008 and 2007 related to stock options was $36,000 and $0, respectively.
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 thefirst-in, first-out (FIFO) method,cost, 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 theability-to-bare process, whereby raw materials and production costs are allocated towork-in-process and finished products based on their relative fair values. Other inventories, including other raw materials, spare parts, and supplies, are valued at the lower of averagemoving-average cost, which approximates FIFO, or market. The cost of inventories includes inbound freight costs.
Inventories consisted of the following (in thousands):
| | | | | | | | | | |
| | | Successor | | |
| | | December 31,
| | June 30,
| | | | | | | | | |
| | | 2005 | | 2006 | | | March 31,
| | December 31,
| |
| | | | | (unaudited) | | | 2008 | | 2007 | |
| |
| Finished goods | | $ | 58,513 | | | $ | 55,078 | | | $ | 123,814 | | | $ | 109,394 | |
| Raw materials and catalysts | | | 47,437 | | | | 85,436 | | | | 123,042 | | | | 92,104 | |
| In-process inventories | | | 33,397 | | | | 16,588 | | | | 17,045 | | | | 29,817 | |
| Parts and supplies | | | 14,929 | | | | 22,556 | | | | 24,514 | | | | 23,340 | |
| | | | | | | | | | | |
| | | $ | 154,276 | | | $ | 179,658 | | | $ | 288,415 | | | $ | 254,655 | |
| | | | | | | | | | | |
| |
| (5) | Property, Plant, and Equipment |
A summary of costs for property, plant, and equipment is as follows (in thousands):
| | | | | | | | | |
| | | March 31,
| | | December 31,
| |
| | | 2008 | | | 2007 | |
| |
| Land and improvements | | $ | 13,170 | | | $ | 13,058 | |
| Buildings | | | 19,351 | | | | 17,541 | |
| Machinery and equipment | | | 1,277,292 | | | | 1,108,858 | |
| Automotive equipment | | | 5,752 | | | | 5,171 | |
| Furniture and fixtures | | | 6,420 | | | | 6,304 | |
| Leasehold improvements | | | 929 | | | | 929 | |
| Construction in progress | | | 30,859 | | | | 182,046 | |
| | | | | | | | | |
| | | | 1,353,773 | | | | 1,333,907 | |
| Accumulated depreciation | | | 161,231 | | | | 141,733 | |
| | | | | | | | | |
| | | $ | 1,192,542 | | | $ | 1,192,174 | |
| | | | | | | | | |
Capitalized interest recognized as a reduction in interest expense for the periods ended March 31, 2008, and March 31, 2007 totaled approximately $1,118,000 and $4,079,000, respectively.
| |
| (6) | Planned Major Maintenance Costs |
The direct-expense method of accounting is used for planned major maintenance activities. Maintenance costs are recognized as expense when maintenance services are performed. The
F-79
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
Coffeyville nitrogen fertilizer plant last completed a major scheduled turnaround in the third quarter of 2006 and is scheduled to complete a turnaround in the fourth quarter of 2008. The Coffeyville refinery started a major scheduled turnaround in February 2007 with completion in April 2007. Costs of $66,003,000 associated with the 2007 refinery turnaround were included in direct operating expenses (exclusive of depreciation and amortization) for the three months ending March 31, 2007.
Cost of product sold (exclusive of depreciation and amortization) includes cost of crude oil, other feedstocks, blendstocks, pet coke expense and freight and distribution expenses. Cost of product sold excludes depreciation and amortization of $600,000 and $619,000 for the three months ended March 31, 2008 and March 31, 2007, respectively.
Direct operating expenses (exclusive of depreciation and amortization) includes direct costs of labor, maintenance and services, energy and utility costs, environmental compliance costs as well as chemicals and catalysts and other direct operating expenses. Direct operating expenses excludes depreciation and amortization of $18,703,000 and $13,530,000 for the three months ended March 31, 2008 and March 31, 2007, respectively.
Selling, general and administrative expenses (exclusive of depreciation and amortization) consists primarily of legal expenses, treasury, accounting, marketing, human resources and maintaining the corporate offices in Texas and Kansas. Selling, general and administrative expenses excludes depreciation and amortization of $332,000 and $86,000 for the three months ended March 31, 2008 and March 31, 2007, respectively.
| |
| (8) | Note Payable and Capital Lease Obligations |
The Company entered into an insurance premium finance agreement with Cananwill, Inc. in July 2007 to finance the purchase of its property, liability, cargo and terrorism policies. The original balance of the note was $7.6 million and required repayment in nine equal installments with final payment due in April 2008. The balance due was paid in full in April 2008. As of March 31, 2008 and December 31, 2007, $0.8 and $3.4 million related to this insurance premium finance agreement was included in note payable and capital lease obligations on the Consolidated Balance Sheet, respectively.
The Company entered into two capital leases in 2007 to lease platinum required in the manufacturing of a new catalyst. The recorded lease obligations fluctuate with the platinum market price. The leases will terminate on the date an equal amount of platinum is returned to each lessor, with the difference to be paid in cash. One lease was settled and terminated in January 2008. At March 31, 2008 and December 31, 2007 the lease obligations were recorded at approximately $10.4 million and $8.2 million on the Consolidated Balance Sheets, respectively.
| |
| (9) | Flood and Insurance Related Matters |
On June 30, 2007, torrential rains in southeast Kansas caused the Verdigris River to overflow its banks and flood the town of Coffeyville, Kansas. As a result, the Company’s refinery and nitrogen fertilizer plant were severely flooded, resulting in significant damage to the refinery assets. The nitrogen fertilizer facility also sustained damage, but to a much lesser degree. The Company maintained property damage insurance which included damage caused by a flood, of up to $300 million per occurrence, subject to deductibles and other limitations. The deductible associated with the property damage was $2.5 million.
Management continues to work closely with 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. At March 31, 2008, total accounts receivable from insurance was $85.7 million. The receivable balance is segregated between current and long-term in the Company’s Consolidated
F-80
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
Balance Sheet in relation to the nature and classification of the items to be settled. Management believes the recovery of the receivable from the insurance carriers is probable. Approximately $11.4 million of the receivable recorded at March 31, 2008 relates to the crude oil discharge and the remaining $74.3 million relates to the flood damage to the Company’s facilities. While management believes that the Company’s property insurance should cover substantially all of the estimated total 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 this45-day period and the refinery restarted its last operating unit in 48 days, a substantial portion of the lost profits incurred because of the flood cannot be claimed under insurance. The Company continues to assess its policies to determine how much, if any, of its lost profits after the45-day period are recoverable. No amounts for recovery of lost profits under the Company’s business interruption policy have been recorded in the accompanying consolidated financial statements.
The Company has recorded pretax costs in total of approximately $47.3 million associated with the flood and related crude oil discharge as discussed in Note 12, “Commitments and Contingent Liabilities”, including $5.8 million of net pretax costs in the first quarter of 2008. These amounts are net of anticipated insurance recoveries of $107.2 million including $1.8 million of recoveries for the first quarter of 2008. These costs are reported in “Net costs associated with flood” in the Consolidated Statements of Operations.
Total gross costs recorded due to the flood and related oil discharge that were included in the Consolidated Statements of Operations for the three months ended March 31, 2008 were $7.6 million. Of these gross costs for the three month period ended March 31, 2008, $3.8 million were associated with repair and other matters as a result of the flood damage to the Company’s facilities. Included in this cost was $0.3 million of professional fees and $3.5 million for other repair and related costs. There were also $3.8 million of costs recorded for the three month period ended March 31, 2008 related to the third party and property damage remediation as a result of the crude oil discharge.
Below is a summary of the gross cost and reconciliation of the insurance receivable (in millions):
| | | | | | | | | |
| | | | | | For the Three
| |
| | | | | | Months Ended
| |
| | | Total Costs | | | March 31, 2008 | |
| |
| Total gross costs incurred | | $ | 154.5 | | | $ | 7.6 | |
| Total insurance receivable | | | (107.2 | ) | | | (1.8 | ) |
| | | | | | | | | |
| Net costs associated with the flood | | $ | 47.3 | | | $ | 5.8 | |
| | | | | |
| | | Receivable
| |
| | | Reconciliation | |
| |
| Total insurance receivable | | $ | 107.2 | |
| Less insurance proceeds received | | | (21.5 | ) |
| | | | | |
| Insurance receivable | | $ | 85.7 | |
The Company anticipates that approximately $2.1 million in additional third party costs related to the repair of flood damaged property will be recorded in future periods. 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
F-81
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
ultimate resolution of the Company’s claims. The difference between what the Company ultimately receives under its insurance policies compared to what has been recorded and described above could be material to the consolidated financial statements.
In 2007, the Company had received insurance proceeds of $10.0 million under its property insurance policy and $10.0 million under its environmental policies related to recovery of certain costs associated with the crude oil discharge. In the first quarter of 2008, the Company received $1.5 million under its Builder’s Risk Insurance Policy. 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.
The Company adopted the provisions of FASB Interpretation No. 48,Accounting for Uncertain Tax Positions — an interpretation of FASB No. 109(FIN 48) on January 1, 2007. The adoption of FIN 48 did not affect the Company’s financial position or results of operations. The Company does not have any unrecognized tax benefits as of March 31, 2008.
The Company did not accrue or recognize any amounts for interest or penalties in its financial statements for the three months ended March 31, 2008. 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 and its subsidiaries file U.S. federal and various state income tax returns. The Company is currently under a U.S. federal income tax examination for its 2005 tax year. The Company has not been subject to any other U.S. federal, state or 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 2007. As of March 31, 2008, no taxing authority has proposed any adjustments to the Company’s tax positions.
The Company’s effective tax rates for the three months ended March 31, 2008 and 2007 were 23.6% and 23.4%, respectively, as compared to the federal statutory tax rate of 35%. The effective tax rate is lower than the statutory rate due to federal income tax credits available to small business refiners related to the production of ultra low sulfur diesel fuel and Kansas state incentives generated under the High Performance Incentive Program (HPIP).
| |
| (11) | Earnings (Loss) Per Share |
On October 26, 2007, the Company completed the initial public offering of 23,000,000 shares of its common stock. Also, in connection with the initial public offering, a reorganization of entities under common control was consummated whereby the Company became the indirect owner of the subsidiaries of CALLC and CALLC II and all of their refinery and fertilizer assets. This reorganization was accomplished by the Company issuing 62,866,720 shares of its common stock to CALLC and CALLC II, its majority stockholders, in conjunction with a 628,667.20 for 1 stock split and the merger of two newly formed direct subsidiaries of CVR. Immediately following the completion of the offering, there were 86,141,291 shares of common stock outstanding, excluding non-vested shares issued. See Note 1, “Organization and History of Company and Basis of Presentation”.
Earnings per share for the three months ended March 31, 2008 is calculated as noted below.
| | | | | | | | | | | | | |
| | | Earnings | | | Shares | | | Per Share | |
| |
| Basic earnings per share | | $ | 22,221,000 | | | | 86,141,291 | | | $ | 0.26 | |
| Diluted earnings per share | | $ | 22,221,000 | | | | 86,158,791 | | | $ | 0.26 | |
Outstanding stock options totaling 18,900 common shares were excluded from the diluted earnings per share calculation for the three months ended March 31, 2008 as they were antidilutive.
F-82
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
The computation of basic and diluted loss per share for the quarter ended March 31, 2007 is calculated on a pro forma basis assuming the capital structure in place after the completion of the offering was in place for the entire period.
Pro forma loss per share for the three months ended March 31, 2007 is calculated as noted below. For the three months ended March 31, 2007, 17,500 non-vested shares of common stock and 18,900 common stock options have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such common stock equivalents in the number of weighted average shares outstanding would be anti-dilutive:
| | | | | |
| | | March 31, 2007 | |
| | | (unaudited) | |
| |
| Net (loss) | | $ | (154,373,000 | ) |
| Pro forma weighted average shares outstanding: | | | | |
| Original CVR shares of common stock | | | 100 | |
| Effect of 628,667.20 to 1 stock split | | | 62,866,620 | |
| Issuance of shares of common stock to management in exchange for subsidiary shares | | | 247,471 | |
| Issuance of shares of common stock to employees | | | 27,100 | |
| Issuance of shares of common stock in the initial public offering | | | 23,000,000 | |
| | | | | |
| Basic weighted average shares outstanding | | | 86,141,291 | |
| Dilutive securities — issuance of non-vested shares of common stock to board of directors | | | — | |
| | | | | |
| Diluted weighted average shares outstanding | | | 86,141,291 | |
| | | | | |
| Pro forma basic loss per share | | $ | (1.79 | ) |
| Pro forma dilutive loss per share | | $ | (1.79 | ) |
| |
| (12) | Commitments and Contingent Liabilities |
The minimum required payments for Successor’sthe Company’s lease agreements and unconditional purchase obligations are as follows:follows (in thousands):
| | | | | | | | | | | | | | | | | |
| | | Operating
| | Unconditional
| | | Operating
| | Unconditional
| |
| | | Leases | | Purchase Obligations | | | Leases | | Purchase Obligations | |
| |
| Six months ending December 31, 2006 | | $ | 1,734,379 | | | $ | 12,479,277 | | |
| Year ending December 31, 2007 | | | 3,771,560 | | | | 23,982,825 | | |
| Year ending December 31, 2008 | | | 3,665,278 | | | | 19,676,401 | | |
| Nine months ending December 31, 2008 | | | $ | 2,833 | | | $ | 20,757 | |
| Year ending December 31, 2009 | | | 2,906,968 | | | | 19,645,325 | | | | 3,266 | | | | 28,229 | |
| Year ending December 31, 2010 | | | 1,596,818 | | | | 17,253,845 | | | | 1,680 | | | | 55,762 | |
| Year ending December 31, 2011 | | | 857,494 | | | | 15,683,927 | | | | 948 | | | | 53,939 | |
| Year ending December 31, 2012 | | | | 196 | | | | 51,333 | |
| Thereafter | | | 108,063 | | | | 138,353,408 | | | | 10 | | | | 372,325 | |
| | | | | | | | | | | |
| | | $ | 14,640,560 | | | $ | 247,075,008 | | | $ | 8,933 | | | $ | 582,345 | |
| | | | | | | | | | | |
CVRThe Company leases various equipment and real properties under long-term operating leases. For the 174-day periodthree months ended June 23, 2005, the 49-day period ended June 30, 2005,March 31, 2008 and the six month period ended June 30, 2006,2007, lease expensesexpense totaled approximately $1,754,564, $1,000$1,071,000 and
F-45
CVR Energy, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
$1,991,651, $1,007,000, respectively. The lease agreements have various remaining terms. Some agreements are renewable, at CVR’sthe Company’s option, for additional periods. It is expected, in the ordinary course of business, that leases will be renewed or replaced as they expire.
From time to time, CVRthe 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 litigationlawsuits are recognized when the related costs are probable and
F-83
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
can be reasonably estimated. Management believes the company has accrued for losses for which it may ultimately be responsible. It is possible management’sthat 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 otherthe Company’s litigation matters is not expected to have a material adverse effect on the accompanying consolidated financial statements. There can be no assurance that management’s beliefs or opinions with respect to liability for potential litigation matters are accurate.
Crude oil was discharged from the Company’s refinery on July 1, 2007 due to the short amount of time available to shut down and secure the refinery in preparation for the flood that occurred on June 30, 2007. As a result of the crude oil discharge, two putative class action lawsuits (one federal and one state) were filed seeking unspecified damages with class certification under applicable law for all residents, domiciliaries and property owners of Coffeyville, Kansas who were impacted by the oil release.
The Company filed a motion to dismiss the federal suit for lack of subject matter jurisdiction. On November 6, 2007, the judge in the federal class action lawsuit granted the Company’s motion to dismiss for lack of subject matter jurisdiction and no appeal was taken.
With respect to the state suit, the District Court of Montgomery County, Kansas conducted an evidentiary hearing on the issue of class certification on October 24 and 25, 2007 and ruled against the class certification leaving only the original two plaintiffs. To date no other lawsuits have been filed as a result of flood related damages.
As a result of the crude oil discharge that occurred on July 1, 2007, the Company entered into an administrative order on consent (Consent Order) with the Environmental Protection Agency (EPA) on July 10, 2007. As set forth in the Consent Order, the EPA concluded that the discharge of oil from the Company’s refinery caused and may continue to cause an imminent and substantial threat to the public health and welfare. Pursuant to the Consent Order, the Company agreed to perform specified remedial actions to respond to the discharge of crude oil from the Company’s refinery. The Company is currently remediating the crude oil discharge and expects its primary remedial actions to continue through May 2008 with continuing minor activities for a period thereafter.
The Company engaged experts to assess and test the areas affected by the crude oil spill. The Company commenced a program on July 19, 2007 to purchase approximately 330 homes and other commercial properties in connection with the flood and the crude oil release. Total costs recorded to date are $13.4 million, which include costs incurred in 2007 of $13.1 million and costs for the three months ended March 31, 2008 of $0.3 million. Total costs recorded related to personal property claims were approximately $1.7 million, which were all recorded in 2007. Total costs recorded related to estimated commercial property to be purchased and associated claims were approximately $3.6 million, which were all recorded in 2007. The total amount of gross costs recorded for the three months ended March 31, 2008 related to the residential and commercial purchase and property claims program were approximately $0.3 million. As the crude oil spill took place in the second and third quarter of 2007, no costs associated with the spill were incurred in the first quarter of 2007.
As of March 31, 2008, the total costs recorded for obligations other than the purchase of homes, commercial properties and related personal property claims approximated $30.0 million. The Company has recorded as of March 31, 2008 total costs (net of anticipated insurance recoveries recorded of $21.4 million) associated with remediation and third party property damage claims resolution of approximately $27.3 million. The Company has not estimated or accrued for, because management does not believe it is probable that there will be any potential fines, penalties or claims that may be imposed or brought by regulatory authorities or possible additional damages arising from class action lawsuits related to the flood.
F-84
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
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 received $10.0 million of insurance proceeds under its environmental insurance policy in 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 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 ownsand/or operates manufacturing and ancillary operations at various locations directly related to petroleum refining and distribution and nitrogen fertilizer manufacturing. Therefore, CVR has exposure to potential EHS liabilities related to past and present EHS conditions at some of these locations.
F-46
CVR Energy, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
Through an Administrative Order issued to Original Predecessor under the Resource Conservation and Recovery Act, as amended (RCRA), CVR is a potential party responsible for conducting corrective actions at its Coffeyville, Kansas and Phillipsburg, Kansas facilities. In 2005, Coffeyville Resources Nitrogen Fertilizers, LLCCRNF agreed to participate in the State of Kansas Voluntary Cleanup and Property Redevelopment Program (VCPRP) to address a reported release of urea ammonium nitrate (UAN) at the Coffeyville UAN loading rack. As of March 31, 2008 and December 31, 2005 and June 30, 2006,2007, environmental accruals of $8,220,338$7,713,000 and $7,408,479,$7,646,000, respectively, were reflected in the consolidated balance sheets for probable and estimated costs for remediation of environmental contamination under the RCRA Administrative Order and the VCPRP, including amounts totaling $1,211,000$2,789,000 and $1,324,991,$2,802,000, respectively, included in other current liabilities. The Immediate Predecessor and SuccessorCompany’s 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)EPA and are discounted at the appropriate risk free rates at March 31, 2008 and December 31, 2005 and June 30, 2006,2007, respectively. The accruals include estimated closure and post-closure costs of $1,812,000$1,580,000 and $1,698,000$1,549,000 for two landfills at March 31, 2008 and December 31, 2005 and June 30, 2006,
F-85
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
2007, respectively. The estimated future payments for these required obligations are as follows (in thousands):
| | | | | | | | | |
| | | Amount | | | Amount | |
| |
| Six months ending December 31, 2006 | | $ | 608 | | |
| Year ending December 31, 2007 | | | 1,737 | | |
| Year ending December 31, 2008 | | | 904 | | |
| Nine months ending December 31, 2008 | | | | 2,617 | |
| Year ending December 31, 2009 | | | 493 | | | | 687 | |
| Year ending December 31, 2010 | | | 341 | | | | 1,556 | |
| Year ending December 31, 2011 | | | 341 | | | | 313 | |
| Year ending December 31, 2012 | | | | 313 | |
| Thereafter | | | 6,001 | | | | 3,282 | |
| | | | | | | |
| Undiscounted total | | | 10,425 | | | | 8,768 | |
| Less amounts representing interest at 5.22% | | | 3,017 | | |
| Less amounts representing interest at 3.13% | | | | 1,055 | |
| | | | | | | |
| Accrued environmental liabilities at June 30, 2006 | | $ | 7,408 | | |
| Accrued environmental liabilities at March 31, 2008 | | | $ | 7,713 | |
| | | | | | | |
CVR has purchased insurance to cover costs above accrued amounts related to this contaminated property. Management periodically reviews and, as appropriate, revises its environmental accruals. Based on current information and regulatory requirements, management believes that the accruals established for environmental expenditures are adequate.
The EPA has issued regulations intended to limit amounts of sulfur in diesel and gasoline. The EPA has granted 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$17 million in 2004,2007, $79 million in 2006 and $27 million in 2005 $33to comply with the low-sulfur rules. CVR has spent $2 million in the first sixthree months of 20062008 and based on information currently available, anticipates spending approximately $55$17 million in the last sixnine months of 2006, $22008 and $26 million in 2007, and $6 million in 20082009 to comply with the low-sulfur rules. The entire amounts are expected to be capitalized.
Environmental expenditures are capitalized when such expenditures are expected to result in future economic benefits. For the174-day period three month periods ended June 23, 2005, the49-day period ended June 30, 2005,March 31, 2008 and the six month period ended June 30, 2006,2007, capital expenditures were approximately $6,065,713, $169,543$15,473,000 and $38,644,920,$50,687,000, respectively, and were incurred to improve the environmental compliance and efficiency of the operations.
F-47
CVR Energy, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
CVR believes it is in substantial compliance with existing EHS rules and regulations. There can be no assurance that the EHS matters described above or other EHS matters which may develop in the future will not have a material adverse effect on the Company’s business, financial condition, or results of operations.
| |
(7)(13) | Derivative Financial Instruments |
Loss on derivatives consisted of the following (in thousands):
| | | | | | | | | |
| | | Three Months Ended
| |
| | | March 31, | |
| | | 2008 | | | 2007 | |
| |
| Realized loss on swap agreements | | $ | (21,516 | ) | | $ | (8,534 | ) |
| Unrealized loss on swap agreements | | | (13,907 | ) | | | (119,704 | ) |
| Realized loss on other agreements | | | (7,993 | ) | | | (2,763 | ) |
| Unrealized gain (loss) on other agreements | | | 1,157 | | | | (5,332 | ) |
| Realized gain on interest rate swap agreements | | | 522 | | | | 1,241 | |
| Unrealized loss on interest rate swap agreements | | | (6,134 | ) | | | (1,867 | ) |
| | | | | | | | | |
| Total loss on derivatives | | $ | (47,871 | ) | | $ | (136,959 | ) |
| | | | | | | | | |
F-86
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
CVR is subject to price fluctuations caused by supply conditions, weather, economic conditions, and other factors and to interest rate fluctuations. To manage price risk on crude oil and other inventories and to fix margins on certain future production, CVR may enter into various derivative transactions. In addition, the Successor,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 Statement of Financial Accounting StandardsSFAS No. 133,Accounting for Derivative Instruments andHedgingActivities, (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, certainover-the-counter forward swap agreements and interest rate swap agreements, which it believes provide an economic hedge on future transactions, but such instruments are not designated as hedges. Gains or losses related to the change in fair value and periodic settlements of these derivative instruments are classified as gain (loss)loss on derivatives.derivatives, net in the Consolidated Statements of Operations.
At June 30, 2006, Successor’sMarch 31, 2008, CVR’s Petroleum Segment held commodity derivative contracts (swap agreements) for the period from July 1, 2005 to June 30, 2010 with a related party (see note 9)Note 15, “Related Party Transactions”). The swap agreements were originally executed by CALLC on June 16, 2005 in conjunction with the Subsequent Acquisition of the Immediate Predecessor 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;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 Managementmanagement believes the swap agreements provide an economic hedge on future transactions. At June 30, 2006March 31, 2008 the notional open amounts under the swap agreements were 77,186,00036,190,000 barrels of crude oil; 1,620,909,000oil, 759,990,000 gallons of heating oil and 1,620,909,000759,990,000 gallons of unleaded gasoline. At June 30, 2006, theseThese positions resulted in unrealized losses of $98,223,459 using a valuation method that utilizes quoted market prices and assumptions for the estimated forward yield curvesthree months ended March 31, 2008 and 2007 of the related commodities in periods when quoted market prices are unavailable. During the six month period ended June 30, 2006, the$13,907,000 and $119,704,000, respectively. The Petroleum Segment recorded $33,412,707$21,516,000 and $8,534,000 in realized losses on these swap agreements.agreements for the three month periods ended March 31, 2008 and 2007, respectively.
Successor entered certain crude oil, heating oil, and gasoline option agreements with a related party (see notes 1 and 8) as of May 16, 2005. These agreements expired unexercised on June 16, 2005 and resulted in an expense of $25,000,000 reported in the accompanying consolidated statements of operations as gain (loss) on derivatives for the 49 days ended June 30, 2005.
CVR has recorded margin account balances in cash and cash equivalents of $1,540,952 and $4,377,648 at December 31, 2005 and June 30, 2006, respectively. The Petroleum Segment also recordedmark-to-market net gains (losses),losses, in loss on derivatives, net exclusive of the swap agreements described above and the interest rate swaps described in the following paragraph, in gain (loss) on derivatives of $(7,664,725), $439,530,$6,836,000 and $(2,259,481),$8,095,000, for174-day period the three month periods ended June 23, 2005, the49-day period
F-48
CVR Energy, Inc.March 31, 2008 and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
ended June 30, 2005, and the six-month period ended June 30, 2006,2007, respectively. All of the activity related to the commodity derivative contracts is reported in the Petroleum Segment.
At June 30, 2006, SuccessorMarch 31, 2008, CRLLC held derivative contracts known as interest rate swap agreements that converted Successor’sCRLLC’s floating-rate bank debt into 4.038%4.195% fixed-rate debt on a notional amount of $375,000,000.$325,000,000. Half of the agreements are held with a related party (as described in note 8)Note 15, “Related Party Transactions”), and the other half are held with a financial institution that is a lender under the Successor’sCRLLC’s long-term debt agreements. The swap agreements carry the following terms:
| | | | | | | | | |
| | Notional
| | | Fixed
| |
Period Covered | | Amount | | | Interest Rate |
| |
June 30, 2006 to March 31, 2007 | | | 375 million | | | | 4.038 | % |
March 31, 2007 to June 30, 2007 | | | 325 million | | | | 4.038 | % |
| June 30, 2007 to March 31, 2008 | | | 325 million | | | | 4.195 | % |
March 31, 2008 to March 31,30, 2009 | | | 250 million | | | | 4.195 | % |
March 31, 2009 to March 31,30, 2010 | | | 180 million | | | | 4.195 | % |
March 31, 2010 to June 30,29, 2010 | | | 110 million | | | | 4.195 | % |
SuccessorCVR 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 marketmarked-to-market at each reporting date, and all unrealized gains and losses are currently recognized in income. Transactions related to the interest
F-87
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
rate swap agreements were not allocated to the Petroleum or Nitrogen Fertilizer segments.Mark-to-market net gainslosses on derivatives and quarterly settlements were $0$5,612,000 and $7,433,604$626,000 for the49-day period three month periods ended June 30, 2005March 31, 2008 and the six month period ended June 30, 2006.2007, respectively.
| |
(8)(14) | Fair Value Measurements |
In September 2006, the FASB issued SFAS No. 157,Fair Value Measurements. This statement established a single authoritative definition of fair value when accounting rules require the use of fair value, set out a framework for measuring fair value, and required additional disclosures about fair value measurements. SFAS 157 clarifies that fair value is an exit price, representing the amount that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants.
The Company adopted SFAS 157 on January 1, 2008 with the exception of nonfinancial assets and nonfinancial liabilities that were deferred by FASB Staff Position157-2 as discussed in Note 2 to the Condensed Consolidated Financial Statements. As of March 31, 2008, the Company has not applied SFAS 157 to goodwill and intangible assets in accordance with FASB Staff Position157-2.
SFAS 157 discusses valuation techniques, such as the market approach (prices and other relevant information generated by market conditions involving identical or comparable assets or liabilities), the income approach (techniques to convert future amounts to single present amounts based on market expectations including present value techniques and option-pricing), and the cost approach (amount that would be required to replace the service capacity of an asset which is often referred to as replacement cost). SFAS 157 utilizes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value into three broad levels. The following is a brief description of those three levels:
| | |
| • | Level 1— Quoted prices in active market for identical assets and liabilities |
|
| • | Level 2 — Other significant observable inputs (including quoted prices in active markets for similar assets or liabilities) |
|
| • | Level 3 — Significant unobservable inputs (including the Company’s own assumptions in determining the fair value) |
The following table sets forth the assets and liabilities measured at fair value on a recurring basis, by input level, as of March 31, 2008 (in thousands):
| | | | | | | | | | | | | | | | | |
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| |
| Cash Flow Swap | | | — | | | $ | (13,907 | ) | | | — | | | $ | (13,907 | ) |
| Interest Rate Swap | | | — | | | | (6,134 | ) | | | — | | | | (6,134 | ) |
| Other Derivative Agreements | | | — | | | | 1,157 | | | | — | | | | 1,157 | |
The Company’s derivative contracts giving rise to assets or liabilities under Level 2 are valued using pricing models based on other significant observable inputs.
| |
| (15) | Related Party Transactions |
GS Capital Partners V Fund, L.P. and related entities (GS) and Kelso Investment Associates VII, L.P. and related entity (Kelso) are majority owners of Successor.CVR.
On June 24, 2005, SuccessorCALLC entered into a management services agreementagreements with each of GS and Kelso pursuant to which GS and Kelso agreed to provide SuccessorCALLC with managerial and advisory services. In consideration for these services, an annual fee of $1.0 million each iswas paid to each of GS and Kelso, plus reimbursement for anyout-of-pocket expenses. The agreement has a term endingagreements terminated upon consummation of CVR’s initial public offering on the date GS and Kelso cease to own any interests in Successor.October 26, 2007. Relating to the agreement,agreements, $0 and $1,048,627 was$538,000 were expensed in selling, general, and administrative expenses for the 49 days ended June 30, 2005(exclusive of depreciation and the six-month period ended June 30, 2006, respectively. In addition, $1,046,575 was included in other current liabilities and approximately $78,671 was included in accounts payable at December 31, 2005. $1,008,219 was included in prepaid expenses and other current assets at June 30, 2006.amortization)
F-88
CVR ENERGY, INC. AND SUBSIDIARIES
SuccessorNotes to the Condensed Consolidated Financial Statements — (Continued)
for the three months ended March 31, 2008 and March 31, 2007, respectively. The Company paid a one-time fee of $5.0 million to each of GS and Kelso by reason of the termination of the agreements 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 7)Note 13, “Derivative Financial Instruments”). AmountsThese agreements were assigned to Coffeyville Resources LLC, a subsidiary of CVR. Losses totaling $127,220,262$35,423,000 and $131,636,166$128,238,000 were expensedrecognized related to these swap agreements for the 49 daysthree months ended June 30, 2005March 31, 2008 and the six-month period ended June 30, 2006,2007, respectively, and are reflected in loss on derivatives.derivatives, net in the Consolidated Statements of Operations. In addition, the consolidated balance sheetConsolidated Balance Sheet at March 31, 2008 and December 31, 2005 and June 30, 20062007 includes liabilities of $96,688,956$294,984,000 and $150,506,479$262,415,000, respectively, included in current payable to swap counterparty and $160,033,333$76,411,000 and $218,462,243$88,230,000, respectively, 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%.
As a result of the flood and the related temporary cessation of business operations, the Company entered into a subsequent letter agreement on July 11, 2007 in which the GS subsidiary agreed to defer an additional $43.7 million of the balance owed for the period ending June 30, 2007. This deferral was entered into on the conditions that each of GS and Kelso agreed to guarantee one half of the payment and that interest accrued on the $43.7 million from July 9, 2007 to the date of payment at the rate of LIBOR plus 1.50%.
On July 26, 2007, the Company entered into a letter agreement in which the GS subsidiary agreed 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. As of March 31, 2008 the Company was not required to pay any portion of the deferred amount.
These deferred payment amounts are included in the Consolidated Balance Sheet at March 31, 2008 in current payable to swap counterparty. The deferred balance owed to GS, excluding accrued interest payable, totalled $123.7 million at March 31, 2008. Approximately $4,874,000 of accrued interest payable related to the deferred payments is included in other current liabilities at March 31, 2008.
F-49F-89
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)Notes to the Condensed Consolidated Financial Statements — (Continued)
During the six-month period endedOn June 30, 2006, losses2005, CALLC entered into three interest-rate swap agreements with the same subsidiary of $33,412,707GS (as described in Note 13, “Derivative Financial Instruments”). Losses totaling $2,813,000 and $313,000 were realizedrecognized related to these swap agreements for the three months ended March 31, 2008 and 2007, respectively, and are reflected in loss on these swapderivatives, net in the Consolidated Statements of Operations. In addition, the Consolidated Balance Sheet at March 31, 2008 and December 31, 2007 includes $1,778,000 and $371,000, respectively, in other current liabilities and $2,223,000 and $557,000, respectively, in other long-term liabilities related to the same agreements.
Effective December 30, 2005, Successorthe Company entered into a crude oil supply agreement with a subsidiary of GS (Supplier). ThisUnder the agreement, replaces a similar contract held with an independent party (see note 10). Boththe parties willagreed to negotiate the cost of each barrel of crude oil to be purchased from a third party. Successor willparty, and CVR agreed to pay Supplier a fixed supply service fee per barrel over the negotiated cost of each barrel of crude purchased. The cost is adjusted further using a spread adjustment calculation based on the time period the crude oil is estimated to be delivered to the refinery, other market conditions, and other factors deemed appropriate. The monthly spread quantity for any delivery month at any time shall not exceed approximately 3.1 million barrels. The initial term of the agreement iswas to December 31, 2006. CVR and Supplier agreed to extend the term of the supply agreement for an additional 12 month period, from January 1, 2007 unless canceled by either party prior to November 2, 2006, in which case it terminates onthrough December 31, 2006. $1,290,7312007, and $2,185,000in connection with the extension amended certain terms and conditions of the supply agreement. On December 31, 2007, CVR and supplier entered into an amended and restated crude oil supply agreement. The terms of the agreement remained substantially the same. $241,000 and $360,000 were recorded on the consolidated balance sheet at March 31, 2008 and December 31, 2005 and June 30, 2006,2007, respectively, in prepaid expenses and other current assets for prepayment of crude oil. Approximately $44,347,045In addition, $62,039,000 and $4,547,978$43,773,000 were recorded in Inventoryinventory and Accounts Payable$27,909,000 and $42,666,000 were recorded in accounts payable at June 30, 2006.March 31, 2008 and December 31, 2007, respectively. Expenses associated with this agreement, included in cost of goodsproduct sold (exclusive of depreciation and amortization) for the sixthree month period ended June 30, 2006March 31, 2008 and 2007 totaled approximately $785,399,150.$766,213,000 and $176,307,000, respectively. Interest expense associated with this agreement for the three month period ended March 31, 2008 and 2007 totaled $14,000 and $(1,029,000), respectively.
As a result of the refinery turnaround in early 2007, CVR needed to delay the processing of quantities of crude oil that it purchased from various small independent producers. In order to facilitate this anticipated delay, CVR entered into a purchase, storage and sale agreement for gathered crude oil, dated March 20, 2007, with J. Aron, a subsidiary of GS. Pursuant to the terms of the agreement, J. Aron agreed to purchase gathered crude oil from CVR, store the gathered crude oil and sell CVR the gathered crude oil on a forward basis.
| |
(9)(16) | Business Segments |
CVR measures segment profit as operating income for Petroleum and Nitrogen Fertilizer, CVR’s two reporting segments, based on the definitions provided in Statement of Financial Accounting StandardsSFAS No. 131,Disclosures Aboutabout Segments of an Enterprise and Related Information.Information. All operations of the segments are located within the United States.
Petroleum
Principal products of the Petroleum Segment are refined fuels, propane, and petroleum refining by-products including pet coke. CVR usessells the pet coke to the Partnership for use in the manufacturemanufacturing of nitrogen fertilizer at the adjacent nitrogen fertilizer plant. For CVR, a $15-per-tonper-ton transfer price is used to record intercompany sales on the part of the Petroleum Segment and corresponding intercompany cost of goodsproduct sold (exclusive of depreciation and amortization) for the Nitrogen Fertilizer Segment. The per ton transfer price paid, pursuant to the coke supply agreement that became effective October 24, 2007, is based on the lesser of a coke price derived from the priced received by the fertilizer segment for UAN (subject to a UAN based price ceiling and floor) and a coke price index for
F-90
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
pet coke. Prior to October 25, 2007 intercompany sales were based upon a price of $15 per ton. The intercompany transactions are eliminated in the Other SegmentSegment. Intercompany sales included in petroleum net sales were $2,806,000 and $580,000 for the three months ended March 31, 2008 and 2007, respectively.
Intercompany cost of product sold (exclusive of depreciation and amortization) for the hydrogen sales described below under “— Nitrogen Fertilizer” was $5,291,000 and $2,829,000 for the three months ended March 31, 2008 and 2007, respectively.
Nitrogen Fertilizer
The principal productsproduct of the Nitrogen Fertilizer Segment is nitrogen fertilizer. Intercompany cost of product sold (exclusive of depreciation and amortization) for the coke transfer described above was $2,545,000 and $850,000 for the three months ended March 31, 2008 and 2007, respectively.
Beginning in 2008, the Nitrogen Fertilizer Segment made a change as to the classification of intercompany hydrogen sales to the Petroleum Segment. In 2008, these amounts are anhydrous ammoniareflected as “Net Sales” for the fertilizer plant. Prior to 2008, the Nitrogen Fertilizer Segment reflected these transactions as a reduction of cost of product sold (exclusive of depreciation and urea ammonia nitrate solution (UAN)amortization). For the quarters ended March 31, 2008 and 2007, the net sales generated from intercompany hydrogen sales were $5,291,000 and $2,829,000, respectively. As noted above, the net sales of $2,829,000 were included as a reduction to the cost of product sold (exclusive of depreciation and amortization) for 2007. As these intercompany sales are eliminated, there is no financial statement impact on the consolidated financial statements.
F-91
CVR ENERGY, INC. AND SUBSIDIARIES
Notes to the Condensed Consolidated Financial Statements — (Continued)
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.
F-50
| | | | | | | | | |
| | | Three Months
| |
| | | Ended March 31, | |
| | | 2008 | | | 2007 | |
| | | (in thousands) | |
| |
| Net sales | | | | | | | | |
| Petroleum | | $ | 1,168,500 | | | $ | 352,488 | |
| Nitrogen Fertilizer | | | 62,600 | | | | 38,575 | |
| Intersegment eliminations | | | (8,097 | ) | | | (580 | ) |
| | | | | | | | | |
| Total | | $ | 1,223,003 | | | $ | 390,483 | |
| | | | | | | | | |
| Cost of product sold (exclusive of depreciation and amortization) Petroleum | | $ | 1,035,085 | | | $ | 298,460 | |
| Nitrogen Fertilizer | | | 8,945 | | | | 6,060 | |
| Intersegment eliminations | | | (7,836 | ) | | | (850 | ) |
| | | | | | | | | |
| Total | | $ | 1,036,194 | | | $ | 303,670 | |
| | | | | | | | | |
| Direct operating expenses (exclusive of depreciation and amortization) Petroleum | | $ | 40,290 | | | $ | 96,674 | |
| Nitrogen Fertilizer | | | 20,266 | | | | 16,738 | |
| Other | | | — | | | | — | |
| | | | | | | | | |
| Total | | $ | 60,556 | | | $ | 113,412 | |
| | | | | | | | | |
| Net costs associated with flood | | | | | | | | |
| Petroleum | | $ | 5,533 | | | $ | — | |
| Nitrogen Fertilizer | | | (17 | ) | | | — | |
| Other | | | 247 | | | | — | |
| | | | | | | | | |
| Total | | $ | 5,763 | | | $ | — | |
| | | | | | | | | |
| Depreciation and amortization | | | | | | | | |
| Petroleum | | $ | 14,877 | | | $ | 9,794 | |
| Nitrogen Fertilizer | | | 4,477 | | | | 4,394 | |
| Other | | | 281 | | | | 47 | |
| | | | | | | | | |
| Total | | $ | 19,635 | | | $ | 14,235 | |
| | | | | | | | | |
| Operating income (loss) | | | | | | | | |
| Petroleum | | $ | 63,618 | | | $ | (63,468 | ) |
| Nitrogen Fertilizer | | | 26,017 | | | | 9,319 | |
| Other | | | (2,277 | ) | | | 165 | |
| | | | | | | | | |
| Total | | $ | 87,358 | | | $ | (53,984 | ) |
| | | | | | | | | |
| Capital expenditures | | | | | | | | |
| Petroleum | | $ | 22,541 | | | $ | 106,501 | |
| Nitrogen Fertilizer | | | 2,817 | | | | 402 | |
| Other | | | 798 | | | | 460 | |
| | | | | | | | | |
| Total | | $ | 26,156 | | | $ | 107,363 | |
| | | | | | | | | |
CVR Energy, Inc. and Subsidiaries
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited) — (Continued)
| | | | | | | | | | | | | | |
| | | Immediate Predecessor | | | | Successor | |
| | | 174-Day Period
| | | | 49-Day Period
| | | Six Months
| |
| | | Ended
| | | | Ended
| | | Ended
| |
| | | June 23,
| | | | June 30,
| | | June 30,
| |
| | | 2005 | | | | 2005 | | | 2006 | |
| | | | | | | (unaudited) | | | (unaudited) | |
| Net sales | | | | | | | | | | | | | |
| Petroleum | | $ | 903,802,983 | | | | $ | 46,646,714 | | | $ | 1,457,663,348 | |
| Nitrogen Fertilizer | | | 79,347,843 | | | | | 3,158,276 | | | | 95,632,021 | |
| Other | | | (2,444,565 | ) | | | | (112,515 | ) | | | (2,728,740 | ) |
| | | | | | | | | | | | | | |
| Total | | $ | 980,706,261 | | | | $ | 49,692,475 | | | $ | 1,550,566,629 | |
| | | | | | | | | | | | | | |
| Depreciation and amortization | | | | | | | | | | | | | |
| Petroleum | | $ | 770,728 | | | | $ | 590,036 | | | $ | 15,612,029 | |
| Nitrogen Fertilizer | | | 316,446 | | | | | 323,815 | | | | 8,384,377 | |
| Other | | | 40,831 | | | | | 744 | | | | 25,702 | |
| | | | | | | | | | | | | | |
| Total | | $ | 1,128,005 | | | | $ | 914,595 | | | $ | 24,022,108 | |
| | | | | | | | | | | | | | |
| Operating income (loss) | | | | | | | | | | | | | |
| Petroleum | | $ | 76,654,428 | | | | $ | (13,298,086 | ) | | $ | 178,023,767 | |
| Nitrogen Fertilizer | | | 35,267,752 | | | | | (270,113 | ) | | | 37,065,026 | |
| Other | | | 333,514 | | | | | (23,801 | ) | | | (228,658 | ) |
| | | | | | | | | | | | | | |
| Total | | $ | 112,255,694 | | | | $ | (13,592,000 | ) | | $ | 214,860,135 | |
| | | | | | | | | | | | | | |
| Capital expenditures | | | | | | | | | | | | | |
| Petroleum | | $ | 10,790,042 | | | | $ | 339,821 | | | $ | 76,791,026 | |
| Nitrogen fertilizer | | | 1,434,921 | | | | | 8,661 | | | | 7,605,735 | |
| Other | | | 31,830 | | | | | 3,903 | | | | 1,777,894 | |
| | | | | | | | | | | | | | |
| Total | | $ | 12,256,793 | | | | $ | 352,385 | | | $ | 86,174,655 | |
| | | | | | | | | | | | | | |
| Total assets | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | 741,525,912 | |
| Nitrogen Fertilizer | | | | | | | | | | | | 424,625,981 | |
| Other | | | | | | | | | | | | 214,881,481 | |
| | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | 1,381,033,374 | |
| | | | | | | | | | | | | | |
| Goodwill | | | | | | | | | | | | | |
| Petroleum | | | | | | | | | | | $ | 42,806,422 | |
| Nitrogen Fertilizer | | | | | | | | | | | | 40,968,463 | |
| Other | | | | | | | | | | | | — | |
| | | | | | | | | | | | | | |
| Total | | | | | | | | | | | $ | 83,774,885 | |
| | | | | | | | | | | | | | |
F-51
F-92
CVR Energy, Inc. and SubsidiariesENERGY, INC. AND SUBSIDIARIES
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)Notes to the Condensed Consolidated Financial Statements — (Continued)
| | | | | | | | | |
| | | Three Months
| | | | |
| | | Ended
| | | Year Ended
| |
| | | March 31,
| | | December 31,
| |
| | | 2008 | | | 2007 | |
| |
| Total assets | | | | | | | | |
| Petroleum | | $ | 1,352,961 | | | $ | 1,277,124 | |
| Nitrogen Fertilizer | | | 496,326 | | | | 446,763 | |
| Other | | | 74,304 | | | | 144,469 | |
| | | | | | | | | |
| Total | | $ | 1,923,591 | | | $ | 1,868,356 | |
| | | | | | | | | |
| Goodwill | | | | | | | | |
| Petroleum | | $ | 42,806 | | | $ | 42,806 | |
| Nitrogen Fertilizer | | | 40,969 | | | | 40,969 | |
| Other | | | — | | | | — | |
| | | | | | | | | |
| Total | | $ | 83,775 | | | $ | 83,775 | |
| | | | | | | | | |
| |
(10)(17) | Major Customers and SuppliersSubsequent Events |
Sales to major customers were as follows:
| | | | | | | | | | | | | | |
| | | Immediate
| | | |
| | | Predecessor | | | Successor |
| | | 174-Day Period
| | | 49-Day Period
| | Six Months
|
| | | Ended
| | | Ended
| | Ended
|
| | | June 23,
| | | June 30,
| | June 30,
|
| | | 2005 | | | 2005 | | 2006 |
Petroleum | | | | | | | | | | | | | |
| Customer A | | | 17 | % | | | | 16 | % | | | 2 | % |
| Customer B | | | 5 | % | | | | 4 | % | | | 6 | % |
| Customer C | | | 17 | % | | | | 25 | % | | | 17 | % |
| Customer D | | | 14 | % | | | | 18 | % | | | 14 | % |
| Customer E | | | 11 | % | | | | 11 | % | | | 10 | % |
| | | | | | | | | | | | | | |
| | | | 64 | % | | | | 74 | % | | | 49 | % |
| | | | | | | | | | | | | | |
Nitrogen Fertilizer | | | | | | | | | | | | | |
| Customer F | | | 16 | % | | | | 25 | % | | | 5 | % |
| Customer G | | | 9 | % | | | | 0 | % | | | 4 | % |
| Customer H | | | 8 | % | | | | 14 | % | | | 6 | % |
| | | | | | | | | | | | | | |
| | | | 33 | % | | | | 39 | % | | | 15 | % |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
The Petroleum Segment maintains long-term contracts with one supplier forOn June 13, 2008, the purchase of its crude oil. The agreement with Supplier A expired in December 2005, at which time Successor entered into a similar arrangement with Supplier B, a related party (as described in note 8). Purchases contracted as a percentageCompany announced that the managing general partner of the total cost of goods sold for each ofPartnership had decided to postpone indefinitely the periods were as follows:Partnership’s initial public offering. The Partnership has notified the SEC that it intends to withdraw the registration statement it filed in February 2008.
| | | | | | | | | | | | | | |
| | | Immediate
| | | |
| | | Predecessor | | | Successor |
| | | 174-Day Period
| | | 49-Day Period
| | Six Months
|
| | | Ended
| | | Ended
| | Ended
|
| | | June 23,
| | | June 30,
| | June 30,
|
| | | 2005 | | | 2005 | | 2006 |
| Supplier A | | | 77 | % | | | | 37 | % | | | 1 | % |
| Supplier B | | | — | | | | | — | | | | 66 | % |
| | | | | | | | | | | | | | |
| | | | 77 | % | | | | 37 | % | | | 67 | % |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
F-52
No dealer, salesperson or other person is authorized to give any information or to represent anything not contained in this prospectus. You must not rely on any unauthorized information or representations. This prospectus is an offer to sell only the shares of common stock offered hereby, but only under circumstances and in jurisdictions where it is lawful to do so. The information contained in this prospectus is current only as of its date.
TABLE OF CONTENTS
Through and including , 2006 (the 25th day after the date of this prospectus), all dealers that effect transactions in these securities, whether or not participating in this offering, may be required to deliver a prospectus. This is in addition to the dealers’ obligation to deliver a prospectus when acting as underwriters and with respect to their unsold allotments or subscriptions.
10,000,000 Shares
CVR Energy, Inc.
PROSPECTUS
Goldman, Sachs & Co.
Deutsche Bank Securities
Citi
Credit Suisse
PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
| |
| Item 13. | Other Expenses of Issuance and Distribution. |
The following table sets forth the costs and expenses to be paid by the Registrant in connection with the sale of the shares of common stock being registered hereby. All amounts are estimates except for the SEC registration fee, the NASDFinancial Industry Regulatory Authority (“FINRA”) filing fee and the listing fee.
| | | | | | | | | |
| SEC registration fee | | $ | 32,100.00 | | | $ | 11,530 | |
| NASD filing fee | | | 30,500.00 | | |
| listing fee | | | | | |
| FINRA filing fee | | | $ | 29,837 | |
| Accounting fees and expenses | | | | | | | | |
| Legal fees and expenses | | | | | | | | |
| Printing and engraving expenses | | | | | | | | |
| Blue Sky qualification fees and expenses | | | | | |
| Transfer agent and registrar fees and expenses | | | | | | | | |
| Miscellaneous expenses | | | | | | | | |
| | | | | | | |
| Total | | $ | | | | $ | | |
| | | | | | | |
| |
| Item 14. | Indemnification of Directors and Officers. |
Section 145 of the Delaware General Corporation Law authorizes a court to award, or a corporation’s board of directors to grant, indemnity to directors and officers in terms sufficiently broad to permit such indemnification under certain circumstances for liabilities (including reimbursement for expenses incurred) arising under the Securities Act of 1933, as amended (the “Securities Act”).
As permitted by the Delaware General Corporation Law, the Registrant’s Certificate of Incorporation includes a provision that eliminates the personal liability of its directors for monetary damages for breach of fiduciary duty as a director, except for liability:
| | |
| | • | for any breach of the director’s duty of loyalty to the Registrant or its stockholders; |
| |
| | • | for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law; |
| |
| | • | under section 174 of the Delaware General Corporation lawLaw regarding unlawful dividends and stock purchases; or |
| |
| | • | for any transaction for which the director derived an improper personal benefit. |
As permitted by the Delaware General Corporation Law, the Registrant’s Bylaws provide that:
| | |
| | • | the Registrant is required to indemnify its directors and officers to the fullest extendextent permitted by the Delaware General Corporation Law, subject to very limited exceptions; |
| |
| | • | the Registrant may indemnify its other employees and agents to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions; |
| |
| | • | the Registrant is required to advance expenses, as incurred, to its directors and officers in connection with a legal proceeding to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions; |
II-1
| | |
| | • | the Registrant may advance expenses, as incurred, to its employees and agents in connection with a legal proceeding; and |
| |
| | • | the rights conferred in the Bylaws are not exclusive. |
The Registrant may enter into Indemnity Agreements with each of its current directors and officers to give these directors and officers additional contractual assurances regarding the scope of the indemnification set forth in the Registrant’s Certificate of Incorporation and to provide additional procedural protections. At present, there is no pending litigation or proceeding involving a director, officer or employee of the Registrant regarding which indemnification is sought, nor is the Registrant aware of any threatened litigation that may result in claims for indemnification.
II-1
The indemnification provisions in the Registrant’s Certificate of Incorporation and Bylaws and any Indemnity Agreements entered into between the Registrant and each of its directors and officers may be sufficiently broad to permit indemnification of the Registrant’s directors and officers for liabilities arising under the Securities Act.
CVR Energy, Inc. and its subsidiaries are covered by liability insurance policies which indemnify their directors and officers against loss arising from claims by reason of their legal liability for acts as such directors, officers or trustees, subject to limitations and conditions as set forth in the policies.
The underwriting agreement to be entered into among the company, the selling stockholderstockholders and the underwriters will contain indemnification and contribution provisions.
| |
| Item 15. | Recent Sales of Unregistered Securities. |
We issued 100 shares of common stock to Coffeyville Acquisition LLC in September 2006.2006 for nominal consideration. The issuance was exempt from registration in accordance with Section 4(2) of the Securities Act of 1933.1933, as amended. We issued 247,471 shares of common stock to our chief executive officer in October 2007. In exchange for shares he owned in Coffeyville Nitrogen Fertilizers, Inc. and Coffeyville Refining and Marketing Holding Holdings, Inc. The issuance was exempt from registration in accordance with Rule 701 under the Securities Act of 1933, as amended.
| |
| Item 16. | Exhibits and Financial Statement Schedules. |
(a) The following exhibits to this Registration Statement are filed herewith:listed on the Exhibit Index page hereof, which is incorporated by reference in this Item 16.
| | | | |
Number
| | Exhibit Title
|
|
| 1 | .1* | | Form of Underwriting Agreement. |
| 3 | .1* | | Certificate of Incorporation of CVR Energy, Inc. |
| 3 | .2* | | Bylaws of CVR Energy, Inc. |
| 4 | .1* | | Specimen Common Stock Certificate. |
| 5 | .1* | | Form of opinion of Fried, Frank, Harris, Shriver & Jacobson, LLP. |
| 10 | .1* | | Amended and Restated First Lien Credit and Guaranty Agreement, dated as of June 29, 2006, among Coffeyville Resources, LLC and the other parties thereto. |
| 10 | .2* | | Second Lien Credit and Guaranty Agreement, dated as of June 24, 2005, as amended. |
| 10 | .3* | | First Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, Cayman Islands Branch, as collateral agent. |
II-2
| | | | | |
Number | | Exhibit Title |
| |
| | 10 | .4* | | Second Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Wachovia Bank, National Association, as collateral agent. |
| | 10 | .5* | | Swap agreements with J. Aron & Company, dated June 16, 2005. |
| | 10 | .6* | | Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. and Coffeyville Resources Nitrogen Fertilizers, LLC. |
| | 10 | .7* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and John J. Lipinski. |
| | 10 | .8* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Stanley A. Riemann. |
| | 10 | .9* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Kevan A. Vick. |
| | 10 | .10* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan. |
| | 10 | .11* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and James T. Rens. |
| | 10 | .12* | | Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi. |
| | 10 | .13* | | Crude Oil Supply Agreement, dated as of December 23, 2005, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC. |
| | 10 | .14* | | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC. |
| | 10 | .15* | | Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas. |
| | 21 | .1* | | List of Subsidiaries of CVR Energy, Inc. |
| | 23 | .1 | | Consent of KPMG LLP. |
| | 23 | .2* | | Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1). |
| | 24 | .1 | | Power of Attorney (included on the signature page to the Registration Statement). |
| | |
* | | To be filed by amendment. |
(b) None.The financial statement schedules are omitted because they are inapplicable or the requested information is shown in the consolidated financial statements of CVR Energy, Inc. or related notes thereto.
The undersigned Registrant hereby undertakes to provide to the underwriters at the closing specified in the underwriting agreement certificates in such denominations and registered in such names as required by the underwriters to permit prompt delivery to each purchaser.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers and controlling persons of the Registrant pursuant to the provisions described in Item 14 above, or otherwise, the Registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore,
II-3
unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the Registrant of expenses incurred or paid by a director, officer or controlling person of the Registrant in the successful defense of any action, suit or proceeding) is asserted by such director, officer or controlling person in connection with the securities being registered, the Registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned Registrant hereby undertakes that:
(1) For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this Registration Statement in reliance upon Rule 430A and contained in a form of prospectus filed by the Registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this Registration Statement as of the time it was declared effective; and
(2) For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at the time shall be deemed to be the initial bona fide offering thereof.
II-4II-2
SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the Registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned, thereunto duly authorized in Sugar Land, State of Texas, on this 26th19th day of September, 2006.June 2008.
CVR ENERGY, INC.
John J. Lipinski
Chief Executive Officer and President
KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears below constitutes and appoints John J. Lipinski, James T. Rens and Edmund S. Gross, and each of them, his or her true and lawfulattorneys-in-fact and agents with full powers of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any or all amendments to this Registration Statement, including post-effective amendments and registration statements filed pursuant to Rule 462(b) and otherwise, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto saidattorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done in and about the premises, as fully to all intents and purposes as he or she might or could do in person, and hereby ratifies and confirms all his or her saidattorneys-in-fact and agents, or any of them, or his or her substitute or substitutes may lawfully do or cause to be done by virtue thereof.
Pursuant to the requirements of the Securities Act of 1933, this Registration Statement has been signed by the following persons in the capacities and on the dates indicated.
| | | | | | | |
Signature | | Title | | Date |
| |
/s/ John J. Lipinski
John J. Lipinski | | Chief Executive Officer, President and
Director (principal executive officer)(Principal Executive Officer) | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ James T. Rens
James T. Rens | | Chief Financial Officer (Principal
Financial and Accounting Officer) | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ Wesley ClarkScott L. Lebovitz
Wesley ClarkScott L. Lebovitz | | Director | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ Scott LebovitzRegis B. Lippert
Scott LebovitzRegis B. Lippert | | Director | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ George E. Matelich
George E. Matelich | | Director | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ Steve A. Nordaker
Steve A. Nordaker | | Director | | June 19, 2008 |
II-3
| | | | | | |
Signature | | Title | | Date |
|
/s/ Stanley de J. Osborne
Stanley de J. Osborne | | Director | | September 26, 2006June 19, 2008 |
| | | | | |
/s/ Kenneth A. Pontarelli
Kenneth A. Pontarelli | | Director | | September 26, 2006June 19, 2008 |
| | | | |
/s/ Mark Tomkins
Mark Tomkins | | Director | | June 19, 2008 |
II-5II-4
EXHIBIT INDEX
| | | | | |
Number | | Exhibit Title |
| |
| | 1 | .1* | | Form of Underwriting Agreement. |
| | 3 | .1** | | Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| | 3 | .2** | | Amended and Restated Bylaws of CVR Energy, Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| | 4 | .1** | | Specimen Common Stock Certificate.Certificate (filed as Exhibit 4.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 5 | .1* | | Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP. |
| | 10 | .1** | | Second Amended and Restated First Lien Credit and Guaranty Agreement, dated as of June 29,December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto.thereto (filed as Exhibit 10.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .2*.1.1** | | First Amendment to Second LienAmended and Restated Credit and Guaranty Agreement, dated as of June 24, 2005,August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto (filed as amended.Exhibit 10.1.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .3*.2** | | Amended and Restated First Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005,December 28, 2006, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, Cayman Islands Branch, as collateral agent.agent (filed as Exhibit 10.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .4* | | Second Lien Pledge and Security Agreement, dated as of June 24, 2005 and amended as of July 8, 2005, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Wachovia Bank, National Association, as collateral agent. |
| 10 | .5*.3†** | | Swap agreements with J. Aron & Company dated June 16, 2005.(filed as Exhibit 10.5 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .6*.3.1** | | Letter agreements between Coffeyville Resources, LLC and J. Aron & Company, dated as of June 26, 2007, July 11, 2007, July 26, 2007 and August 23, 2007 (filed as Exhibit 10.5.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .4†** | | License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between Texaco Development Corporation and Farmland Industries, Inc., as amended (filed as Exhibit 10.4 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .5†** | | Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The Linde Group (f/k/a The BOC Group, Inc.) and Coffeyville Resources Nitrogen Fertilizers, LLC.LLC (filed as Exhibit 10.6 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .7*.6†** | | Employment Agreement dated as of July 12, 2005, byAmended and between Coffeyville Resources, LLC and John J. Lipinski. |
| 10 | .8* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Stanley A. Riemann. |
| 10 | .9* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Kevan A. Vick. |
| 10 | .10* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan. |
| 10 | .11* | | Employment Agreement dated as of July 12, 2005, by and between Coffeyville Resources, LLC and James T. Rens. |
| 10 | .12* | | Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi. |
| 10 | .13* | | Restated Crude Oil Supply Agreement, dated as of December 23, 2005,31, 2007, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC.LLC (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K, filed on January 7, 2008 and incorporated by reference herein). |
| | 10 | .14*.7†** | | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC.LLC (filed as Exhibit 10.14 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | | | | |
Number | | Exhibit Title |
| |
| | 10 | .15* | | Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas. |
| | 21 | .1* | | List of Subsidiaries of CVR Energy, Inc. |
| | 23 | .1 | | Consent of KPMG LLP. |
| | 23 | .2* | | Consent of Fried, Frank, Harris, Shriver & Jacobson, LLP (included in Exhibit 5.1). |
| | 24 | .1 | | Power of Attorney (included on the signature page to the Registration Statement). |
| | | | |
Number | | Exhibit Title |
|
| 10 | .8** | | Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas (filed as Exhibit 10.15 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .9** | | Purchase, Storage and Sale Agreement for Gathered Crude, dated as of March 20, 2007, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.22 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .10** | | Stockholders Agreement of CVR Energy, Inc., dated as of October 16, 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (filed as Exhibit 10.20 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .11** | | Registration Rights Agreement, dated as of October 16, 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC (filed as Exhibit 10.21 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .12** | | Management Registration Rights Agreement, dated as of October 24, 2007, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.27 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .13** | | Stock Purchase Agreement, dated as of May 15, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .13.1** | | Amendment No. 1 to the Stock Purchase Agreement, dated as of June 24, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .13.2** | | Amendment No. 2 to the Stock Purchase Agreement, dated as of July 25, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC (filed as Exhibit 10.23.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .14** | | First Amended and Restated Agreement of Limited Partnership of CVR Partners, LP, dated as of October 24, 2007, by and among CVR GP, LLC, CVR Special GP, LLC and Coffeyville Resources, LLC (filed as Exhibit 10.4 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .15** | | Coke Supply Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.5 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .16** | | Cross Easement Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .17** | | Environmental Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.7 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .17.1** | | Supplement to Environmental Agreement, dated as of February 15, 2008, by and between Coffeyville Resources Refining and Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.17.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| | | | |
Number | | Exhibit Title |
|
| 10 | .18** | | Feedstock and Shared Services Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.8 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .19** | | Raw Water and Facilities Sharing Agreement, dated as of October 25, 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.9 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .20** | | Services Agreement, dated as of October 25, 2007, by and among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and CVR Energy, Inc. (filed as Exhibit 10.10 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .21** | | Omnibus Agreement, dated as of October 24, 2007 by and among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR Partners, LP (filed as Exhibit 10.11 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .22** | | Contribution, Conveyance and Assumption Agreement, dated as of October 24, 2007, by and among Coffeyville Resources, LLC, CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP (filed as Exhibit 10.26 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .23** | | Registration Rights Agreement, dated as of October 24, 2007, by and among CVR Partners, LP, CVR Special GP, LLC and Coffeyville Resources, LLC (filed as Exhibit 10.24 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .24** | | Amended and Restated Employment Agreement, dated as of January 1, 2008, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.24 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .25** | | Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and Stanley A. Riemann (filed as Exhibit 10.25 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .26** | | Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and James T. Rens (filed as Exhibit 10.26 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .27** | | Employment Agreement, dated as of October 23, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .27.1** | | First Amendment to Employment Agreement, dated as of November 30, 2007, by and between CVR Energy, Inc. and Daniel J. Daly, Jr. (filed as Exhibit 10.27.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .28** | | Amended and Restated Employment Agreement, dated as of December 29, 2007, by and between CVR Energy, Inc. and Robert W. Haugen (filed as Exhibit 10.28 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| 10 | .29** | | CVR Energy, Inc. 2007 Long Term Incentive Plan (filed as Exhibit 10.13 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .29.1** | | Form of Nonqualified Stock Option Agreement (filed as Exhibit 10.33.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | | | |
Number | | Exhibit Title |
|
| 10 | .29.2** | | Form of Director Stock Option Agreement (filed as Exhibit 10.33.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .29.3** | | Form of Director Restricted Stock Agreement (filed as Exhibit 10.33.3 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .30** | | Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), as amended (filed as Exhibit 10.3 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .31** | | Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II) (filed as Exhibit 10.12 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .32** | | Stockholders Agreement of Coffeyville Nitrogen Fertilizer, Inc., dated as of March 9, 2007, by and among Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Acquisition LLC and John J. Lipinski (filed as Exhibit 10.17 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .33** | | Stockholders Agreement of Coffeyville Refining & Marketing Holdings, Inc., dated as of August 22, 2007, by and among Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Acquisition LLC and John J. Lipinski (filed as Exhibit 10.18 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .34** | | Subscription Agreement, dated as of March 9, 2007, by Coffeyville Nitrogen Fertilizers, Inc. and John J. Lipinski (filed as Exhibit 10.19 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| 10 | .35** | | Subscription Agreement, dated as of August 22, 2007, by Coffeyville Refining & Marketing Holdings, Inc. and John J. Lipinski (filed as Exhibit 10.20 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated herein by reference). |
| 10 | .36** | | Amended and Restated Recapitalization Agreement, dated as of October 16, 2007, by and among Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc. (filed as Exhibit 10.3 to the Company’s Quarterly Report onForm 10-Q for the quarterly period September 30, 2007 and incorporated by reference herein). |
| 10 | .37** | | Subscription Agreement, dated as of October 16, 2007, by and between CVR Energy, Inc. and John J. Lipinski (filed as Exhibit 10.21 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .38** | | Redemption Agreement, dated as of October 16, 2007, by and among Coffeyville Acquisition LLC and the Redeemed Parties signatory thereto (filed as Exhibit 10.19 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .39** | | Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.4 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .39.1** | | Amendment No. 1 to the Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of October 16, 2007 (filed as Exhibit 10.15 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| 10 | .40** | | First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.16 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| | | | | |
Number | | Exhibit Title |
| |
| | 10 | .40.1** | | Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of October 16, 2007 (filed as Exhibit 10.17 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| | 10 | .41** | | Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition III LLC, dated as of February 15, 2008 (filed as Exhibit 10.41 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| | 10 | .42** | | Letter Agreement, dated as of October 24, 2007, by and among Coffeyville Acquisition LLC, Goldman, Sachs & Co. and Kelso & Company, L.P. (filed as Exhibit 10.23 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). |
| | 10 | .43** | | Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Refining & Marketing, LLC and various unions of the Metal Trades Department (filed as Exhibit 10.46 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .44** | | Collective Bargaining Agreement, effective as of March 3, 2004, by and between Coffeyville Resources Crude Transportation, LLC and the Paper, Allied-Industrial, Chemical & Energy Workers International Union (filed as Exhibit 10.47 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
| | 10 | .45** | | Consulting Agreement dated May 2, 2008, by and between General Wesley Clark and CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended March 31, 2008 and incorporated by reference herein). |
| | 21 | .1** | | List of Subsidiaries of CVR Energy, Inc. (filed as Exhibit 21.1 to the Company’s Annual Report onForm 10-K for the year ended December 31, 2007 and incorporated by reference herein). |
| | 23 | .1 | | Consent of KPMG LLP. |
| | 23 | .2* | | Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1). |
| | 23 | .3 | | Consent of Blue, Johnson & Associates. |
| | |
| * | | To be filed by amendmentamendment. |
|
| ** | | Previously filed. |
|
| † | | Confidential treatment has been granted for certain provisions of this exhibit by the Securities and Exchange Commission. |
