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Delaware | 2911 | 61-1512186 | ||
(State or Other Jurisdiction of Incorporation or Organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) |
Stuart H. Gelfond Michael A. Levitt Fried, Frank, Harris, Shriver & Jacobson LLP One New York Plaza New York, New York 10004 (212) 859-8000 | Peter J. Loughran Debevoise & Plimpton LLP 919 Third Avenue New York, New York 10022 (212) 909-6000 |
Large accelerated filer o | Accelerated filer o | Non-accelerated filer þ | Smaller reporting company o | |||
(Do not check if a smaller reporting company) |
Proposed Maximum | Proposed Maximum | Amount of | ||||||||||
Title of Each Class of | Amount to be | Offering | Aggregate | Registration | ||||||||
Securities to be Registered | Registered(1) | Price per Share(2) | Offering Price(1)(2) | Fee | ||||||||
Common Stock, $0.01 par value | 11,500,000 | $25.51 | $293,365,000 | $11,530 | ||||||||
(1) | Includes the number of shares, or the offering price of shares, as the case may be, which the underwriters have the option to purchase. | |
(2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(c) of the Securities Act of 1933, as amended, based on the average of the high and low prices of the Registrant’s Common Stock as reported on the New York Stock Exchange on June 13, 2008. The actual amount received by the selling shareholders will be based upon fluctuating market prices. |
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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted. |
Per Share | Total | |||||||
Public offering price | $ | $ | ||||||
Underwriting discount | $ | $ | ||||||
Proceeds, before expenses, to the selling stockholders | $ | $ |
Goldman, Sachs & Co. | Deutsche Bank Securities |
Citi | Credit Suisse |
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• | High capital costs, historical excess capacity and environmental regulatory requirements that have limited the construction of new refineries in the United States over the past 30 years. | |
• | Refining capacity shortage in the mid-continent region, as certain regional markets in the U.S. are subject to insufficient local refining capacity to meet regional demands. This should result in local refiners earning higher margins on product sales than those who must rely on pipelines and other modes of transportation for supply. | |
• | Crack spreads are increasing in terms of absolute value with dramatically higher crude oil costs, but are substantially narrower as a percentage of crude oil costs, which has reduced oil refinery profitability. | |
• | A shift in market fundamentals for global petroleum refiners. The most profitable end products for refiners have shifted from gasoline products to distillate products. | |
• | Increasing demand for sweet crude oils and higher incremental production of lower-cost sour crude that are expected to provide a cost advantage to sour crude processing refiners. | |
• | U.S. fuel specifications, including reduced sulfur content, reduced vapor pressure and the addition of oxygenates such as ethanol, that should benefit refiners who are able to efficiently produce fuels that meet these specifications. | |
• | Limited competitive threat from foreign refiners due to sophisticated U.S. fuel specifications and increasing foreign demand for refined products. |
• | Nitrogen fertilizer prices in the United States are experiencing all-time highs. Based on industry projections, including from Blue Johnson, these high prices are forecast to continue for the next several years. | |
• | Nitrogen fertilizer prices have been decoupled from their historical correlation with natural gas prices in recent years, and increased substantially more than natural gas prices in 2007 and |
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2008 (based on data provided by Blue Johnson). Moreover, natural gas prices are currently higher in the United States and Canada compared to prevailing prices in the years prior to 2004. High North American natural gas prices contribute to the currently high prices for nitrogen-based fertilizers in the United States. |
• | The Energy Independence and Security Act of 2007 requires fuel producers to use at least 36 billion gallons of biofuel (such as ethanol) by 2022, a nearly five-fold increase over current levels. The increase in grain production necessary to meet this requirement is expected to result in rising demand for nitrogen-based fertilizers. | |
• | World population and economic growth, combined with changing dietary trends in many nations, has significantly increased demand for U.S. agricultural production and exports. Increasing U.S. crop production requires higher application rates of fertilizers, primarily nitrogen-based fertilizers. |
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• | Expanding 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 permit the nitrogen fertilizer business to increase its UAN production and to result in its UAN manufacturing facility consuming substantially all of its net ammonia production. This should increase the nitrogen fertilizer plant’s margins because UAN has historically been a higher margin product than ammonia. The UAN expansion is expected to be complete in July 2010 and it is estimated that it will result in an approximately 50% increase in the nitrogen fertilizer business’ annual UAN production. The company has also begun to acquire or lease offsite UAN storage facilities and continues to expand this program. | |
• | Executing Several Efficiency-Based and Other Projects. The nitrogen fertilizer business is currently engaged in several efficiency-based and other projects in order to reduce overall operating costs, incrementally increase its ammonia production and utilize byproducts to generate revenue. For example, by redesigning the system that segregates carbon dioxide, or CO2, during the gasification process, the nitrogen fertilizer business estimates that it will be able to produce approximately 25 tons per day of incremental ammonia, worth approximately $6 million per year at current market prices. The nitrogen fertilizer business estimates that this project will cost approximately $7 million (of which none has yet been incurred) and will be completed in 2010. The nitrogen fertilizer business has a proven track record of operating gasifiers and is well positioned to offer operating and technical services as a third-party operator to other gasifier-based projects. | |
• | Evaluating Construction of a Third Gasifier Unit and a New Ammonia Unit and UAN Unit at the Nitrogen Fertilizer Plant. The nitrogen fertilizer business has engaged a major engineering firm to help it evaluate the construction and operation of an additional gasifier unit to produce a synthesis gas from pet coke. It is expected that the addition of a third gasifier unit, together with additional ammonia and UAN units, to the nitrogen fertilizer business’ operations could result, on a long-term basis, in an increase in UAN production of approximately 75,000 tons per month. This project is in its earliest stages of review and is still subject to numerous levels of internal analysis. |
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• | Debt was used as part of the acquisition financing in June 2005 which required the introduction of a financial risk management tool intended to mitigate a portion of the inherent commodity price based volatility in our cash flow and preserve our ability to service debt; and | |
• | Given the size of the capital expenditure program contemplated by us at the time of the June 2005 acquisition, we considered it necessary to enter into a derivative arrangement to reduce the volatility of our cash flow and to ensure an appropriate return on the incremental invested capital. |
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* | CVR GP, LLC, which we refer to as Fertilizer GP, is the managing general partner of CVR Partners, LP. As managing general partner, Fertilizer GP holds incentive distribution rights, or IDRs, which entitle it to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases its distributions above an amount specified in the limited partnership agreement. The IDRs will only be payable after the Partnership has distributed all aggregated adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009. |
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Shares of common stock offered by the selling stockholders | 10,000,000 shares. | |
Option to purchase additional shares of common stock from certain of the selling stockholders | 1,500,000 shares. | |
Common stock outstanding immediately after the offering | 86,141,291 shares. | |
Use of proceeds | We will not receive any proceeds from sales of our common stock by the selling stockholders in this offering. | |
Dividend policy | We do not anticipate paying any dividends on our common stock in the foreseeable future. | |
New York Stock Exchange symbol | “CVI” | |
Concurrent notes offering | Concurrently with this offering, we are offering $125,000,000 aggregate principal amount of % Convertible Senior Notes due 2013 in a registered public offering. The consummation of this offering is not conditioned upon the concurrent consummation of the convertible notes offering and vice versa. | |
Risk Factors | See “Risk Factors” beginning on page 24 of this prospectus for a discussion of factors that you should carefully consider before deciding to invest in shares of our common stock. |
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Successor | ||||||||
Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31 | March 31 | |||||||
2007 | 2008 | |||||||
(unaudited, in millions, except share and per share data) | ||||||||
Statement of Operations Data: | ||||||||
Net sales | $ | 390.5 | $ | 1,223.0 | ||||
Cost of product sold (exclusive of depreciation and amortization) | 303.7 | 1,036.2 | ||||||
Direct operating expenses (exclusive of depreciation and amortization) | 113.4 | 60.6 | ||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 13.2 | 13.4 | ||||||
Net costs associated with flood(1) | — | 5.8 | ||||||
Depreciation and amortization(2) | 14.2 | 19.6 | ||||||
Operating income (loss) | (54.0 | ) | $ | 87.4 | ||||
Other income, net | 0.5 | 0.9 | ||||||
Interest expense and other financing costs | (11.9 | ) | (11.3 | ) | ||||
Loss on derivatives, net | (137.0 | ) | (47.9 | ) | ||||
Income (loss) before income taxes and minority interest in subsidiaries | $ | (202.4 | ) | $ | 29.1 | |||
Income tax (expense) benefit | 47.3 | (6.9 | ) | |||||
Minority interest in (income) loss of subsidiaries | 0.7 | — | ||||||
Net income (loss)(3) | $ | (154.4 | ) | $ | 22.2 | |||
Pro forma loss per share, basic | $ | (1.79 | ) | |||||
Pro forma loss per share, diluted | $ | (1.79 | ) | |||||
Pro forma weighted average shares, basic | 86,141,291 | |||||||
Pro forma weighted average shares, diluted | 86,141,291 | |||||||
Earnings per share, basic | $ | 0.26 | ||||||
Earnings per share, diluted | $ | 0.26 | ||||||
Weighted average shares, basic | 86,141,291 | |||||||
Weighted average shares, diluted | 86,158,791 | |||||||
Segment Financial Data: | ||||||||
Operating income (loss): | ||||||||
Petroleum | (63.5 | ) | 63.6 | |||||
Nitrogen Fertilizer | 9.3 | 26.0 | ||||||
Other | 0.2 | (2.2 | ) | |||||
Operating income (loss): | $ | (54.0 | ) | $ | 87.4 | |||
Depreciation and amortization | ||||||||
Petroleum | 9.8 | 14.9 | ||||||
Nitrogen Fertilizer | 4.4 | 4.5 | ||||||
Other | — | 0.2 | ||||||
Depreciation and amortization(2) | $ | 14.2 | $ | 19.6 | ||||
Other Financial Data: | ||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | $ | (82.4 | ) | $ | 30.6 | |||
Cash flows provided by operating activities | 44.1 | 24.2 | ||||||
Cash flows used in investing activities | (107.4 | ) | (26.2 | ) | ||||
Cash flows provided by (used in) financing activities | 29.0 | (3.4 | ) | |||||
Capital expenditures for property, plant and equipment | 107.4 | 26.2 |
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Successor | ||||||||
Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31 | March 31 | |||||||
2007 | 2008 | |||||||
(unaudited) | ||||||||
Key Operating Statistics: | ||||||||
Petroleum Business | ||||||||
Production (barrels per day)(5) | 53,689 | 125,614 | ||||||
Crude oil throughput (barrels per day)(5) | 47,267 | 106,530 | ||||||
Refining margin per crude oil throughput barrel (dollars)(6) | $ | 12.69 | $ | 13.76 | ||||
NYMEX 2-1-1 crack spread (dollars)(7) | $ | 12.17 | $ | 11.81 | ||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8) | $ | 22.73 | $ | 4.16 | ||||
Gross profit (loss) per crude oil throughput per barrel (dollars)(8) | $ | (12.34 | ) | $ | 7.50 | |||
Nitrogen Fertilizer Business | ||||||||
Production Volume: | ||||||||
Ammonia (tons in thousands) | 86.2 | 83.7 | ||||||
UAN (tons in thousands) | 165.7 | 150.1 | ||||||
On-stream factors: | ||||||||
Gasification | 91.8 | % | 91.8 | % | ||||
Ammonia | 86.3 | % | 90.7 | % | ||||
UAN | 89.4 | % | 85.9 | % |
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 | ||||||||||||||
(in millions, except share and per share data) | |||||||||||||||||
Statement of Operations Data: | |||||||||||||||||
Net sales | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | $ | 2,966.9 | |||||||||
Cost of product sold (exclusive of depreciation and amortization) | 768.0 | 1,168.1 | 2,443.4 | 2,308.8 | |||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 80.9 | 85.3 | 199.0 | 276.1 | |||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 18.4 | 18.4 | 62.6 | 93.1 | |||||||||||||
Net costs associated with flood(1) | — | — | — | 41.5 | |||||||||||||
Depreciation and amortization(2) | 1.1 | 24.0 | 51.0 | 60.8 | |||||||||||||
Operating income | $ | 112.3 | $ | 158.5 | $ | 281.6 | $ | 186.6 | |||||||||
Other income (expense)(9) | (8.4 | ) | 0.4 | (20.8 | ) | 0.2 | |||||||||||
Interest expense and other financing costs | (7.8 | ) | (25.0 | ) | (43.9 | ) | (61.1 | ) | |||||||||
Gain (loss) on derivatives | (7.6 | ) | (316.1 | ) | 94.5 | (282.0 | ) | ||||||||||
Income (loss) before income taxes | $ | 88.5 | $ | (182.2 | ) | $ | 311.4 | $ | (156.3 | ) | |||||||
Income tax (expense) benefit | (36.1 | ) | 63.0 | (119.8 | ) | 88.5 | |||||||||||
Minority interest in (income) loss of subsidiaries | — | — | — | 0.2 | |||||||||||||
Net income (loss)(3) | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | (67.6 | ) | |||||||
Pro forma earnings per share, basic | $ | 2.22 | $ | (0.78 | ) | ||||||||||||
Pro forma earnings per share, diluted | $ | 2.22 | $ | (0.78 | ) | ||||||||||||
Pro forma weighted average shares, basic | 86,141,291 | 86,141,291 | |||||||||||||||
Pro forma weighted average shares, diluted | 86,158,791 | 86,141,291 |
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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 | ||||||||||||||
(in millions, except share and per share data) | |||||||||||||||||
Segment Financial Data: | |||||||||||||||||
Operating income | |||||||||||||||||
Petroleum | 76.7 | 123.0 | 245.6 | 144.9 | |||||||||||||
Nitrogen Fertilizer | 35.3 | 35.7 | 36.8 | 46.6 | |||||||||||||
Other | 0.3 | (0.2 | ) | (0.8 | ) | (4.9 | ) | ||||||||||
Operating income | 112.3 | 158.5 | 281.6 | 186.6 | |||||||||||||
Depreciation and amortization | |||||||||||||||||
Petroleum | 0.8 | 15.6 | 33.0 | 43.0 | |||||||||||||
Nitrogen Fertilizer | 0.3 | 8.4 | 17.1 | 16.8 | |||||||||||||
Other | — | — | 0.9 | 1.0 | |||||||||||||
Depreciation and amortization(2) | 1.1 | 24.0 | 51.0 | 60.8 | |||||||||||||
Other Financial Data: | |||||||||||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | 52.4 | 23.6 | 115.4 | (5.6 | ) | ||||||||||||
Cash flows provided by operating activities | 12.7 | 82.5 | 186.6 | 145.9 | |||||||||||||
Cash flows (used in) investing activities | (12.3 | ) | (730.3 | ) | (240.2 | ) | (268.6 | ) | |||||||||
Cash flows provided by (used in) financing activities | (52.4 | ) | 712.5 | 30.8 | 111.3 | ||||||||||||
Capital expenditures for property, plant and equipment | 12.3 | 45.2 | 240.2 | 268.6 |
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 | ||||||||||||||
(unaudited) | |||||||||||||||||
Key Operating Statistics: | |||||||||||||||||
Petroleum Business | |||||||||||||||||
Production (barrels per day)(5)(10) | 99,171 | 107,177 | 108,031 | 86,201 | |||||||||||||
Crude oil throughput (barrels per day)(5)(10) | 88,012 | 93,908 | 94,524 | 76,285 | |||||||||||||
Refining margin per crude oil throughput barrel (dollars)(6) | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 18.17 | |||||||||
NYMEX 2-1-1 crack spread (dollars)(7) | 9.60 | 13.47 | 10.84 | 13.95 | |||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8) | 3.44 | 3.13 | 3.92 | 7.52 | |||||||||||||
Gross profit (loss) per crude oil throughput barrel (dollars)(8) | 5.79 | 7.55 | 8.39 | 7.79 | |||||||||||||
Nitrogen Fertilizer Business | |||||||||||||||||
Production Volume: | |||||||||||||||||
Ammonia (tons in thousands)(10) | 193.2 | 220.0 | 369.3 | 326.7 | |||||||||||||
UAN (tons in thousands)(10) | 309.9 | 353.4 | 633.1 | 576.9 | |||||||||||||
On-stream factors(11): | |||||||||||||||||
Gasifier | 97.4 | % | 98.7 | % | 92.5 | % | 90.0 | % | |||||||||
Ammonia | 95.0 | % | 98.3 | % | 89.3 | % | 87.7 | % | |||||||||
UAN | 93.9 | % | 94.8 | % | 88.9 | % | 78.7 | % |
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Successor | |||||||||||||||||
December 31 | December 31 | December 31 | March 31 | ||||||||||||||
2005 | 2006 | 2007 | 2008 | ||||||||||||||
(unaudited) | |||||||||||||||||
(in millions) | |||||||||||||||||
Balance Sheet Data: | |||||||||||||||||
Cash and cash equivalents | $ | 64.7 | $ | 41.9 | $ | 30.5 | $ | 25.2 | |||||||||
Working capital | 108.0 | 112.3 | 10.7 | 21.5 | |||||||||||||
Total assets | 1,221.5 | 1,449.5 | 1,868.4 | 1,923.6 | |||||||||||||
Total debt, including current portion | 499.4 | 775.0 | 500.8 | 499.2 | |||||||||||||
Minority interest in subsidiaries(12) | — | 4.3 | 10.6 | 10.6 | |||||||||||||
Divisional/members’/stockholders’ equity | 115.8 | 76.4 | 432.7 | 455.1 |
(1) | Represents the write-off of approximate net costs associated with flood and crude oil spill that are not probable of recovery. See “Flood and Crude Oil Discharge.” | |
(2) | Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general and administrative expenses: |
Immediate | Successor | |||||||||||||||||||||||||
Predecessor | Three | Three | ||||||||||||||||||||||||
174 Days | 233 Days | Year | Year | Months | Months | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||
June 23 | December 31 | December 31 | December 31 | March 31 | March 31 | |||||||||||||||||||||
2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Depreciation and amortization excluded from cost of product sold | $ | 0.1 | $ | 1.1 | $ | 2.2 | $ | 2.4 | $ | 0.6 | $ | 0.6 | ||||||||||||||
Depreciation and amortization excluded from direct operating expenses | 0.9 | 22.7 | 47.7 | 57.4 | 13.5 | 18.7 | ||||||||||||||||||||
Depreciation and amortization excluded from selling, general and administrative expenses | 0.1 | 0.2 | 1.1 | 1.0 | 0.1 | 0.3 | ||||||||||||||||||||
Depreciation included in net costs associated with flood | — | — | — | 7.6 | — | — | ||||||||||||||||||||
Total depreciation and amortization | $ | 1.1 | $ | 24.0 | $ | 51.0 | $ | 68.4 | $ | 14.2 | $ | 19.6 |
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(3) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: |
Immediate | ||||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||||
Three | Three | |||||||||||||||||||||||||
174 Days | 233 Days | Year | Year | Months | Months | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||
June 23 | December 31 | December 31 | December 31 | March 31 | March 31 | |||||||||||||||||||||
2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||
(in millions) | (unaudited) | (unaudited) | ||||||||||||||||||||||||
Loss on extinguishment of debt(a) | $ | 8.1 | $ | — | $ | 23.4 | $ | 1.3 | $ | — | $ | — | ||||||||||||||
Inventory fair market value adjustment(b) | — | 16.6 | — | — | — | — | ||||||||||||||||||||
Funded letter of credit expense and interest rate swap not included in interest expense(c) | — | 2.3 | — | 1.8 | — | 0.9 | ||||||||||||||||||||
Major scheduled turnaround expense(d) | �� | — | — | 6.6 | 76.4 | 66.0 | — | |||||||||||||||||||
Loss on termination of swap(e) | — | 25.0 | — | — | — | — | ||||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | 235.9 | (126.8 | ) | 103.2 | 119.7 | 13.9 |
(a) | Represents the write-off of: (i) $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005, (ii) $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006 and (iii) $1.3 million in connection with the repayment and termination of three credit facilities on October 26, 2007. | |
(b) | Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at June 24, 2005 as a result of the allocation of the purchase price of the Subsequent Acquisition to inventory. | |
(c) | Consists of fees which are expensed to selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the credit facility. | |
(d) | Represents expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and the refinery. | |
(e) | Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005. |
(4) | Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the unrealized portion of the derivative transaction that was executed in conjunction with the acquisition of Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC on June 24, 2005. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not as a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through |
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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. | ||
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect in each period material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements, which is accounted for as a liability on our balance sheet. As the absolute crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as absolute crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. In managing our business and assessing its growth and profitability from a strategic and financial planning perspective, management and our board of directors considers our GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit. | ||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of financial performance or liquidity in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark to market adjustments, the measure does not reflect the fair market value of our Cash Flow Swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies. | ||
The following is a reconciliation of Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap to Net income (loss): |
Immediate | ||||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||||
Three | Three | |||||||||||||||||||||||||
174 Days | 233 Days | Year | Year | Months | Months | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||
June 23 | December 31 | December 31 | December 31 | March 31 | March 31 | |||||||||||||||||||||
2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | (5.6 | ) | $ | (82.4 | ) | $ | 30.6 | ||||||||||||
Plus: | ||||||||||||||||||||||||||
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit | — | (142.8 | ) | 76.2 | (62.0 | ) | (72.0 | ) | (8.4 | ) | ||||||||||||||||
�� | ||||||||||||||||||||||||||
Net income (loss) | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | (67.6 | ) | $ | (154.4 | ) | $ | 22.2 |
(5) | Barrels per day is calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facility’s continuous operations. | |
(6) | Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) divided by the refinery’s crude oil throughput volumes for the respective periods presented. Refining margin per crude oil throughput barrel is a non-GAAP measure that should not be substituted for gross profit or operating income and that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Our calculation of refining margin per crude oil throughput barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. We |
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use refining margin per crude oil throughput barrel as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability. | ||
(7) | This information is industry data and is not derived from our audited financial statements or unaudited interim financial statements. | |
(8) | Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel is calculated by dividing direct operating expenses (exclusive of depreciation and amortization) by total crude oil throughput volumes for the respective periods presented. Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel includes costs associated with the actual operations of the refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance and labor and environmental compliance costs but does not include depreciation or amortization. We use direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel as a measure of operating efficiency within the plant and as a control metric for expenditures. | |
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel is a non-GAAP measure. Our calculations of direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. The following table reflects direct operating expenses (exclusive of depreciation and amortization) and the related calculation of direct operating expenses per crude oil throughput barrel: |
Immediate | ||||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||||
Three | Three | |||||||||||||||||||||||||
174 Days | 233 Days | Year | Year | Months | Months | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||
June 23, | December 31, | December 31, | December 31, | March 31, | March 31, | |||||||||||||||||||||
2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||
(in millions, except as otherwise indicated) | (unaudited) | (unaudited) | ||||||||||||||||||||||||
Petroleum Business: | ||||||||||||||||||||||||||
Net Sales | $ | 903.8 | $ | 1,363.4 | $ | 2,880.4 | $ | 2,806.2 | $ | 352.5 | $ | 1,168.5 | ||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 761.7 | 1,156.2 | 2,422.7 | 2,300.2 | 298.5 | 1,035.1 | ||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||||
Net costs associated with flood | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||||
Depreciation and amortization | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||||
Gross profit (loss) | $ | 88.7 | $ | 135.4 | $ | 289.4 | $ | 216.8 | $ | (52.5 | ) | $ | 72.7 | |||||||||||||
Plus direct operating expenses (exclusive of depreciation and amortization) | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||||
Plus net costs associated with flood | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||||
Plus depreciation and amortization | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||||
Refining margin | $ | 142.1 | $ | 207.2 | $ | 457.7 | $ | 506.0 | $ | 54.0 | $ | 133.4 | ||||||||||||||
Refining margin per crude oil throughput barrel (dollars) | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 18.17 | $ | 12.69 | $ | 13.76 | ||||||||||||||
Gross profit (loss) per crude oil throughput barrel (dollars) | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 7.79 | $ | (12.34 | ) | $ | 7.50 | |||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars) | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 7.52 | $ | 22.73 | $ | 4.16 | ||||||||||||||
Operating income (loss) | 76.7 | 123.0 | 245.6 | 144.9 | (63.5 | ) | 63.6 |
(9) | During the 174 days ended June 23, 2005, the year ended December 31, 2006 and the year ended December 31, 2007, we recognized a loss of $8.1 million, $23.4 million and $1.3 million, respectively, on early extinguishment of debt. |
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(10) | Operational information reflected for the 233 day Successor period ended December 31, 2005 includes only 191 days of operational activity. Successor was formed on May 13, 2005 but had no financial statement activity during the 42 day period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005 which expired unexercised on June 16, 2005. | |
(11) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnaround at the nitrogen fertilizer facility in the third quarter of 2006, the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN. | |
(12) | Minority interest at December 31, 2006 reflects common stock in two of our subsidiaries owned by John J. Lipinski (which were exchanged for shares of our common stock with an equivalent value prior to the consummation of our initial public offering). Minority interest at December 31, 2007 and March 31, 2008 reflects Coffeyville Acquisition III LLC’s ownership of the managing general partner interest and IDRs of the Partnership. |
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• | Original Predecessor refers to the former Petroleum Division and one facility within the eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division of Farmland which Coffeyville Resources, LLC acquired on March 3, 2004 in a sales process under Chapter 11 of the U.S. Bankruptcy Code; | |
• | Initial Acquisition refers to the acquisition of Original Predecessor on March 3, 2004 by Coffeyville Resources, LLC; | |
• | Immediate Predecessor refers to Coffeyville Group Holdings, LLC and its subsidiaries, including Coffeyville Resources, LLC; | |
• | Subsequent Acquisition refers to the acquisition of Immediate Predecessor on June 24, 2005 by Coffeyville Acquisition LLC; and | |
• | Successor refers to (1) Coffeyville Acquisition LLC and its consolidated subsidiaries from June 24, 2005 through October 15, 2007 and (2) CVR Energy, Inc. and its consolidated subsidiaries (including the Partnership) on and after October 16, 2007. |
• | Managing general partner refers to CVR GP, LLC, the Partnership’s managing general partner, which is owned by Coffeyville Acquisition III; | |
• | Special general partner refers to CVR Special GP, LLC, the Partnership’s special general partner, which is indirectly owned by us; | |
• | General Partners refers to the Partnership’s managing general partner and special general partner; | |
• | Coffeyville Resources refers to Coffeyville Resources, LLC, the subsidiary of CVR Energy which is the sole limited partner of the Partnership; | |
• | Coffeyville Acquisition refers to Coffeyville Acquisition LLC, an entity owned principally by the Kelso Funds, which owns 36.5% of our common stock prior to this offering and will own 30.7% of our common stock following this offering, assuming all of the shares of common stock offered hereby are sold and the underwriters do not exercise their option to purchase additional shares; | |
• | Coffeyville Acquisition II refers to Coffeyville Acquisition II LLC, an entity owned principally by the Goldman Sachs Funds, which owns 36.5% of our common stock prior to this offering and will own 30.7% of our common stock following this offering, assuming all of the shares of common stock offered hereby are sold and the underwriters do not exercise their option to purchase additional shares; and | |
• | Coffeyville Acquisition III refers to Coffeyville Acquisition III LLC, the owner of the Partnership’s managing general partner, which in turn is owned by the Goldman Sachs Funds, the Kelso Funds and certain members of CVR Energy’s senior management team. |
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• | our upgraded equipment may not perform at expected throughput levels; | |
• | the yield and product quality of new equipment may differ from design; and | |
• | redesign or modification of the equipment may be required to correct equipment that does not perform as expected, which could require facility shutdowns until the equipment has been redesigned or modified. |
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• | unforeseen difficulties in the acquired operations and disruption of the ongoing operations of our petroleum business and the nitrogen fertilizer business; | |
• | failure to achieve cost savings or other financial or operating objectives with respect to an acquisition; | |
• | strain on the operational and managerial controls and procedures of our petroleum business and the nitrogen fertilizer business, and the need to modify systems or to add management resources; | |
• | difficulties in the integration and retention of customers or personnel and the integration and effective deployment of operations or technologies; | |
• | assumption of unknown material liabilities or regulatory non-compliance issues; | |
• | amortization of acquired assets, which would reduce future reported earnings; | |
• | possible adverse short-term effects on our cash flows or operating results; and | |
• | diversion of management’s attention from the ongoing operations of our business. |
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• | making it more difficult to satisfy obligations to our creditors, including holders of the convertible senior notes; | |
• | limiting our ability to obtain additional financing to fund our working capital, acquisitions, expenditures, debt service requirements or for other purposes; | |
• | limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt; | |
• | limiting our ability to compete with other companies who are not as highly leveraged; | |
• | placing restrictive financial and operating covenants in the agreements governing our and our subsidiaries’ long-term indebtedness and bank loans, including, in the case of certain indebtedness of subsidiaries, certain covenants that restrict the ability of subsidiaries to pay dividends or make other distributions to us; | |
• | exposing us to potential events of default (if not cured or waived) under financial and operating covenants contained in our or our subsidiaries’ debt instruments that could have a material adverse effect on our business, financial condition and operating results; | |
• | increasing our vulnerability to a downturn in general economic conditions or in pricing of our products; and | |
• | limiting our ability to react to changing market conditions in our industry and in our customers’ industries. |
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• | the requirement that a majority of our board of directors consist of independent directors; | |
• | the requirement that we have a nominating/corporate governance committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and | |
• | the requirement that we have a compensation committee that is composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities. |
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• | the failure of securities analysts to cover our common stock or changes in financial estimates by analysts; | |
• | announcements by us or our competitors of significant contracts or acquisitions; | |
• | variations in quarterly results of operations; | |
• | loss of a large customer or supplier; | |
• | general economic conditions; | |
• | terrorist acts; | |
• | future sales of our common stock; and | |
• | investor perceptions of us and the industries in which our products are used. |
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We Hold Our Interest in the Nitrogen Fertilizer Business
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• | Fertilizer GP, as managing general partner of the Partnership, holds all of the IDRs in the Partnership. IDRs give Fertilizer GP a right to increasing percentages of the Partnership’s quarterly distributions after the Partnership has distributed all adjusted operating surplus generated by the Partnership during the period from October 24, 2007 through December 31, 2009, assuming the Partnership and its subsidiaries are released from their guaranty of our credit facility and if the quarterly distributions exceed the target of $0.4313 per unit. Fertilizer GP may have an incentive to manage the Partnership in a manner which preserves or increases the possibility of these future cash flows rather than in a manner that preserves or increases current cash flows. | |
• | Fertilizer GP may also have an incentive to engage in conduct with a high degree of risk in order to increase cash flows substantially and thereby increase the value of the IDRs instead of following a safer course of action. | |
• | The owners of Fertilizer GP, who are also our controlling stockholders and senior management, are permitted to compete with us or the Partnership or to own businesses that compete with us or the Partnership. In addition, the owners of Fertilizer GP are not required to share business opportunities with us, and our owners are not required to share business opportunities with the Partnership or Fertilizer GP. | |
• | Neither the partnership agreement nor any other agreement requires the owners of Fertilizer GP to pursue a business strategy that favors us or the Partnership. The owners of Fertilizer GP have fiduciary duties to make decisions in their own best interests, which may be contrary to our interests and the interests of the Partnership. In addition, Fertilizer GP is allowed to take into account the interests of parties other than us, such as its owners, or the Partnership in resolving conflicts of interest, which has the effect of limiting its fiduciary duty to us. | |
• | Fertilizer GP has limited its liability and reduced its fiduciary duties under the partnership agreement and has also restricted the remedies available to the unitholders of the Partnership, |
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including us, for actions that, without the limitations, might constitute breaches of fiduciary duty. As a result of our ownership interest in the Partnership, we may consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law. |
• | Fertilizer GP determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, issuances of additional partnership interests and cash reserves maintained by the Partnership (subject to our specified joint management rights), each of which can affect the amount of cash that is available for distribution to us in our capacity as a holder of special units and the amount of cash paid to Fertilizer GP in respect of its IDRs. | |
• | Fertilizer GP will also able to determine the amount and timing of any capital expenditures and whether a capital expenditure is for maintenance, which reduces operating surplus, or expansion, which does not. Such determinations can affect the amount of cash that is available for distribution and the manner in which the cash is distributed. | |
• | In some instances Fertilizer GP may cause the Partnership to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions, which may not be in our interests. | |
• | The partnership agreement permits the Partnership to classify up to $60 million as operating surplus, even if this cash is generated from asset sales, borrowings other than working capital borrowings or other sources the distribution of which would otherwise constitute capital surplus. This cash may be used to fund distributions in respect of the IDRs. | |
• | The partnership agreement does not restrict Fertilizer GP from causing the nitrogen fertilizer business to pay it or its affiliates for any services rendered to the Partnership or entering into additional contractual arrangements with any of these entities on behalf of the Partnership. | |
• | Fertilizer GP may exercise its rights to call and purchase all of the Partnership’s equity securities of any class if at any time it and its affiliates (excluding us) own more than 80% of the outstanding securities of such class. | |
• | Fertilizer GP controls the enforcement of obligations owed to the Partnership by it and its affiliates. In addition, Fertilizer GP decides whether to retain separate counsel or others to perform services for the Partnership. | |
• | Fertilizer GP determines which costs incurred by it and its affiliates are reimbursable by the Partnership. | |
• | The executive officers of Fertilizer GP, and the majority of the directors of Fertilizer GP, also serve as our directorsand/or executive officers. The executive officers who work for both us and Fertilizer GP, including our chief executive officer, chief operating officer, chief financial officer and general counsel, divide their time between our business and the business of the Partnership. These executive officers will face conflicts of interest from time to time in making decisions which may benefit either us or the Partnership. |
• | The partnership agreement 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 |
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obligation to give any consideration to any interest of, or factors affecting, us or our affiliates. Decisions made by Fertilizer GP in its individual capacity will be made by the sole member of Fertilizer GP, and not by the board of directors of Fertilizer GP. Examples include the exercise of its limited call right, its voting rights, its registration rights and its determination whether or not to consent to any merger or consolidation or amendment to the partnership agreement. |
• | The partnership agreement provides that Fertilizer GP will not have any liability to the Partnership or to us for decisions made in its capacity as managing general partner so long as it acted in good faith, meaning it believed that the decisions were in the best interests of the Partnership. | |
• | The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that Fertilizer GP or those persons acted in bad faith or engaged in fraud or willful misconduct, or in the case of a criminal matter, acted with knowledge that such person’s conduct was criminal. | |
• | The partnership agreement generally provides that affiliate transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unitholders must be on terms no less favorable to the Partnership than those generally provided to or available from unrelated third parties or be “fair and reasonable.” In determining whether a transaction or resolution is “fair and reasonable,” Fertilizer GP may consider the totality of the relationship between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership. |
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• | The managing general partner of the nitrogen fertilizer business has broad discretion to establish reserves for the prudent conduct of the nitrogen fertilizer business. The establishment of those reserves could result in a reduction of the nitrogen fertilizer business’ distributions. | |
• | The amount of distributions made by the nitrogen fertilizer business and the decision to make any distribution are determined by the managing general partner of the Partnership, whose interests may be different from ours. The managing general partner of the Partnership has limited fiduciary and contractual duties, which may permit it to favor its own interests to our detriment. | |
• | Although the partnership agreement requires the nitrogen fertilizer business to distribute its available cash, the partnership agreement may be amended. | |
• | Any credit facility that the nitrogen fertilizer business enters into may limit the distributions which the nitrogen fertilizer business can make. In addition, any credit facility may contain financial tests and covenants that the nitrogen fertilizer business must satisfy. Any failure to comply with these tests and covenants could result in the lenders prohibiting distributions by the nitrogen fertilizer business. | |
• | The actual amount of cash available for distribution will depend on numerous factors, some of which are beyond the control of the nitrogen fertilizer business, including the level of capital expenditures made by the nitrogen fertilizer business, the nitrogen fertilizer business’ debt service requirements, the cost of acquisitions, if any, fluctuations in its working capital needs, its ability to borrow funds and access capital markets, the amount of fees and expenses incurred by the nitrogen fertilizer business, and restrictions on distributions and on the ability of the nitrogen fertilizer business to make working capital and other borrowings for distributions contained in its credit agreements. |
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• | volatile margins in the refining industry; | |
• | exposure to the risks associated with volatile crude prices; | |
• | the availability of adequate cash and other sources of liquidity for our capital needs; | |
• | disruption of our ability to obtain an adequate supply of crude oil; | |
• | losses due to the Cash Flow Swap; | |
• | decreases in the light/heavyand/or the sweet/sour crude oil price spreads; | |
• | losses, damages and lawsuits related to the flood and crude oil discharge; | |
• | the failure of our new and redesigned equipment in our facilities to perform according to expectations; | |
• | interruption of the pipelines supplying feedstock and in the distribution of our products; | |
• | the seasonal nature of our petroleum business; | |
• | competition in the petroleum and nitrogen fertilizer businesses; | |
• | capital expenditures required by environmental laws and regulations; | |
• | changes in our credit profile; | |
• | the potential decline in the price of natural gas, which historically has correlated with the market price for nitrogen fertilizer products; | |
• | the cyclical nature of the nitrogen fertilizer business; | |
• | adverse weather conditions, including potential floods; | |
• | the supply and price levels of essential raw materials; | |
• | the volatile nature of ammonia, potential liability for accidents involving ammonia that cause severe damage to propertyand/or injury to the environment and human health and potential increased costs relating to transport of ammonia; | |
• | the dependence of the nitrogen fertilizer operations on a few third-party suppliers; | |
• | the reliance of the nitrogen fertilizer business on third-party providers of transportation services and equipment; | |
• | environmental laws and regulations affecting the end-use and application of fertilizers; |
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• | a decrease in ethanol production; | |
• | the potential loss of the nitrogen fertilizer business’ transportation cost advantage over its competitors; | |
• | refinery operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage; | |
• | our commodity derivative activities; | |
• | uncertainty regarding our ability to recover costs and losses resulting from the flood and crude oil discharge; | |
• | our limited operating history as a stand-alone company; | |
• | our dependence on significant customers; | |
• | our potential inability to successfully implement our business strategies, including the completion of significant capital programs; | |
• | the success of our acquisition and expansion strategies; | |
• | the dependence on our subsidiaries for cash to meet our debt obligations; | |
• | our significant indebtedness; | |
• | whether we will be able to amend our credit facility on acceptable terms if the Partnership seeks to consummate a public or private offering; | |
• | the potential loss of key personnel; | |
• | labor disputes and adverse employee relations; | |
• | potential increases in costs and distraction of management resulting from the requirements of being a public company; | |
• | risks relating to evaluations of internal controls required by Section 404 of the Sarbanes-Oxley Act; | |
• | the operation of our company as a “controlled company”; | |
• | new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities; | |
• | successfully defending against third-party claims of intellectual property infringement; | |
• | our ability to continue to license the technology used in our operations; | |
• | the Partnership’s ability to make distributions equal to the minimum quarterly distribution or any distributions at all; | |
• | the possibility that Partnership distributions to us will decrease if the Partnership issues additional equity interests and that our rights to receive distributions will be subordinated to the rights of third party investors; | |
• | the possibility that we will be required to deconsolidate the Partnership from our financial statements in the future; | |
• | the Partnership’s preferential right to pursue certain business opportunities before we pursue them; | |
• | reduction of our voting power in the Partnership if the Partnership completes a public offering or private placement; |
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• | whether we will be required to purchase the managing general partner interest in the Partnership, and whether we will have the requisite funds to do so; | |
• | the possibility that we will be required to sell a portion of our interests in the Partnership in the Partnership’s initial offering at an undesirable time or price; | |
• | the ability of the Partnership to manage the nitrogen fertilizer business in a manner adverse to our interests; | |
• | the conflicts of interest faced by our senior management, which operates both our company and the Partnership, and our controlling stockholders, who control our company and the managing general partner of the Partnership; | |
• | limitations on the fiduciary duties owed by the managing general partner which are included in the partnership agreement; | |
• | whether we are ever deemed to be an investment company under the 1940 Act or will need to take actions to sell interests in the Partnership or buy assets to refrain from being deemed an investment company; | |
• | changes in the treatment of the Partnership as a partnership for U.S. income tax purposes; | |
• | transfer of control of the managing general partner of the Partnership to a third party that may have no economic interest in us; and | |
• | the risk that the Partnership will not consummate a public offering or private placement. |
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High | Low | |||||||
Year Ended December 31, 2007: | ||||||||
Fourth Quarter (from October 23, 2007) | $ | 26.25 | $ | 19.80 | ||||
Year Ending December 31, 2008: | ||||||||
First Quarter | 30.94 | 20.71 | ||||||
Second Quarter (through June 17, 2008) | 28.88 | 19.57 |
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• | on an actual basis; | |
• | on an adjusted basis to give effect to (a) the proposed $25.0 million senior secured credit facility, (b) certain expenses associated with this offering and (c) the Phantom Unit Plans payment of $3.5 million (assuming the underwriters’ option is not exercised) by us to members of our senior management team as a result of this offering, as if each had occurred on March 31, 2008; and | |
• | on an as further adjusted basis to give effect to (a), (b) and (c) above as well as (d) our concurrent offering of $125.0 million aggregate principal amount of our Convertible Senior Notes due 2013 (assuming the underwriters’ option is not exercised), as if each had occurred on March 31, 2008. The consummation of this equity offering is not conditioned upon the consummation of our concurrent offering of Convertible Senior Notes due 2013 and vice versa. |
As of March 31, 2008 | ||||||||||||
Further | ||||||||||||
Adjusted for | ||||||||||||
Convertible | ||||||||||||
Actual | As Adjusted | Offering | ||||||||||
(unaudited) | (unaudited) | |||||||||||
(in thousands) | ||||||||||||
Cash and cash equivalents | $ | 25,179 | $ | $ | ||||||||
Debt (including current portion): | ||||||||||||
Revolving credit facility(1) | $ | — | $ | $ | ||||||||
Term loan facility | 487,979 | |||||||||||
Proposed senior secured credit facility | ||||||||||||
Convertible senior notes due 2013 | — | |||||||||||
Total debt | 487,979 | |||||||||||
Minority interest in subsidiaries(2) | 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 | |||||||||||
Preferred stock, $0.01 par value per share, 50,000,000 shares authorized; no shares issued and outstanding | — | |||||||||||
Additionalpaid-in-capital | 458,523 | |||||||||||
Retained earning (deficit) | (4,279 | ) | ||||||||||
Total stockholders’ equity | 455,105 | |||||||||||
Total capitalization | $ | 953,684 | $ | $ | ||||||||
(1) | As of June 16, 2008, we had availability of $112.6 million under our revolving credit facility. | |
(2) | Represents the managing general partner’s interest in the Partnership held by Coffeyville Acquisition III LLC. |
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Successor | ||||||||
Three Months | Three Months | |||||||
Ended | Ended | |||||||
March 31, 2007 | March 31, 2008 | |||||||
(unaudited) | ||||||||
(in millions, unless | ||||||||
otherwise indicated) | ||||||||
Statement of Operations Data: | ||||||||
Net sales | $ | 390.5 | $ | 1,223.0 | ||||
Cost of product sold (exclusive of depreciation and amortization) | 303.7 | 1,036.2 | ||||||
Direct operating expenses (exclusive of depreciation and amortization) | 113.4 | 60.6 | ||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 13.2 | 13.4 | ||||||
Net costs associated with flood(1) | — | 5.8 | ||||||
Depreciation and amortization(2) | 14.2 | 19.6 | ||||||
Operating income (loss) | (54.0 | ) | 87.4 | |||||
Other income, net | 0.5 | 0.9 | ||||||
Interest expense and other financing costs | (11.9 | ) | (11.3 | ) | ||||
Loss on derivatives, net | (137.0 | ) | (47.9 | ) | ||||
Income (loss) before income taxes and minority interests in subsidiaries | (202.4 | ) | 29.1 | |||||
Income tax (expense) benefit | (47.3 | ) | (6.9 | ) | ||||
Minority interest in (income) loss of subsidiaries | 0.7 | — | ||||||
Net income (loss)(3) | (154.4 | ) | 22.2 | |||||
Pro forma earnings (loss) per share, basic | (1.79 | ) | ||||||
Pro forma earnings (loss) per share, diluted | (1.79 | ) | ||||||
Pro forma weighted average shares, basic | 86,141,291 | |||||||
Pro forma weighted average shares, diluted | 86,141,291 | |||||||
Earnings per share, basic | 0.26 | |||||||
Earnings per share, diluted | 0.26 | |||||||
Weighted average shares, basic | 86,141,291 | |||||||
Weighted average shares, diluted | 86,158,791 | |||||||
Balance Sheet Data: | ||||||||
Cash and cash equivalents | 25.2 | |||||||
Working capital | 21.5 | |||||||
Total assets | 1,923.6 | |||||||
Total debt, including current portion | 499.2 | |||||||
Minority interest in subsidiaries | 10.6 | |||||||
Stockholders’ equity | 455.1 | |||||||
Other Financial Data: | ||||||||
Depreciation and amortization(2) | 14.2 | 19.6 | ||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | (82.4 | ) | 30.6 | |||||
Cash flows provided by operating activities | 44.1 | 24.2 | ||||||
Cash flows (used in) investing activities | (107.4 | ) | (26.2 | ) | ||||
Cash flows provided by (used in) financing activities | 29.0 | (3.4 | ) | |||||
Capital expenditures for property, plant and equipment | 107.4 | 26.2 | ||||||
Key Operating Statistics: | ||||||||
Petroleum Business | ||||||||
Production (barrels per day)(5) | 53,689 | 125,614 | ||||||
Crude oil throughput (barrels per day)(5) | 47,267 | 106,530 | ||||||
Refining margin per crude oil throughput barrel (dollars)(6) | $ | 12.69 | $ | 13.76 | ||||
NYMEX 2-1-1 crack spread (dollars)(7) | $ | 12.17 | $ | 11.81 | ||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8) | $ | 22.73 | $ | 4.16 | ||||
Gross profit (loss) per crude oil throughput per barrel (dollars)(8) | $ | (12.34 | ) | $ | 7.50 | |||
Nitrogen Fertilizer Business | ||||||||
Production Volume: | ||||||||
Ammonia (tons in thousands) | 86.2 | 83.7 | ||||||
UAN (tons in thousands) | 165.7 | 150.1 | ||||||
On-stream factors: | ||||||||
Gasification | 91.8 | % | 91.8 | % | ||||
Ammonia | 86.3 | % | 90.7 | % | ||||
UAN | 89.4 | % | 85.9 | % |
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Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Year | ||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | December 31, | ||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2007 | ||||||||||||||||||||||
(in millions, unless otherwise indicated) | ||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||
Net sales | $ | 1,262.2 | $ | 261.1 | $ | 1,479.9 | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | $ | 2,966.9 | ||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 1,061.9 | 221.4 | 1,244.2 | 768.0 | 1,168.1 | 2,443.4 | 2,308.8 | |||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 133.1 | 23.4 | 117.0 | 80.9 | 85.3 | 199.0 | 276.1 | |||||||||||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 23.6 | 4.7 | 16.3 | 18.4 | 18.4 | 62.6 | 93.1 | |||||||||||||||||||||
Net costs associated with flood(1) | — | — | — | — | — | — | 41.5 | |||||||||||||||||||||
Depreciation and amortization(2) | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | 60.8 | |||||||||||||||||||||
Impairment, earnings (losses) in joint ventures, and other charges(9) | 10.9 | — | — | — | — | — | — | |||||||||||||||||||||
Operating income | $ | 29.4 | $ | 11.2 | $ | 100.0 | $ | 112.3 | $ | 158.5 | $ | 281.6 | $ | 186.6 | ||||||||||||||
Other income (expense)(10) | (0.5 | ) | — | (6.9 | ) | (8.4 | ) | 0.4 | (20.8 | ) | 0.2 | |||||||||||||||||
Interest (expense) | (1.3 | ) | — | (10.1 | ) | (7.8 | ) | (25.0 | ) | (43.9 | ) | (61.1 | ) | |||||||||||||||
Gain (loss) on derivatives | 0.3 | — | 0.5 | (7.6 | ) | (316.1 | ) | 94.5 | (282.0 | ) | ||||||||||||||||||
Income (loss) before income taxes | $ | 27.9 | $ | 11.2 | $ | 83.5 | $ | 88.5 | $ | (182.2 | ) | $ | 311.4 | $ | (156.3 | ) | ||||||||||||
Income tax (expense) benefit | — | — | (33.8 | ) | (36.1 | ) | 63.0 | (119.8 | ) | 88.5 | ||||||||||||||||||
Minority interest in (income) loss of subsidiaries | — | — | — | — | — | — | 0.2 | |||||||||||||||||||||
Net income (loss)(3) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | (67.6 | ) | ||||||||||||
Pro forma earnings per share, basic | $ | 2.22 | $ | (0.78 | ) | |||||||||||||||||||||||
Pro forma earnings per share, diluted | $ | 2.22 | $ | (0.78 | ) | |||||||||||||||||||||||
Pro forma weighted average shares, basic | 86,141,291 | 86,141,291 | ||||||||||||||||||||||||||
Pro forma weighted average shares, diluted | 86,158,791 | 86,141,291 | ||||||||||||||||||||||||||
Historical dividends: | ||||||||||||||||||||||||||||
Preferred per unit(11) | $ | 1.50 | $ | 0.70 | ||||||||||||||||||||||||
Common per unit(11) | $ | 0.48 | $ | 0.70 | ||||||||||||||||||||||||
Management common units subject to redemption | $ | 3.1 | ||||||||||||||||||||||||||
Common units | $ | 246.9 | ||||||||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||||||||||
Cash and cash equivalents | $ | 0.0 | $ | 52.7 | $ | 64.7 | $ | 41.9 | $ | 30.5 | ||||||||||||||||||
Working capital(12) | 150.5 | 106.6 | 108.0 | 112.3 | 10.7 | |||||||||||||||||||||||
Total assets | 199.0 | 229.2 | 1,221.5 | 1,449.5 | 1,868.4 | |||||||||||||||||||||||
Liabilities subject to compromise(13) | 105.2 | — | — | — | — | |||||||||||||||||||||||
Total debt, including current portion | — | 148.9 | 499.4 | 775.0 | 500.8 | |||||||||||||||||||||||
Minority interest in subsidiaries(14) | — | — | — | 4.3 | 10.6 | |||||||||||||||||||||||
Management units subject to redemption | — | — | 3.7 | 7.0 | — | |||||||||||||||||||||||
Divisional/members’/stockholders’ equity | 58.2 | 14.1 | 115.8 | 76.4 | 432.7 | |||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||
Depreciation and amortization | $ | 3.3 | $ | 0.4 | $ | 2.4 | $ | 1.1 | $ | 24.0 | $ | 51.0 | $ | 68.4 | ||||||||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | 27.9 | 11.2 | 49.7 | 52.4 | 23.6 | 115.4 | (5.6 | ) | ||||||||||||||||||||
Cash flows provided by operating activities | 20.3 | 53.2 | 89.8 | 12.7 | 82.5 | 186.6 | 145.9 | |||||||||||||||||||||
Cash flows (used in) investing activities | (0.8 | ) | — | (130.8 | ) | (12.3 | ) | (730.3 | ) | (240.2 | ) | (268.6 | ) | |||||||||||||||
Cash flows provided by (used in) financing activities | (19.5 | ) | (53.2 | ) | 93.6 | (52.4 | ) | 712.5 | 30.8 | 111.3 | ||||||||||||||||||
Capital expenditures for property, plant and equipment | 0.8 | — | 14.2 | 12.3 | 45.2 | 240.2 | 268.6 | |||||||||||||||||||||
Key Operating Statistics: | ||||||||||||||||||||||||||||
Petroleum Business | ||||||||||||||||||||||||||||
Production (barrels per day)(5)(15) | 95,701 | 106,645 | 102,046 | 99,171 | 107,177 | 108,031 | 86,201 | |||||||||||||||||||||
Crude oil throughput (barrels per day)(5)(15) | 85,501 | 92,596 | 90,418 | 88,012 | 93,908 | 94,524 | 76,285 | |||||||||||||||||||||
Refining margin per crude oil throughput barrel (dollars)(6) | $ | 3.89 | $ | 4.23 | $ | 5.92 | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 18.17 | ||||||||||||||
NYMEX 2-1-1 crack spread (dollars)(7) | $ | 5.53 | $ | 6.80 | $ | 7.55 | $ | 9.60 | $ | 13.47 | $ | 10.84 | $ | 13.95 | ||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars)(8) | $ | 2.57 | $ | 2.60 | $ | 2.66 | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 7.52 | ||||||||||||||
Gross profit (loss) per crude oil throughput per barrel (dollars)(8) | $ | 1.25 | $ | 1.57 | $ | 3.20 | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 7.79 | ||||||||||||||
Nitrogen Fertilizer Business | ||||||||||||||||||||||||||||
Production Volume: | ||||||||||||||||||||||||||||
Ammonia (tons in thousands)(15) | 335.7 | 56.4 | 252.8 | 193.2 | 220.0 | 369.3 | 326.7 | |||||||||||||||||||||
UAN (tons in thousands)(15) | 510.6 | 93.4 | 439.2 | 309.9 | 353.4 | 633.1 | 576.9 | |||||||||||||||||||||
On-steam factors (16): | ||||||||||||||||||||||||||||
Gasifier | 90.1 | % | 93.5 | % | 92.2 | % | 97.4 | % | 98.7 | % | 92.5 | % | 90.0 | % | ||||||||||||||
Ammonia | 89.6 | % | 80.9 | % | 79.7 | % | 95.0 | % | 98.3 | % | 89.3 | % | 87.7 | % | ||||||||||||||
UAN | 81.6 | % | 88.7 | % | 82.2 | % | 93.9 | % | 94.8 | % | 88.9 | % | 78.7 | % |
(1) | Represents the write-off of approximate net costs associated with the flood and crude oil spill that are not probable of recovery. See “Flood and Crude Oil Discharge”. | |
(2) | Depreciation and amortization is comprised of the following components as excluded from cost of product sold, direct operating expenses and selling, general and administrative expenses: |
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Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Three Months | |||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | March 31, | |||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||||||||||
(unaudited) | (unaudited) | ||||||||||||||||||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||||||||||||
Depreciation and amortization included in cost of product sold | $ | — | $ | — | $ | 0.2 | $ | 0.1 | $ | 1.1 | $ | 2.2 | $ | 2.4 | $ | 0.6 | $ | 0.6 | |||||||||||||||||||
Depreciation and amortization included in direct operating expense | 3.3 | 0.4 | 2.2 | 0.9 | 22.7 | 47.7 | 57.4 | 13.5 | 18.7 | ||||||||||||||||||||||||||||
Depreciation and amortization included in selling, general and administrative expense | — | — | 0.2 | 0.1 | 0.2 | 1.1 | 1.0 | 0.1 | 0.3 | ||||||||||||||||||||||||||||
Depreciation and amortization included in net costs associated with flood | — | — | — | — | — | — | 7.6 | — | — | ||||||||||||||||||||||||||||
Total depreciation and amortization | $ | 3.3 | $ | 0.4 | $ | 2.4 | $ | 1.1 | $ | 24.0 | $ | 51.0 | $ | 68.4 | $ | 14.2 | $ | 19.6 |
(3) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: |
Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Three Months | |||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | March 31, | |||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||||||||||
(unaudited) | (unaudited) | ||||||||||||||||||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||||||||||||
Impairment of property, plant and equipment(a) | $ | 9.6 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||
Loss on extinguishment of debt(b) | — | — | 7.2 | 8.1 | — | 23.4 | 1.3 | — | — | ||||||||||||||||||||||||||||
Inventory fair market value adjustment(c) | — | — | 3.0 | — | 16.6 | — | — | — | — | ||||||||||||||||||||||||||||
Funded letter of credit expense and interest rate swap not included in interest expense(d) | — | — | — | — | 2.3 | — | 1.8 | — | 0.9 | ||||||||||||||||||||||||||||
Major scheduled turnaround expense(e) | — | — | 1.8 | — | — | 6.6 | 76.4 | 66.0 | — | ||||||||||||||||||||||||||||
Loss on termination of swap(f) | — | — | — | — | 25.0 | — | — | — | — | ||||||||||||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | — | — | — | 235.9 | (126.8 | ) | 103.2 | 119.7 | 13.9 |
(a) | During the year ended December 31, 2003, we recorded a charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. | |
(b) | Represents the write-off of: (i) $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004, (ii) $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005, (iii) $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006 and (iv) $1.3 million in connection with the repayment and termination of three credit facilities on October 26, 2007. | |
(c) | Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory. | |
(d) | Consists of fees which are expensed to selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the credit facility. | |
(e) | Represents expense associated with a major scheduled turnaround. | |
(f) | Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005. |
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(4) | Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the unrealized portion of the derivative transaction that was executed in conjunction with the acquisition of Coffeyville Group Holdings, LLC by Coffeyville Acquisition LLC on June 24, 2005. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned by Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not as a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. Based upon expected crude oil capacity of 115,000 bpd, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, so long as at the time of reduction or termination, we pay the amount of unrealized losses associated with the amount reduced or terminated. See “Description of our Indebtedness and the Cash Flow Swap.” |
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of financial performance or liquidity in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark to market adjustments, the measure does not reflect the fair market value of our Cash Flow Swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies. | ||
The following is a reconciliation of Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap to Net income (loss): |
Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||||
Year | |||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Ended | Three | |||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | December 31, | Months Ended | |||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | March 31, | ||||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||||||||||
(in millions) | (unaudited) | (unaudited) | |||||||||||||||||||||||||||||||||||
Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | (5.6 | ) | $ | (82.4 | ) | $ | 30.6 | |||||||||||||||||
Plus: | |||||||||||||||||||||||||||||||||||||
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit | — | — | — | — | (142.8 | ) | 76.2 | (62.0 | ) | (72.0 | ) | (8.4 | ) | ||||||||||||||||||||||||
Net income (loss) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | (67.6 | ) | $ | (154.4 | ) | $ | 22.2 |
(5) | Barrels per day is calculated by dividing the volume in the period by the number of calendar days in the period. Barrels per day as shown here is impacted by plant down-time and other plant disruptions and does not represent the capacity of the facility’s continuous operations. | |
(6) | Refining margin per crude oil throughput barrel is a measurement calculated as the difference between net sales and cost of product sold (exclusive of depreciation and amortization) divided by the refinery’s crude oil throughput volumes for the respective periods presented. Refining margin per crude oil throughput barrel is a non-GAAP measure that should not be substituted for gross profit or operating income and that we believe is important to investors in evaluating our refinery’s performance as a general indication of the amount above our cost of product sold that we are able to sell refined products. Our calculation of refining margin per crude oil throughput barrel may differ from similar calculations of other companies in our industry, thereby limiting its usefulness as a comparative measure. We use refining margin per crude oil throughput barrel as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability. | |
The table included in footnote 8 reconciles refining margin per crude oil throughput barrel to gross profit for the periods presented. | ||
(7) | This information is industry data and is not derived from our audited financial statements or unaudited interim financial statements. |
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(8) | Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel is calculated by dividing direct operating expenses (exclusive of depreciation and amortization) by total crude oil throughput volumes for the respective periods presented. Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel includes costs associated with the actual operations of the refinery, such as energy and utility costs, catalyst and chemical costs, repairs and maintenance and labor and environmental compliance costs but does not include depreciation or amortization. We use direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel as a measure of operating efficiency within the plant and as a control metric for expenditures. |
Historical | |||||||||||||||||||||||||||||||||||||||
Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||||||
Three | Three | ||||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Year | Months | Months | |||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | December 31, | March 31, | March 31, | |||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||||||||||||||
(unaudited) | (unaudited) | ||||||||||||||||||||||||||||||||||||||
(in millions, except as otherwise indicated) | |||||||||||||||||||||||||||||||||||||||
Petroleum Business: | |||||||||||||||||||||||||||||||||||||||
Net Sales | $ | 1,161.3 | $ | 241.6 | $ | 1,390.8 | $ | 903.8 | $ | 1,363.4 | $ | 2,880.4 | $ | 2,806.2 | $ | 352.5 | $ | 1,168.5 | |||||||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 1,040.0 | 217.4 | 1,228.1 | 761.7 | 1,156.2 | 2,422.7 | 2,300.2 | 298.5 | 1,035.1 | ||||||||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||||||||||||||
Net costs associated with flood | — | — | — | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||||||||||||||
Gross profit (loss) | $ | 39.1 | $ | 9.0 | $ | 88.0 | $ | 88.7 | $ | 135.4 | $ | 289.4 | $ | 216.8 | $ | (52.5 | ) | $ | 72.7 | ||||||||||||||||||||
Plus direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||||||||||||||
Plus net costs associated with flood | — | — | — | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||||||||||||||
Plus depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||||||||||||||
Refining margin | $ | 121.3 | $ | 24.2 | $ | 162.7 | $ | 142.1 | $ | 207.2 | $ | 457.7 | $ | 506.0 | $ | 54.0 | $ | 133.4 | |||||||||||||||||||||
Refining margin per crude oil throughput barrel (dollars) | $ | 3.89 | $ | 4.23 | $ | 5.92 | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 18.17 | $ | 12.69 | $ | 13.76 | |||||||||||||||||||||
Gross profit (loss) per crude oil throughput barrel (dollars) | $ | 1.25 | $ | 1.57 | $ | 3.20 | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 7.79 | $ | (12.34 | ) | $ | 7.50 | ||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel (dollars) | $ | 2.57 | $ | 2.60 | $ | 2.66 | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 7.52 | $ | 22.73 | $ | 4.16 | |||||||||||||||||||||
Operating income (loss) | 21.5 | 7.7 | 77.1 | 76.7 | 123.0 | 245.6 | 144.9 | (63.5 | ) | 63.6 |
(9) | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code. | |
(10) | During the 304 days ended December 31, 2004, the 174 days ended June 23, 2005, the year ended December 31, 2006 and the year ended December 31, 2007, we recognized a loss of $7.2 million, $8.1 million, $23.4 million and $1.3 million, respectively, on early extinguishment of debt. | |
(11) | Historical dividends per unit for the304-day period ended December 31, 2004 and the174-day period ended June 23, 2005 are calculated based on the ownership structure of Immediate Predecessor. | |
(12) | Excludes liabilities subject to compromise due to Original Predecessor’s bankruptcy of $105.2 million as of December 31, 2003 in calculating Original Predecessor’s working capital. | |
(13) | While operating under Chapter 11 of the U.S. Bankruptcy Code, Original Predecessor’s financial statements were prepared in accordance withSOP 90-7, “Financial Reporting by Entities in Reorganization under the Bankruptcy Code.”SOP 90-7 requires that pre-petition liabilities be segregated in the balance sheet. |
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(14) | Minority interest reflects common stock in two of our subsidiaries owned by John J. Lipinski (which were exchanged for shares of our common stock with an equivalent value prior to the consummation of our initial public offering). Minority interest at December 31, 2007 reflects Coffeyville Acquisition III LLC’s ownership of the managing general partner interest and IDRs of the Partnership. | |
(15) | Operational information reflected for the233-day Successor period ended December 31, 2005 includes only 191 days of operational activity. Successor was formed on May 13, 2005 but had no financial statement activity during the42-day period from May 13, 2005 to June 24, 2005, with the exception of certain crude oil, heating oil and gasoline option agreements entered into with J. Aron as of May 16, 2005 which expired unexercised on June 16, 2005. | |
(16) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the nitrogen fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors for the year ended December 31, 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN and (ii) the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN. |
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FINANCIAL CONDITION AND RESULTS OF OPERATIONS
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Quarter Ended September 30, 2007 Financial Statements
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• | a sale of some or all of our partnership interests to an unrelated party; | |
• | a sale of the managing general partner interest to a third party; | |
• | the issuance by the Partnership of partnership interests to parties other than us or our related parties; and | |
• | the acquisition by us of additional partnership interests (either new interests issued by the Partnership or interests acquired from unrelated interest holders). |
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Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | |||||||||||||||||||||||
Ended | Ended | Year Ended | Year Ended | Three Months | ||||||||||||||||||||
June 23, | December 31, | December 31, | December 31, | Ended March 31, | ||||||||||||||||||||
Consolidated Financial Results | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net sales | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | $ | 2,966.9 | $ | 390.5 | $ | 1,223.0 | ||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 768.0 | 1,168.1 | 2,443.4 | 2,308.8 | 303.7 | 1,036.2 | ||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 80.9 | 85.3 | 199.0 | 276.1 | 113.4 | 60.6 | ||||||||||||||||||
Selling, general and administrative expense (exclusive of depreciation and amortization) | 18.4 | 18.4 | 62.6 | 93.1 | 13.2 | 13.4 | ||||||||||||||||||
Net costs associated with flood(1) | — | — | — | 41.5 | — | 5.8 | ||||||||||||||||||
Depreciation and amortization(2) | 1.1 | 24.0 | 51.0 | 60.8 | 14.2 | 19.6 | ||||||||||||||||||
Operating income | $ | 112.3 | $ | 158.5 | $ | 281.6 | $ | 186.6 | $ | (54.0 | ) | $ | 87.4 | |||||||||||
Net income (loss)(3) | 52.4 | (119.2 | ) | 191.6 | (67.6 | ) | (154.4 | ) | 22.2 | |||||||||||||||
Net income (loss) adjusted for | ||||||||||||||||||||||||
unrealized gain or loss from Cash Flow Swap(4) | 52.4 | 23.6 | 115.4 | (5.6 | ) | (137.0 | ) | (47.9 | ) |
(1) | Represents the write-off of approximate net costs associated with the flood and crude oil discharge that are not probable of recovery. See “Flood and Crude Oil Discharge.” | |
(2) | Depreciation and amortization is comprised of the following components as excluded from cost of products sold, direct operating expense and selling, general and administrative expense: |
Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | Year | ||||||||||||||||||||||
Ended | Ended | Ended | Three Months | |||||||||||||||||||||
June 23, | December 31, | December 31, | Ended March 31, | |||||||||||||||||||||
Consolidated Financial Results | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Depreciation and amortization excluded from cost of product sold | $ | 0.1 | $ | 1.1 | $ | 2.2 | $ | 2.4 | $ | 0.6 | $ | 0.6 | ||||||||||||
Depreciation and amortization excluded from direct operating expenses | 0.9 | 22.7 | 47.7 | 57.4 | 13.5 | 18.7 | ||||||||||||||||||
Depreciation and amortization excluded from selling, general and administrative expense | 0.1 | 0.2 | 1.1 | 1.0 | 0.1 | 0.3 | ||||||||||||||||||
Depreciation included in net costs associated with flood | — | — | — | 7.6 | — | — | ||||||||||||||||||
Total depreciation and amortization | $ | 1.1 | $ | 24.0 | $ | 51.0 | $ | 68.4 | $ | 14.2 | $ | 19.6 |
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(3) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: |
Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | Year | ||||||||||||||||||||||
Ended | Ended | Ended | Three Months | |||||||||||||||||||||
June 23, | December 31, | December 31, | Ended March 31, | |||||||||||||||||||||
Consolidated Financial Results | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Loss of extinguishment of debt(a) | $ | 8.1 | $ | — | $ | 23.4 | $ | 1.3 | $ | — | $ | — | ||||||||||||
Inventory fair market value adjustment(b) | — | 16.6 | — | — | — | — | ||||||||||||||||||
Funded letter of credit expense & interest rate swap not included in interest expense(c) | — | 2.3 | — | 1.8 | — | 0.9 | ||||||||||||||||||
Major scheduled turnaround expense(d) | — | — | 6.6 | 76.4 | 66.0 | — | ||||||||||||||||||
Loss on termination of swap(e) | — | 25.0 | — | — | — | — | ||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | 235.9 | (126.8 | ) | 103.2 | 119.7 | 13.9 |
(a) | Represents the write-off of $8.1 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on June 23, 2005, the write-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006 and the write-off of $1.3 million in connection with the repayment and termination of three credit facilities on October 26, 2007. | |
(b) | Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at June 24, 2005, as a result of the allocation of the purchase price of the Subsequent Acquisition to inventory. | |
(c) | Consists of fees which are expensed to selling, general and administrative expense in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the credit facility. | |
(d) | Represents expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery. | |
(e) | Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005. | |
(4) | Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the unrealized portion of the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if absolute (i.e., in dollar terms, not as a percentage of crude oil prices) crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if absolute crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. The Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods July 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of our credit facility and upon meeting specific requirements related to our leverage ratio and our credit ratings, we are permitted to reduce the Cash Flow Swap to 35,000 bpd, or approximately 30% of expected crude oil capacity, for the period from April 1, 2008 through December 31, 2008 and terminate the Cash Flow Swap in 2009 and 2010, so long as at the time of reduction or termination, we pay the amount of unrealized losses associated with the amount reduced or terminated. | |
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which is accounted for as a liability on our balance sheet. As the absolute crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as absolute crack spreads decline, we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income (loss) adjusted for unrealized gain or loss from Cash Flow |
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Swap as a key indicator of our business performance. In managing our business and assessing its growth and profitability from a strategic and financial planning perspective, management and our board of directors considers our GAAP net income results as well as Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap enhances the understanding of our results of operations by highlighting income attributable to our ongoing operating performance exclusive of charges and income resulting from mark to market adjustments that are not necessarily indicative of the performance of our underlying business and our industry. The adjustment has been made for the unrealized loss from Cash Flow Swap net of its related tax benefit. | ||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our financial performance or liquidity but instead should be utilized as a supplemental measure of performance in evaluating our business. Because Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap excludes mark to market adjustments, the measure does not reflect the fair market value of our cash flow swap in our net income. As a result, the measure does not include potential cash payments that may be required to be made on the Cash Flow Swap in the future. Also, our presentation of this non-GAAP measure may not be comparable to similarly titled measures of other companies. |
Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | Year | ||||||||||||||||||||||
Ended | Ended | Ended | Three Months | |||||||||||||||||||||
June 23, | December 31, | December 31, | Ended March 31, | |||||||||||||||||||||
Consolidated Financial Results | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | (5.6 | ) | $ | (82.4 | ) | $ | 30.6 | ||||||||||
Plus: | ||||||||||||||||||||||||
Unrealized gain or (loss) from Cash Flow Swap, net of taxes | — | (142.8 | ) | 76.2 | (62.0 | ) | (72.0 | ) | (8.4 | ) | ||||||||||||||
Net income (loss) | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | (67.6 | ) | $ | (154.4 | ) | $ | 22.2 |
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Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | Year | Year | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Three Months | ||||||||||||||||||||
June 23, | December 31, | December 31, | December 31, | Ended March 31, | ||||||||||||||||||||
2005 | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Petroleum Business: | ||||||||||||||||||||||||
Net sales | $ | 903.8 | $ | 1,363.4 | $ | 2,880.4 | $ | 2,806.2 | $ | 352.5 | $ | 1,168.5 | ||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 761.7 | 1,156.2 | 2,422.7 | 2,300.2 | 298.5 | 1,035.1 | ||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||
Net costs associated with flood | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||
Depreciation and amortization | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||
Gross profit (loss) | $ | 88.7 | $ | 135.4 | $ | 289.4 | $ | 216.8 | $ | (52.5 | ) | $ | 72.7 | |||||||||||
Plus direct operating expenses (exclusive of depreciation and amortization) | 52.6 | 56.2 | 135.3 | 209.5 | 96.7 | 40.3 | ||||||||||||||||||
Plus net costs associated with flood | — | — | — | 36.7 | — | 5.5 | ||||||||||||||||||
Plus depreciation and amortization | 0.8 | 15.6 | 33.0 | 43.0 | 9.8 | 14.9 | ||||||||||||||||||
Refining margin | $ | 142.1 | $ | 207.2 | $ | 457.7 | $ | 506.0 | $ | 54.0 | $ | 133.4 | ||||||||||||
Refining margin per crude oil throughput barrel | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 18.17 | $ | 12.69 | $ | 13.76 | ||||||||||||
Gross profit (loss) per crude oil throughput barrel | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 7.79 | $ | (12.34 | ) | $ | 7.50 | |||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per crude oil throughput barrel | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 7.52 | $ | 22.73 | $ | 4.16 | ||||||||||||
Operating income (loss) | 76.7 | 123.0 | 245.6 | 144.9 | (63.5 | ) | 63.6 |
Immediate | ||||||||||||||||||||
Predecessor | ||||||||||||||||||||
and Successor | ||||||||||||||||||||
Combined | Successor | |||||||||||||||||||
Year Ended | Year Ended | Year Ended | Three Months | |||||||||||||||||
December 31, | December 31, | December 31, | Ended March 31, | |||||||||||||||||
2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||
(dollars per barrel, except as indicated) | ||||||||||||||||||||
Market Indicators | ||||||||||||||||||||
West Texas Intermediate (WTI) crude oil | $ | 56.70 | $ | 66.25 | $ | 72.36 | $ | 58.27 | $ | 97.82 | ||||||||||
NYMEX 2-1-1 Crack Spread | 11.62 | 10.84 | 13.95 | 12.17 | 11.81 | |||||||||||||||
Crude Oil Differentials: | ||||||||||||||||||||
WTI less WTS (sour) | 4.73 | 5.36 | 5.16 | 4.26 | 4.63 | |||||||||||||||
WTI less Maya (heavy sour) | 15.67 | 14.99 | 12.54 | 14.80 | 19.84 | |||||||||||||||
WTI less Dated Brent (foreign) | 2.18 | 1.13 | (0.02 | ) | 0.51 | 1.10 | ||||||||||||||
PADD II Group 3 versus NYMEX Basis: | ||||||||||||||||||||
Gasoline | (0.53 | ) | 1.52 | 3.56 | (0.54 | ) | (1.46 | ) | ||||||||||||
Heating Oil | 3.20 | 7.42 | 7.95 | 8.77 | 3.65 | |||||||||||||||
PADD II Group 3 versus NYMEX Crack: | ||||||||||||||||||||
Gasoline | 10.53 | 12.26 | 18.34 | 12.43 | 4.95 | |||||||||||||||
Heating Oil | 15.60 | 18.77 | 21.40 | 20.57 | 20.77 |
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Immediate | ||||||||||||||||||||
Predecessor | ||||||||||||||||||||
and Successor | ||||||||||||||||||||
Combined | Successor | |||||||||||||||||||
Year Ended | Year Ended | Year Ended | Three Months | |||||||||||||||||
December 31, | December 31, | December 31, | Ended March 31, | |||||||||||||||||
2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||
(dollars per barrel, except as indicated) | ||||||||||||||||||||
Company Operating Statistics | ||||||||||||||||||||
Per barrel profit, margin and expense of crude oil throughput: | ||||||||||||||||||||
Refining margin | $ | 10.50 | $ | 13.27 | $ | 18.17 | $ | 12.69 | $ | 13.76 | ||||||||||
Gross profit | $ | 6.74 | $ | 8.39 | $ | 7.79 | $ | (12.34 | ) | $ | 7.50 | |||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 3.27 | 3.92 | 7.52 | 22.73 | 4.16 | |||||||||||||||
Per gallon sales price: | ||||||||||||||||||||
Gasoline | 1.61 | 1.88 | 2.20 | 1.59 | 2.45 | |||||||||||||||
Distillate | 1.71 | 1.99 | 2.28 | 1.78 | 2.85 |
Immediate | ||||||||||||||||||||||||||||||||||||||||
Predecessor and | ||||||||||||||||||||||||||||||||||||||||
Successor Combined | Successor | Successor | Three Months | |||||||||||||||||||||||||||||||||||||
December 31, | December 31, | December 31, | Ended March 31, | |||||||||||||||||||||||||||||||||||||
2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||||||||||||||||||||
Selected Company | Barrels | Barrels | Barrels | Barrels | Barrels | |||||||||||||||||||||||||||||||||||
Volumetric Data | per Day | % | per Day | % | per Day | % | per Day | % | per Day | % | ||||||||||||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||||||||||||||||
Production: | ||||||||||||||||||||||||||||||||||||||||
Total gasoline | 45,275 | 43.8 | 48,248 | 44.7 | 37,017 | 42.9 | 23,499 | 43.8 | 59,662 | 47.5 | ||||||||||||||||||||||||||||||
Total distillate | 39,997 | 38.7 | 42,175 | 39.0 | 34,814 | 40.4 | 21,976 | 40.9 | 48,591 | 38.7 | ||||||||||||||||||||||||||||||
Total other | 18,090 | 17.5 | 17,608 | 16.3 | 14,370 | 16.7 | 8,214 | 15.3 | 17,361 | 13.8 | ||||||||||||||||||||||||||||||
Total all production | 103,362 | 100.0 | 108,031 | 100.0 | 86,201 | 100.0 | 53,689 | 100.0 | 125,614 | 100.0 | ||||||||||||||||||||||||||||||
Crude oil throughput | 91,097 | 92.6 | 94,524 | 92.1 | 76,285 | 93.0 | 47,267 | 92.7 | 106,530 | 89.0 | ||||||||||||||||||||||||||||||
All other inputs | 7,246 | 7.4 | 8,067 | 7.9 | 5,780 | 7.0 | 3,716 | 7.3 | 13,197 | 11.0 | ||||||||||||||||||||||||||||||
Total feedstocks | 98,343 | 100.0 | 102,591 | 100.0 | 82,065 | 100.0 | 50,983 | 100.0 | 119,727 | 100.0 | ||||||||||||||||||||||||||||||
Crude oil throughput by crude type: | ||||||||||||||||||||||||||||||||||||||||
Sweet | 13,958,567 | 42.0 | 17,481,803 | 50.7 | 18,190,459 | 65.3 | 2,782,136 | 65.4 | 6,573,627 | 67.8 | ||||||||||||||||||||||||||||||
Light/medium-sour | 19,291,951 | 58.0 | 16,695,173 | 48.4 | 6,465,368 | 23.2 | 1,454,878 | 34.2 | 1,785,669 | 18.4 | ||||||||||||||||||||||||||||||
Heavy sour | — | — | 324,312 | 0.9 | 3,188,133 | 11.5 | 17,016 | 0.4 | 1,334,889 | 13.8 | ||||||||||||||||||||||||||||||
Total crude oil throughput | 33,250,518 | 100.0 | 34,501,288 | 100.0 | 27,843,960 | 100.0 | 4,254,030 | 100.0 | 9,694,185 | 100.0 |
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Immediate | ||||||||||||||||||||||||
Predecessor | Successor | |||||||||||||||||||||||
174 Days | 233 Days | Year | ||||||||||||||||||||||
Ended | Ended | Ended | Three Months | |||||||||||||||||||||
June 23, | December 31, | December 31, | Ended March 31, | |||||||||||||||||||||
Nitrogen Fertilizer Business Financial Results | 2005 | 2005 | 2006 | 2007 | 2007 | 2008 | ||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net sales | $ | 79.3 | $ | 93.7 | $ | 162.5 | $ | 165.9 | $ | 38.6 | $ | 62.6 | ||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 9.1 | 14.5 | 25.9 | 13.0 | 6.1 | 8.9 | ||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 28.3 | 29.2 | 63.7 | 66.7 | 16.7 | 20.3 | ||||||||||||||||||
Net costs associated with flood | — | — | — | 2.4 | — | — | ||||||||||||||||||
Depreciation and amortization | 0.3 | 8.4 | 17.1 | 16.8 | 4.4 | 4.5 | ||||||||||||||||||
Operating income | 35.3 | 35.7 | 36.8 | 46.6 | 9.3 | 26.0 |
Year Ended December 31, | Three Months Ended March 31, | |||||||||||||||||||
Market Indicators | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||
Natural gas (dollars per MMBtu) | $ | 9.01 | $ | 6.98 | $ | 7.12 | $ | 7.17 | $ | 8.74 | ||||||||||
Ammonia — Southern Plains (dollars per ton) | 356 | 353 | 409 | 389 | 590 | |||||||||||||||
UAN — Corn Belt (dollars per ton) | 212 | 197 | 288 | 239 | 371 |
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Predecessor | ||||||||||||||||||||
and Successor | ||||||||||||||||||||
Combined | Successor | |||||||||||||||||||
Year Ended | Year Ended | Year Ended | ||||||||||||||||||
December 31, | December 31, | December 31, | Three Months Ended March 31, | |||||||||||||||||
Company Operating Statistics | 2005 | 2006 | 2007 | 2007 | 2008 | |||||||||||||||
Production (thousand tons): | ||||||||||||||||||||
Ammonia | 413.2 | 369.3 | 326.7 | 86.2 | 83.7 | |||||||||||||||
UAN | 663.3 | 633.1 | 576.9 | 165.7 | 150.1 | |||||||||||||||
Total | 1,076.5 | 1,002.4 | 903.6 | 251.9 | 233.8 | |||||||||||||||
Sales (thousand tons)(1): | ||||||||||||||||||||
Ammonia | 141.8 | 117.3 | 92.1 | 20.7 | 24.1 | |||||||||||||||
UAN | 646.5 | 645.5 | 555.4 | 166.8 | 158.0 | |||||||||||||||
Total | 788.3 | 762.8 | 647.5 | 187.5 | 182.1 | |||||||||||||||
Product pricing (plant gate) (dollars per ton)(1): | ||||||||||||||||||||
Ammonia | $ | 324 | $ | 338 | $ | 376 | $ | 347 | $ | 494 | ||||||||||
UAN | $ | 173 | $ | 162 | $ | 211 | $ | 169 | $ | 262 | ||||||||||
On-stream factor(2): | ||||||||||||||||||||
Gasifier | 98.1 | % | 92.5 | % | 90.0 | % | 91.8 | % | 91.8 | % | ||||||||||
Ammonia | 96.7 | % | 89.3 | % | 87.7 | % | 86.3 | % | 90.7 | % | ||||||||||
UAN | 94.3 | % | 88.9 | % | 78.7 | % | 89.4 | % | 85.9 | % | ||||||||||
Reconciliation to net sales (dollars in thousands): | ||||||||||||||||||||
Freight in revenue | $ | 15,010 | $ | 17,890 | $ | 13,826 | $ | 3,139 | $ | 4,022 | ||||||||||
Hydrogen revenue | — | 5,291 | ||||||||||||||||||
Sales net plant gate | 157,989 | 144,575 | 152,030 | 35,436 | 53,287 | |||||||||||||||
Total net sales | $ | 172,999 | $ | 162,465 | $ | 165,856 | $ | 38,575 | $ | 62,600 |
(1) | Plant gate sales per ton represents net sales less freight revenue divided by product sales volume in tons in the reporting period. Plant gate price per ton is shown in order to provide a pricing measure that is comparable across the fertilizer industry. | |
(2) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the fertilizer facility in the third quarter of 2006, the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN. |
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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). | |
• | Revolving loan borrowings bear interest at either (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 2.25%, or, at the borrower’s option, (b) LIBOR plus 3.25% (with step-downs to the prime rate/federal funds rate plus 1.75% or 1.50% or LIBOR plus 2.75% or 2.50%, respectively, upon achievement of certain rating conditions). | |
• | Letters of credit issued under the $75.0 million sub-limit available under the revolving loan facility are subject to a fee equal to the applicable margin on revolving LIBOR loans owing to all revolving lenders and a fronting fee of 0.25% per annum owing to the issuing lender. | |
• | Funded letters of credit are subject to a fee equal to the applicable margin on term LIBOR loans owed to all funded letter of credit lenders and a fronting fee of 0.125% per annum owing to the issuing lender. The borrower is also obligated to pay a fee of 0.10% to the administrative agent on a quarterly basis based on the average balance of funded letters of credit outstanding during the calculation period, for the maintenance of a credit-linked deposit account backstopping funded letters of credit. |
• | 100% of the net asset sale proceeds received from specified asset sales and net insurance/ condemnation proceeds, if the borrower does not reinvest those proceeds in assets to be used in its business or make other permitted investments within 12 months or if, within 12 months of receipt, the borrower does not contract to reinvest those proceeds in assets to be used in its business or make other permitted investments within 18 months of receipt, each subject to certain limitations; | |
• | 100% of the cash proceeds from the incurrence of specified debt obligations; and | |
• | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that with respect to any fiscal year commencing with fiscal 2008 this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is 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. |
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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 |
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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 | |||||||||||
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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%. | |
• | $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. |
• | 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%. |
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2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental and safety capital needs | $ | 144.6 | $ | 121.8 | $ | 46.0 | $ | 53.9 | $ | 23.5 | $ | 2.6 | $ | 2.1 | $ | 394.5 | ||||||||||||||||
Sustaining capital needs | 11.8 | 14.9 | 22.0 | 29.8 | 22.3 | 22.0 | 22.0 | 144.8 | ||||||||||||||||||||||||
156.4 | 136.7 | 68.0 | 83.7 | 45.8 | 24.6 | 24.1 | 539.3 | |||||||||||||||||||||||||
Major scheduled turnaround expenses | 4.0 | 76.4 | — | — | 50.0 | — | — | 130.4 | ||||||||||||||||||||||||
Total estimated non-discretionary spending | $ | 160.4 | $ | 213.1 | $ | 68.0 | $ | 83.7 | $ | 95.8 | $ | 24.6 | $ | 24.1 | $ | 669.7 |
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental and safety capital needs | $ | 0.1 | $ | 0.5 | $ | 2.2 | $ | 4.5 | $ | 2.6 | 2.7 | 3.8 | $ | 16.4 | ||||||||||||||||||
Sustaining capital needs | 6.6 | 3.9 | 9.7 | 3.1 | 4.5 | 4.8 | 4.3 | 36.9 | ||||||||||||||||||||||||
6.7 | 4.4 | 11.9 | 7.6 | 7.1 | 7.5 | 8.1 | 53.3 | |||||||||||||||||||||||||
Major scheduled turnaround expenses | 2.6 | — | 2.8 | — | 2.6 | — | 2.8 | 10.8 | ||||||||||||||||||||||||
Total estimated non-discretionary spending | $ | 9.3 | $ | 4.4 | $ | 14.7 | $ | 7.6 | $ | 9.7 | $ | 7.5 | $ | 10.9 | $ | 64.1 |
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental and safety capital needs | $ | 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 |
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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 | ) |
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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 | $ | — | $ | — | $ | — | $ | — | $ | — |
(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.” | |
(2) | The nitrogen fertilizer business leases various facilities and equipment, primarily railcars, under non-cancelable operating leases for various periods. | |
(3) | The amount includes (1) commitments under several agreements in our petroleum operations related to pipeline usage, petroleum products storage and petroleum transportation and (2) commitments under an electric supply agreement with the city of Coffeyville. | |
(4) | Environmental liabilities represents (1) our estimated payments required by federal and/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas and (2) our estimated remaining costs to address environmental contamination resulting from a reported release of UAN in 2005 pursuant to the State of Kansas Voluntary Cleanup and Property Redevelopment Program. We also have other environmental liabilities which are not contractual obligations but which would be necessary for our continued operations. See “Business — Environmental Matters”. | |
(5) | This amount represents the total of all fees related to the funded letter of credit issued under our Credit Facility. The funded letter of credit is utilized as credit support for the Cash Flow Swap. See “— Quantitative and Qualitative Disclosures About Market Risk — Commodity Price Risk”. | |
(6) | Interest payments are based on interest rates in effect at April 1, 2008 and assume contractual amortization payments. | |
(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. |
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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; | |
• | hedge the value of inventories in excess of minimum required inventories; and | |
• | hedge the value of inventories held with respect to our rack marketing business. |
• | Time Basis — In entering into over-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underlying physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods then weighted average physical prices will be weighted differently than the swap price as the result of timing. | |
• | Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area. |
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Effective | Termination | Fixed | ||||||||||
Notional Amount | Date | Date | Rate | |||||||||
$250.0 million | March 31, 2008 | March 30, 2009 | 4.195 | % | ||||||||
$180.0 million | March 31, 2009 | March 30, 2010 | 4.195 | % | ||||||||
$110.0 million | March 31, 2010 | June 29, 2010 | 4.195 | % |
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Ammonia | UAN 32 | |||||||
State | Quantity | Quantity(1) | ||||||
(thousand tons | ||||||||
per year) | ||||||||
Texas | 2,125 | 850 | ||||||
Oklahoma | 95 | 200 | ||||||
Kansas | 395 | 690 | ||||||
Missouri | 325 | 230 | ||||||
Iowa | 710 | 900 | ||||||
Nebraska | 425 | 1,150 | ||||||
Minnesota | 310 | 200 |
(1) | UAN 32, which consists of 45% ammonium nitrate, 35% urea and 20% water, contains 32% nitrogen by weight and is the most common grade of UAN sold in the United States.Source: Blue Johnson |
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Year | Natural Gas | WTI | Ammonia | UAN 32 | ||||||||||||
($/million btu) | ($/bbl) | ($/ton) | ($/ton) | |||||||||||||
1990 | 1.78 | 24.53 | 125 | 90 | ||||||||||||
1991 | 1.53 | 21.55 | 130 | 97 | ||||||||||||
1992 | 1.73 | 20.57 | 134 | 95 | ||||||||||||
1993 | 2.11 | 18.43 | 139 | 102 | ||||||||||||
1994 | 1.94 | 17.16 | 197 | 108 | ||||||||||||
1995 | 1.69 | 18.38 | 238 | 132 | ||||||||||||
1996 | 2.50 | 22.01 | 217 | 129 | ||||||||||||
1997 | 2.48 | 20.59 | 220 | 116 | ||||||||||||
1998 | 2.16 | 14.43 | 162 | 96 | ||||||||||||
1999 | 2.32 | 19.26 | 145 | 86 | ||||||||||||
2000 | 4.32 | 30.28 | 208 | 115 | ||||||||||||
2001 | 4.04 | 25.92 | 262 | 144 | ||||||||||||
2002 | 3.37 | 26.19 | 191 | 108 | ||||||||||||
2003 | 5.49 | 31.03 | 292 | 141 | ||||||||||||
2004 | 6.18 | 41.47 | 326 | 170 | ||||||||||||
2005 | 9.02 | 56.58 | 394 | 210 | ||||||||||||
2006 | 6.98 | 66.09 | 379 | 196 | ||||||||||||
2007 | 7.12 | 72.36 | 469 | 290 | ||||||||||||
2008 (through May) | 9.77 | 106.54 | 681 | 377 |
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• | Expanding 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 permit the nitrogen fertilizer business to increase its UAN production and to result in its UAN manufacturing facility consuming substantially all of its net ammonia production. This should increase the nitrogen fertilizer plant’s margins because UAN has historically been a higher margin product than ammonia. The UAN expansion is expected to be complete in July 2010 and it is estimated that it will result in an approximately 50% increase in the nitrogen fertilizer business’ annual UAN production. The company has also begun to acquire or lease offsite UAN storage facilities and continues to expand this program. | |
• | Executing Several Efficiency-Based and Other Projects. The nitrogen fertilizer business is currently engaged in several efficiency-based and other projects in order to reduce overall operating costs, incrementally increase its ammonia production and utilize byproducts to generate revenue. For example, by redesigning the system that segregates carbon dioxide, or CO2, during the gasification process, the nitrogen fertilizer business estimates that it will be able to produce approximately 25 tons per day of incremental ammonia, worth approximately $6 million per year at current market prices. The nitrogen fertilizer business estimates that this project will cost approximately $7 million (of which none has yet been incurred) and will be completed in 2010. | |
• | Evaluating Construction of a Third Gasifier Unit and a New Ammonia Unit and UAN Unit at the Nitrogen Fertilizer Plant. The nitrogen fertilizer business has engaged a major engineering firm to help it evaluate the construction and operation of an additional gasifier unit to produce a synthesis gas from pet coke. It is expected that the addition of a third gasifier unit, together with additional ammonia and UAN units, to the nitrogen fertilizer business’ operations could result, on a long-term basis, in an increase in UAN production of approximately 75,000 tons per month. This project is in its earliest stages of review and is still subject to numerous levels of internal analysis. |
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• | Crude Oil Gathering System. We own and operate a 25,000 bpd capacity crude oil gathering system serving central Kansas, northern Oklahoma and southwestern Nebraska. The system has field offices in Bartlesville, Oklahoma and Plainville and Winfield, Kansas. The system is comprised of over 300 miles of feeder and trunk pipelines, 43 trucks, and associated storage facilities for gathering light, sweet Kansas, Nebraska and Oklahoma crude oils purchased from independent crude producers. We also lease a section of a pipeline from Magellan Pipeline Company, L.P. | |
• | Phillipsburg Terminal. We own storage and terminalling facilities for asphalt and refined fuels at Phillipsburg, Kansas. Our asphalt storage and terminalling facilities are used to receive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement. We also collect fees for refined products we store for another oil company. | |
• | Pipelines. We own a 145,000 bpd proprietary pipeline system that transports crude oil from Caney, Kansas to our refinery. Crude oils sourced outside of our proprietary gathering system are delivered by common carrier pipelines into various terminals in Cushing, Oklahoma, where they are blended and then delivered to Caney, Kansas via a pipeline owned by Plains All American L.P. We also own associated crude oil storage tanks with a capacity of approximately 1.2 million barrels located outside our refinery. | |
• | Rack Marketing Division. We own a rack marketing division which supplies product through tanker trucks directly to customers located in close geographic proximity to our refinery and Phillipsburg terminal and to customers at throughput terminals on Magellan Midstream Partners L.P.’s refined products distribution systems. |
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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 | |||||||||
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Year Ended December 31, | ||||||||||||||||||||
2003 | 2004(1) | 2005 | 2006(1) | 2007(1) | ||||||||||||||||
Gasifier | 90.1 | % | 92.4 | % | 98.1 | % | 92.5 | % | 90.0 | % | ||||||||||
Ammonia | 89.6 | % | 79.9 | % | 96.7 | % | 89.3 | % | 87.7 | % | ||||||||||
UAN | 81.6 | % | 83.3 | % | 94.3 | % | 88.9 | % | 78.7 | % |
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(1) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the nitrogen fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors in 2004 would have been 95.6% for gasifier, 83.1% for ammonia and 86.7% for UAN, and (ii) the on-stream factors for the year ended December 31, 2006 would have been 97.1% for gasifier, 94.3% for ammonia and 93.6% for UAN. Excluding the impact of the flood during the weekend of June 30, 2007, the on-stream factors for the year ended December 31, 2007 would have been 94.6% for gasifier, 92.4% for ammonia and 83.9% for UAN. |
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• | restrictions on operationsand/or the need to install enhanced or additional controls; | |
• | the need to obtain and comply with permits, licenses and authorizations; | |
• | liability for the investigation and remediation of contaminated soil and groundwater at current and former facilities and off-site waste disposal locations; and | |
• | specifications for the products manufactured and marketed by our petroleum and nitrogen fertilizer businesses, primarily gasoline, diesel fuel, UAN and ammonia. |
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Total | ||||||||||||||||
Site | Total O&M | Estimated | ||||||||||||||
Investigation | Costs | Costs | ||||||||||||||
Facility | Costs | Capital Costs | Through 2011 | Through 2011 | ||||||||||||
Coffeyville Oil Refinery | $ | 0.3 | $ | — | $ | 1.1 | $ | 1.4 | ||||||||
Phillipsburg Terminal | 0.3 | — | 1.9 | 2.2 | ||||||||||||
Total Estimated Costs | $ | 0.6 | $ | — | $ | 3.0 | $ | 3.6 | ||||||||
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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; | |
• | management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; | |
• | recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions; | |
• | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice; | |
• | recommending the payment of distributions; and | |
• | managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time. |
Location | Acres | Own/Lease | Use | |||||
Coffeyville, KS | 440 | Own | Oil refinery, fertilizer plant and office buildings | |||||
Phillipsburg, KS | 200 | Own | Terminal facility | |||||
Montgomery County, KS (Coffeyville Station) | 20 | Own | Crude oil storage | |||||
Montgomery County, KS (Broome Station) | 20 | Own | Crude oil storage | |||||
Bartlesville, OK | 25 | Own | Truck storage and office buildings | |||||
Winfield, KS | 5 | Own | Truck storage | |||||
Cushing, OK | 185 | Own | Crude oil storage | |||||
Cowley County, KS (Hooser Station) | 80 | Own | Crude oil storage | |||||
Holdrege, NE | 7 | Own | Crude oil storage | |||||
Stockton, KS | 6 | Own | Crude oil storage | |||||
Sugar Land, TX | 22,000 (square feet) | Lease | Office space | |||||
Kansas City, KS | 18,400 (square feet) | Lease | Office space |
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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. | |
• | 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. |
• | 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. |
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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. | |
• | Our builders’ risk policy provided coverage for property damage to buildings in the course of construction. Flood-related loss or damage was subject to a $100,000 deductible and sub-limit of $50 million. | |
• | Our environmental insurance coverage program provided coverage for bodily injury, property damage, and cleanup costs resulting from new pollution conditions. At the time of the flood, the program included a primary policy with a $25.0 million aggregate limit of liability. This policy was subject to a $1 million self-insured retention. In addition, at the time of the flood we had a $25.0 million excess policy that was triggered by exhaustion of the primary policy. The excess policy covered bodily injury and property damage resulting from new pollution conditions, but did not cover cleanup costs. | |
• | Our umbrella and excess liability coverage program provided $100 million of coverage for claims in excess of $5.0 million and other applicable insurance for third-party claims of property damage and bodily injury arising out of the sudden and accidental discharge of pollutants. |
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Total Costs | ||||||||
Total gross costs incurred | $ | 154.5 | ||||||
Total insurance receivable | (107.2 | ) | ||||||
Net costs associated with the flood | $ | 47.3 | ||||||
Receivable | ||||
Reconciliation | ||||
Total insurance receivable | $ | 107.2 | ||
Less insurance proceeds received | (21.5 | ) | ||
Insurance receivable | $ | 85.7 | ||
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Name | Age | Position | ||||
John J. Lipinski | 57 | Chairman of the Board of Directors, Chief Executive Officer and President | ||||
Stanley A. Riemann | 57 | Chief Operating Officer | ||||
James T. Rens | 41 | Chief Financial Officer and Treasurer | ||||
Edmund S. Gross | 57 | Senior Vice President, General Counsel and Secretary | ||||
Daniel J. Daly, Jr. | 62 | Executive Vice President, Strategy | ||||
Robert W. Haugen | 50 | Executive Vice President, Refining Operations | ||||
Wyatt E. Jernigan | 56 | Executive Vice President, Crude Oil Acquisition and Petroleum Marketing | ||||
Kevan A. Vick | 54 | Executive Vice President and Fertilizer General Manager | ||||
Christopher G. Swanberg | 50 | Vice President, Environmental, Health and Safety | ||||
Scott L. Lebovitz | 32 | Director | ||||
Regis B. Lippert | 68 | Director | ||||
George E. Matelich | 52 | Director | ||||
Steve A. Nordaker | 61 | Director | ||||
Stanley de J. Osborne | 37 | Director | ||||
Kenneth A. Pontarelli | 37 | Director | ||||
Mark E. Tomkins | 52 | Director |
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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; | |
• | To provide competitive financial incentives in the form of salary, bonuses, and benefits with the goal of retaining and attracting talented and highly motivated executive officers; and | |
• | To maintain a compensation program whereby the executive officers, through exceptional performance and equity ownership, will have the opportunity to realize economic rewards commensurate with appropriate gains of other equity holders and stakeholders. |
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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. | |
• | Initial Public Offering. Mr. Lipinski supervised the initial filing of our registration statement with the Securities and Exchange Commission in September 2006 and the consummation of our initial public offering in October 2007. The initial public offering process required a large amount of time and attention due to the turnaround in the first quarter of 2007, the decision to move our nitrogen fertilizer operations into a limited partnership structure, and the flood which occurred during the weekend of June 30, 2007. We ultimately listed our shares of common stock on the New York Stock Exchange and sold 23 million shares in the offering at an initial price of $19.00 per share. | |
• | Business Expansion. Mr. Lipinski directed the Company’s growth strategy beginning in 2005, which included our refinery expansion project during 2006 and 2007 and the fertilizer plant UAN expansion project that commenced in 2007. Nearly every process unit at the refinery was involved in the refinery expansion project, which was consummated in the fourth quarter of |
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2007. Our refinery throughput rates, averaging less than 90,000 bpd prior to June 2005, averaged over 110,000 bpd of crude during the fourth quarter of 2007, a record rate for our refinery. In addition, the blend of crudes was optimized to accommodate larger volumes of heavy sour crude. We processed more than 21,000 bpd of heavy sour crude in the fourth quarter of 2007, as compared with 2,700 bpd of heavy sour crude in the first quarter of 2006. Part of this project also included the addition of a new 24,000 bpd continuous catalytic reforming (“CCR”) unit which replaced an older technology unit two-thirds its size. The new CCR increased reforming capacity and also over time will produce more hydrogen, which over time will reduce our refinery’s dependence on the nitrogen fertilizer business for hydrogen purchases. The fertilizer plant UAN expansion project is expected to enable the nitrogen fertilizer plant to consume substantially all of its net ammonia production in the production of UAN, historically a higher margin product than ammonia. We estimate that it will result in an approximately 50% increase in the fertilizer plant’s annual UAN production. |
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Non-Equity | ||||||||||||||||||||||||||||
Stock | Incentive Plan | All Other | ||||||||||||||||||||||||||
Name and Principal Position | Year | Salary | Bonus(1) | Awards(3) | Compensation(1)(4) | Compensation(5) | Total | |||||||||||||||||||||
John J. Lipinski | 2007 | $ | 650,000 | $ | 1,850,000 | — | — | $ | 12,189,955 | (6) | $ | 14,689,955 | ||||||||||||||||
Chief Executive Officer | 2006 | $ | 650,000 | $ | 1,331,790 | $ | 4,326,188 | $ | 487,500 | $ | 5,007,935 | (7) | $ | 11,803,413 | ||||||||||||||
James T. Rens | 2007 | $ | 250,000 | $ | 400,000 | — | — | $ | 2,761,144 | (8) | $ | 3,411,144 | ||||||||||||||||
Chief Financial Officer | 2006 | $ | 250,000 | $ | 205,000 | — | $ | 130,000 | $ | 695,316 | (9) | $ | 1,280,316 | |||||||||||||||
Stanley A. Riemann | 2007 | $ | 350,000 | $ | 722,917 | (2) | — | — | $ | 4,911,011 | (10) | $ | 5,983,928 | |||||||||||||||
Chief Operating Officer | 2006 | $ | 350,000 | $ | 772,917 | (2) | — | $ | 210,000 | $ | 943,789 | (11) | $ | 2,276,706 | ||||||||||||||
Robert W. Haugen | 2007 | $ | 275,000 | $ | 230,000 | — | — | $ | 2,822,978 | (12) | $ | 3,327,978 | ||||||||||||||||
Executive Vice President, | 2006 | $ | 225,000 | $ | 205,000 | — | $ | 117,000 | $ | 695,471 | (13) | $ | 1,242,471 | |||||||||||||||
Refining Operations | ||||||||||||||||||||||||||||
Daniel J. Daly, Jr. | 2007 | $ | 215,000 | $ | 200,000 | — | — | $ | 2,355,059 | (14) | $ | 2,770,059 | ||||||||||||||||
Executive Vice President, | 2006 | $ | 185,000 | $ | 175,000 | — | $ | 96,200 | $ | 714,705 | (15) | $ | 1,170,905 | |||||||||||||||
Strategy |
(1) | Bonuses are reported for the year in which they were earned, though they may have been paid the following year. | |
(2) | Includes a retention bonus in the amount of $122,917. | |
(3) | Reflects the amount recognized for financial statement reporting purposes for the fiscal years ended December 31, 2006 and December 31, 2007 with respect to shares of common stock of each of Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc. granted to Mr. Lipinski effective December 28, 2006. In connection with the formation of Coffeyville Refining & Marketing Holdings, Inc. in August 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. In connection with our initial public offering in October 2007, Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. were exchanged by Mr. Lipinski for 247,471 shares of our common stock. | |
(4) | Reflects cash awards to the named individuals in respect of 2006 performance pursuant to our Variable Compensation Plan. Beginning in 2007, our executive officers no longer participated in this plan. | |
(5) | The amounts shown represent grants of profits interests in Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and grants of phantom points in Phantom Unit Plan I and Phantom Unit Plan II and reflect the dollar amounts recognized for financial statement reporting purposes for the years ended December 31, 2006 and December 31, 2007 in accordance with SFAS 123(R). For the 2006 amounts, assumptions used in the calculation are included in footnote 5 to our audited financial statements for the year ended December 31, 2006 included in the Company’s registration statement onForm S-1/A filed on October 16, 2007. For |
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the 2007 amounts, assumptions used in the calculation are included in footnote 3 to our audited financial statements for the year ended December 31, 2007 included elsewhere in this prospectus. The profits interests in Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC and the phantom points in Phantom Unit Plan I and Phantom Unit Plan II are more fully described below under “— Executive Officers’ Interests in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC”, “— Executive Officers’ Interests in Coffeyville Acquisition III LLC”, and “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. | ||
(6) | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC that were granted in 2005 in the amount of $8,057,632, (e) profits interests in Coffeyville Acquisition LLC that were granted on December 29, 2006 in the amount of $1,595,428, (f) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $1,080 and (g) phantom points granted during the period ending December 31, 2006 in the amount of $2,519,640. | |
(7) | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) forgiveness of a note that Mr. Lipinski owed to Coffeyville Acquisition LLC in the amount of $350,000, (d) forgiveness of accrued interest related to the forgiven note in the amount of $17,989, (e) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $630,059, (f) a cash payment in respect of taxes payable on his December 28, 2006 grant of subsidiary stock in the amount of $2,481,346, (g) profits interests in Coffeyville Acquisition LLC that were granted on December 29, 2006 in the amount of $20,510 and (h) phantom points granted during the period ending December 31, 2006 in the amount of $1,495,211. | |
(8) | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program, (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,836,087, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $201 and (f) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $911,768. | |
(9) | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $279,670 and (d) phantom points granted to Mr. Rens during the period ending December 31, 2006 in the amount of $651,299. | |
(10) | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) the premiums paid for by us on behalf of the executive officer with respect to our basic life insurance program (d) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $3,576,617, (e) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $393, (f) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $1,097,527 and (g) a relocation bonus of $222,099. | |
(11) | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and (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. | |
(13) | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $143,571 and (d) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $541,061. | |
(14) | Includes (a) a company contribution under our 401(k) plan in 2007, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2007, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $1,324,168, (d) profits interests in Coffeyville Acquisition III LLC that were granted in October 2007 in the amount of $144 and (e) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $1,016,972. | |
(15) | Includes (a) a company contribution under our 401(k) plan in 2006, (b) the premiums paid by us on behalf of the executive officer with respect to our executive life insurance program in 2006, (c) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $103,543 and (d) phantom points granted to Mr. Daly during the period ending December 31, 2006 in the amount of $603,491. |
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• | 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). |
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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 |
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(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. |
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(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. |
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(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. |
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”. |
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(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. |
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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 |
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 | ||||||||
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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 |
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more fully described below under “— Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) and Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II)”. |
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• | 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; | |
• | all of our executive officers and directors as a group; and | |
• | all selling stockholders. |
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 | % |
† | Coffeyville Acquisition LLC 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, would own 51,645,691 shares, or 60.0%, of our common stock. | |
* | Less than 1%. |
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(1) | Coffeyville Acquisition LLC directly owns 31,433,360 shares of common stock. Kelso Investment Associates VII, L.P. (“KIA VII”), a Delaware limited partnership, owns a number of common units in Coffeyville Acquisition LLC that corresponds to 24,557,883 shares of common stock, and KEP Fertilizer, 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 dispose of the common stock of the Company owned by Coffeyville Acquisition LLC. KIA VII and KEP 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, Berney, Loverro, Connors, Osborne and Moore may be deemed to share beneficial ownership of shares of common stock owned of record or beneficially owned by KIA VII, KEP Fertilizer and Coffeyville Acquisition LLC by virtue of their status as managing members of KEP Fertilizer and of Kelso GP VII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of Kelso GP VII, L.P., a Delaware limited partnership, the principal business of which is serving as the general partner of KIA VII. Each of Messrs. Nickell, Wall, Matelich, Goldberg, Bynum, Wahrhaftig, Berney, Loverro, Connors, Osborne and Moore share investment and voting power with respect to the ownership interests owned by KIA VII, KEP Fertilizer and Coffeyville Acquisition LLC but disclaim beneficial ownership of such interests. | |
(2) | Coffeyville Acquisition II LLC directly owns 31,433,360 shares of common stock. GS Capital Partners V Fund, L.P., GS Capital Partners V Offshore Fund, L.P., GS Capital Partners V GmbH & Co. KG and GS Capital Partners V Institutional, L.P. (collectively, the “Goldman Sachs Funds”) are members of Coffeyville Acquisition II LLC and own common units of Coffeyville Acquisition II LLC. The Goldman Sachs Funds’ common units in Coffeyville Acquisition II LLC correspond to 31,125,918 shares of common stock. The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. may be deemed to beneficially own indirectly, in the aggregate, all of the common stock owned by Coffeyville Acquisition II LLC through the Goldman Sachs Funds because (i) affiliates of Goldman, Sachs & Co. and The Goldman Sachs Group, Inc. are the general partner, managing general partner, managing partner, managing member or member of the Goldman Sachs Funds and (ii) the Goldman Sachs Funds control Coffeyville Acquisition II LLC and have the power to vote or dispose of the common stock of the Company owned by Coffeyville Acquisition II LLC. Goldman, Sachs & Co. is a direct and indirect wholly owned subsidiary of The Goldman Sachs Group, Inc. Goldman, Sachs & Co. is the investment manager of certain of the Goldman Sachs Funds. Shares that may be deemed to be beneficially owned by the Goldman Sachs Funds consist of: (1) 16,389,665 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Fund, L.P. and its general partner, GSCP V Advisors, L.L.C., (2) 8,466,218 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Offshore Fund, L.P. and its general partner, GSCP V Offshore Advisors, L.L.C., (3) 5,620,242 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V Institutional, L.P. and its general partner, GSCP V Advisors, L.L.C., and (4) 649,793 shares of common stock that may be deemed to be beneficially owned by GS Capital Partners V GmbH & Co. KG and its general partner, Goldman, Sachs Management GP GmbH. Kenneth A. Pontarelli is a partner managing director of Goldman, Sachs & Co. and Scott L. Lebovitz is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, Mr. Lebovitz, The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. each disclaims beneficial ownership of the shares of common stock owned directly or indirectly by the Goldman Sachs Funds, except to the extent of their pecuniary interest therein, if any. | |
(3) | Mr. Lipinski owns 247,471 shares of common stock directly. In addition, Mr. Lipinski owns 158,285 shares indirectly through his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Mr. Lipinski does not have the power to vote or dispose of shares that correspond to his ownership of common units in Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and thus does not have beneficial ownership of such shares. Mr. Lipinski also owns (i) profits interests in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, (ii) phantom points under each of the Phantom Unit Plans and (iii) common units and override units in Coffeyville Acquisition III LLC. See “Compensation Discussion and Analysis — Outstanding Equity Awards at 2007 Fiscal Year-End” and “Compensation Discussion and Analysis — Equity Awards at 2007 Fiscal Year-End That Have Vested”. Such interests do not give Mr. Lipinski beneficial ownership of any |
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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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Coffeyville Acquisition II
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 |
Named Executive Officers as a result of this Offering by Coffeyville
Acquisition and Coffeyville Acquisition II
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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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 | % |
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Number of | Amount of | |||||||
Common | Promissory | |||||||
Executive Officer | Units | Note | ||||||
Philip L. Rinaldi | 3,717,647 | $ | 21,000 | |||||
Abraham H. Kaplan | 2,230,589 | $ | 12,600 | |||||
George W. Dorsey | 2,230,589 | $ | 12,600 | |||||
Stanley A. Riemann | 1,301,176 | $ | 7,350 | |||||
James T. Rens | 371,764 | $ | 2,100 | |||||
Keith D. Osborn | 650,588 | $ | 3,675 | |||||
Kevan A. Vick | 650,588 | $ | 3,675 |
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Executive Officer | Bonus Amount | |||
Philip L. Rinaldi | $ | 1,000,000 | ||
Abraham H. Kaplan | $ | 600,000 | ||
George W. Dorsey | $ | 300,000 | ||
Stanley A. Riemann | $ | 700,000 | ||
James T. Rens | $ | 150,000 | ||
Keith D. Osborn | $ | 150,000 | ||
Kevan A. Vick | $ | 150,000 | ||
Edmund S. Gross | $ | 200,000 |
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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 |
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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 |
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• | appointment rights and consent rights for the termination of employment and compensation of the chief executive officer and chief financial officer of the managing general partner, not to be exercised unreasonably (our approval for appointment of an officer is deemed given if the officer is an executive officer of CVR Energy); | |
• | the right to appoint two directors to the board of directors of the managing general partner and one such director to any committee thereof (subject to certain exceptions); | |
• | consent rights over any merger by the Partnership into another entity where: |
• | for so long as we own 50% or more of all units of the Partnership immediately prior to the merger, less than 60% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; | |
• | for so long as we own 25% or more of all units of the Partnership immediately prior to the merger, less than 50% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; and | |
• | for so long as we own more than 15% of all of the units of the Partnership immediately prior to the merger, less than 40% of the equity interests of the resulting entity are owned by the pre-merger unitholders of the Partnership; |
• | consent rights over any purchase or sale, exchange or other transfer of assets or entities with a purchase/sale price equal to 50% or more of the Partnership’s asset value; and | |
• | consent rights over any incurrence of indebtedness or issuance of Partnership interests with rights to distribution or in liquidation ranking prior or senior to the common units, in either case in excess of $125 million ($200 million in the case of the Partnership’s initial public or private offering, exclusive of the underwriters’ option, if any), increased by 80% of the purchase price for assets or entities whose purchase was approved by us as described in the immediately preceding bullet point. |
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• | less the amount of cash reserves established by the managing general partner to: |
• | provide for the proper conduct of the Partnership’s business (including the satisfaction of obligations in respect of pre-paid fertilizer contracts, future capital expenditures, anticipated future credit needs and the payment of expenses and fees, including payments to the managing general partner); | |
• | comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other agreement or obligation to which the Partnership or any of its subsidiaries is a party or by which the Partnership is bound or its assets are subject; and | |
• | provide funds for distributions in respect of any one or more of the next eight quarters, provided, however, that following an initial public offering of the Partnership, the managing general partner may not establish cash reserves pursuant to this clause if the effect of such reserves would be that the Partnership would be unable to distribute the minimum quarterly distribution on all common units and any cumulative common unit arrearages thereon with respect to any such quarter; |
• | plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are used solely for working capital purposes or to make distributions to partners. |
• | $60 million (as described below); plus | |
• | all of the Partnership’s cash receipts after formation (reset to the date of the Partnership’s initial offering if an initial offering occurs), excluding cash from “interim capital transactions” (as described below); plus | |
• | working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; plus | |
• | 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 | |
• | all of the Partnership’s “operating expenditures” (as defined below) after formation (reset to the date of closing of the Partnership’s initial offering if an initial offering occurs); less | |
• | the amount of cash reserves established by the managing general partner to provide funds for future operating expenditures (which does not include expansion capital expenditures). |
• | repayments of working capital borrowings, if such working capital borrowings were outstanding for twelve months, not repaid, but deemed repaid, thus decreasing operating surplus at such time; | |
• | payments (including prepayments) of principal of and premium on indebtedness, other than working capital borrowings; | |
• | expansion capital expenditures; | |
• | investment capital expenditures; | |
• | payment of transaction expenses relating to “interim capital transactions”; or | |
• | distributions to partners. |
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• | borrowings other than working capital borrowings; | |
• | sales of debt securities and equity interests; and | |
• | sales or other dispositions of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of the normal retirement or replacement of assets. |
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Total Quarterly | ||||||||||
Distribution — Target | Managing General | |||||||||
Amount | Special Units | Partner | ||||||||
Minimum Quarterly Distribution | $0.375 | 100 | % | 0 | % | |||||
First Target Distribution | Up to $0.4313 | 100 | % | 0 | % | |||||
Second Target Distribution | Above $0.4313 | 87 | % | 13 | % | |||||
and up to $0.4688 | ||||||||||
Third Target Distribution | Above $0.4688 | 77 | % | 23 | % | |||||
and up to $0.5625 | ||||||||||
Thereafter | Above $0.5625 | 52 | % | 48 | % |
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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 | |
• | any net increase in working capital borrowings with respect to that period; less | |
• | any net reduction in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus | |
• | any net decrease in working capital borrowings with respect to that period; plus | |
• | any net increase in cash reserves for operating expenditures with respect to that period to the extent required by any debt instrument for the repayment of principal, interest or premium. |
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• | Issuance of Additional Units: no approval right. | |
• | Amendment of the Partnership Agreement: certain amendments may be made by the managing general partner without the approval of the unitholders. Other amendments generally require the approval of a unit majority. | |
• | Merger of the Partnership or the Sale of all or Substantially all of the Partnership’s Assets: unit majority in certain circumstances. In addition, the holder of special GP rights has joint management rights with respect to some mergers. | |
• | Dissolution of the Partnership: unit majority. | |
• | Continuation of the Partnership upon Dissolution: unit majority. | |
• | Withdrawal of the Managing General Partner: under most circumstances, a unit majority is required for the withdrawal of the managing general partner prior to June 30, 2017 in a manner which would cause a dissolution of the Partnership. | |
• | Removal of the Managing General Partner: not less than 80% of the outstanding units, voting as a single class, including units held by the managing general partner and its affiliates (i) for cause prior to October 26, 2012 or (ii) with or without cause (as defined in the partnership agreement) on or after October 26, 2012. | |
• | Transfer of the Managing General Partner’s General Partner Interest: the managing general partner may transfer all, but not less than all, of its managing general partner interest |
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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. |
• | Transfer of Ownership Interests in the Managing General Partner: no approval required at any time. |
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• | approved by Fertilizer GP’s conflicts committee, although Fertilizer GP is not obligated to seek such approval; | |
• | approved by the vote of a majority of the outstanding common units, excluding any common units owned by Fertilizer GP and its affiliates (including us so long as we remain an affiliate); | |
• | on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or | |
• | 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. |
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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. |
• | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unit holders must be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to the Partnership, as determined by Fertilizer GP in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable”, Fertilizer GP may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership. | |
• | The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership or its partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct. |
• | amount and timing of asset purchases and sales; | |
• | cash expenditures; | |
• | borrowings; | |
• | issuance of additional units; and | |
• | the creation, reduction, or increase of reserves in any quarter. |
• | on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties; or | |
• | “fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). |
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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; | |
• | the making of tax, regulatory and other filings, or rendering of periodic or other reports to governmental or other agencies having jurisdiction over the Partnership’s business or assets; | |
• | the acquisition, disposition, mortgage, pledge, encumbrance, hypothecation or exchange of any or all of the Partnership’s assets or the merger or other combination of the Partnership with or into another person; | |
• | the negotiation, execution and performance of any contracts, conveyances or other instruments; | |
• | the distribution of Partnership cash; | |
• | the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; | |
• | the maintenance of insurance for the Partnership’s benefit and the benefit of its partners; | |
• | the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships; | |
• | the control of any matters affecting the Partnership’s rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; | |
• | the indemnification of any person against liabilities and contingencies to the extent permitted by law; | |
• | the purchase, sale or other acquisition or disposition of Partnership interests, or the issuance of additional options, rights, warrants and appreciation rights relating to Partnership interests; and |
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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. |
• | State law fiduciary duty standards are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where the general partner has a conflict of interest. | |
• | The partnership agreement contains provisions that waive or consent to conduct by the Partnership’s general partners and their affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, the partnership agreement provides that when either of the general partners is acting in its capacity as a general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when either of the general partners is acting in its individual capacity, as opposed to in its capacity as a general partner, it may act without any fiduciary obligation to the Partnership or the unit holders whatsoever. These standards reduce the obligations to which the Partnership’s general partners would otherwise be held. | |
• | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unit holders and that are not approved by the conflicts committee of the board of directors of the Partnership’s managing general partner |
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must be (1) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). |
• | If the Partnership’s managing general partner does not seek approval from the conflicts committee or the common unit holders and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet point above, then it will be presumed that, in making its decision, the board of directors of the managing general partner, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which the Partnership’s managing general partner would otherwise be held. | |
• | In addition to the other more specific provisions limiting the obligations of the Partnership’s general partners, the partnership agreement further provides that the Partnership’s general partners and their officers and directors will not be liable for monetary damages to the Partnership or its partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct. |
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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; | |
• | engaging in any refinery restricted business subject to the offer to us described in the immediately preceding bullet point pending our determination whether to accept such offer and pending the closing of any offers we accept; | |
• | engaging in any refinery restricted business if we have previously advised the Partnership that our board of directors has elected not to cause us to acquire or seek to acquire such business; or | |
• | acquiring up to 9.9% of any class of securities of any publicly traded company that engages in any refinery restricted business. |
• | any fertilizer restricted business acquired as part of a business or package of assets if a majority of the value of the total assets or business acquired is not attributable to a fertilizer restricted business, as determined in good faith by our board of directors, as applicable; however, if at any time we complete such an acquisition, we must, within 365 days of the closing of the transaction, offer to sell the fertilizer-related assets to the Partnership for their fair market value plus any additional tax or other similar costs that would be required to transfer the fertilizer-related assets to the Partnership separately from the acquired business or package of assets; | |
• | engaging in any fertilizer restricted business subject to the offer to the Partnership described in the immediately preceding bullet point pending the Partnership’s determination whether to accept such offer and pending the closing of any offers the Partnership accepts; | |
• | engaging in any fertilizer restricted business if the Partnership has previously advised us that it has elected not to acquire such business; or |
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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. |
• | services by our employees as the Partnership’s corporate executive officers, including chief executive officer, chief operating officer, chief financial officer, general counsel, fertilizer general manager, and vice president for environmental, health and safety, except that those who serve in such capacities under the agreement serve the Partnership on a shared, part-time basis only, unless we and the Partnership agree otherwise; | |
• | administrative and professional services, including legal, accounting services, human resources, insurance, tax, credit, finance, government affairs and regulatory affairs; | |
• | management of the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; | |
• | recommendations on capital raising activities, including the issuance of debt or equity securities, the entry into credit facilities and other capital market transactions; | |
• | managing or overseeing litigation and administrative or regulatory proceedings, and establishing appropriate insurance policies for the Partnership, and providing safety and environmental advice; | |
• | recommending the payment of distributions; and | |
• | managing or providing advice for other projects as may be agreed by us and the managing general partner of the Partnership from time to time. |
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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; | |
• | 100% of the cash proceeds from the incurrence of specified debt obligations by Holdings or any of its subsidiaries; and | |
• | 75% of “consolidated excess cash flow” less 100% of voluntary prepayments made during the fiscal year; provided that this percentage will be reduced to 50% if the total leverage ratio at the end of such fiscal year is less than 1.50:1.00 and 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00; |
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Minimum Interest | Maximum | |||||
Fiscal Quarter Ending | Coverage Ratio | Leverage Ratio | ||||
June 30, 2008 | 3.25:1.00 | 3.00:1.00 | ||||
September 30, 2008 | 3.25:1.00 | 2.75:1.00 | ||||
December 31, 2008 | 3.25:1.00 | 2.50:1.00 | ||||
March 31, 2009 and thereafter | 3.75:1.00 | 2.25:1.00 to December 31, 2009, 2.00:1.00 thereafter |
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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%. | |
• | $25.0 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25.0 million senior unsecured term loan (the “$25.0 million unsecured facility”). Interest was payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. | |
• | $75.0 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75.0 million senior unsecured term loan (the “$75.0 million unsecured facility”). Drawings could be made from time to time in amounts of at least $5.0 million. Interest accrued, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest was paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrued by adding such fees to the principal amount of loans outstanding. No amounts were drawn under this facility. |
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• | crude oil for each quarter equals the average of the closing settlement price(s) on NYMEX for the Nearby Light Crude Futures Contract that is “first nearby” as of any determination date during that calendar quarter quoted in U.S. dollars per barrel; | |
• | unleaded gasoline for each quarter equals the average of the closing settlement prices on NYMEX for the Unleaded Gasoline Futures Contract that is “first nearby” for any determination period to and including the determination period ending December 31, 2006 and the average of the closing settlement prices on NYMEX for Reformulated Gasoline Blendstock for Oxygen Blending Futures Contract that is “first nearby” for each determination period thereafter quoted in U.S. dollars per gallon; and | |
• | heating oil for each quarter equals the average of the closing settlement prices on NYMEX for the Heating Oil Futures Contract that is “first nearby” as of any determination date during such calendar quarter quoted in U.S. dollars per gallon. |
• | guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; | |
• | secured by a $150.0 million funded letter of credit issued under the Credit Facility in favor of J. Aron; and | |
• | to the extent J. Aron’s exposure under the derivative transaction exceeds $150.0 million, secured by the same collateral that secures our Credit Facility. |
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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 Credit Facility; | |
• | Coffeyville Resources, LLC’s obligations under the derivative transaction cease to be guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; or | |
• | Coffeyville Resources, LLC fails to maintain a $150.0 million funded letter of credit in favor of J. Aron. |
• | On June 26, 2007, Coffeyville Resources, LLC and J. Aron & Company entered into a letter agreement in which J. Aron deferred to August 7, 2007 a $45.0 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. We agreed to pay interest on the deferred amount at the rate of LIBOR plus 3.25%. | |
• | On July 11, 2007, Coffeyville Resources, LLC and J. Aron entered into a letter agreement in which J. Aron deferred to July 25, 2007 a separate $43.7 million payment which we owed to J. Aron under the Cash Flow Swap for the period ending June 30, 2007. J. Aron deferred the $43.7 million payment on the conditions that (a) each of GS Capital Partners V Fund, L.P. and Kelso Investment Associates VII, L.P. agreed to guarantee one half of the payment and |
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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%. |
• | 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%. | |
• | 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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• | restricting dividends on the common stock; | |
• | diluting the voting power of the common stock; | |
• | impairing the liquidation rights of the common stock; or | |
• | delaying or preventing a change in control without further action by the stockholders. |
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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 | |
• | the average weekly trading volume of the common stock during the four calendar weeks preceding the sale. |
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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; | |
• | a corporation created or organized in or under the laws of the United States, any state thereof or the District of Columbia; | |
• | a partnership; | |
• | an estate whose income is includible in gross income for U.S. federal income tax purposes regardless of its source; or | |
• | a trust, if (1) a United States court is able to exercise primary supervision over the trust’s administration and one or more “United States persons” (within the meaning of the U.S. Internal Revenue Code of 1986, as amended, or the Code) has the authority to control all of the trust’s substantial decisions, or (2) the trust has a valid election in effect under applicable U.S. Treasury regulations to be treated as a “United States person”. |
• | 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; | |
• | non-U.S. holders holding our common stock as part of a conversion, constructive sale, wash sale or other integrated transaction or a hedge, straddle or synthetic security; | |
• | any U.S. state and local ornon-U.S. or other tax consequences; and | |
• | the U.S. federal income or estate tax consequences for the beneficial owners of anon-U.S. holder. |
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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; | |
• | 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. |
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• | is a United States person; | |
• | derives 50% or more of its gross income in specific periods from the conduct of a trade or business in the United States; | |
• | is a “controlled foreign corporation” for U.S. federal income tax purposes; or | |
• | is a foreign partnership, if at any time during its tax year: |
• | one or more of its partners are United States persons who in the aggregate hold more than 50% of the income or capital interests in the partnership; or |
• | the foreign partnership is engaged in a U.S. trade or business, |
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Underwriters | Number of Shares | |||
Goldman, Sachs & Co. | ||||
Deutsche Bank Securities Inc. | ||||
Citigroup Global Markets Inc. | ||||
Credit Suisse Securities (USA) LLC | ||||
Total | 10,000,000 | |||
No Exercise | Full Exercise | |||||||
Per Share | $ | $ | ||||||
Total | $ | $ |
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2-1-1 crack spread | The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of heating oil. | |
Barrel | Common unit of measure in the oil industry which equates to 42 gallons. | |
Blendstocks | Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others. | |
bpd | Abbreviation for barrels per day. | |
Btu | British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit. | |
Bulk sales | Volume sales through third party pipelines, in contrast to tanker truck quantity sales. | |
By-products | Products that result from extracting high value products such as gasoline and diesel fuel from crude oil; these include black oil, sulfur, propane, pet coke and other products. | |
Capacity | Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints. | |
Catalyst | A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process. | |
Coker unit | A refinery unit that utilizes the lowest value component of crude oil remaining after all higher value products are removed, further breaks down the component into more valuable products and converts the rest into pet coke. | |
Common units | The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which provide for voting rights and have rights with respect to profits and losses of, and distributions from, the respective limited liability companies. | |
Corn belt | The primary corn producing region of the United States, which includes Illinois, Indiana, Iowa, Minnesota, Missouri, Nebraska, Ohio and Wisconsin. | |
Crack spread | A simplified calculation that measures the difference between the price for light products and crude oil. For example, 2-1-1 crack spread is often referenced and represents the approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel. | |
Crude slate | The mix of different crude types (qualities) being charged to a crude unit. |
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Crude slate optimization | The process of determining the most economic crude oils to be refined based upon the prevailing product values, crude prices, crude oil yields and refinery process unit operating unit constraints to maximize profit. | |
Crude unit | The initial refinery unit to process crude oil by separating the crude oil according to boiling point under high heat to recover various hydrocarbon fractions. | |
Distillates | Primarily diesel fuel, kerosene and jet fuel. | |
Ethanol | A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate. | |
Farm belt | Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. | |
Feedstocks | Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. | |
Fluid catalytic cracking unit | Converts gas oil from the crude unit or coker unit into liquefied petroleum gas, distillates and gasoline blendstocks by applying heat in the presence of a catalyst. | |
Fluxant | Material added to coke to aid in the removal of coke metal impurities from the gasifier. The material consists of a mixture of fly ash and sand. | |
Heavy crude oil | A relatively inexpensive crude oil characterized by high relative density and viscosity. Heavy crude oils require greater levels of processing to produce high value products such as gasoline and diesel fuel. | |
Independent refiner | A refiner that does not have crude oil exploration or production operations. An independent refiner purchases the crude oil used as feedstock in its refinery operations from third parties. | |
Jobber | A person or company that purchases quantities of refined fuel from refining companies, either for sale to retailers or to sell directly to the users of those products. | |
Light crude oil | A relatively expensive crude oil characterized by low relative density and viscosity. Light crude oils require lower levels of processing to produce high value products such as gasoline and diesel fuel. | |
Liquefied petroleum gas | Light hydrocarbon material gaseous at atmospheric temperature and pressure, held in the liquid state by pressure to facilitate storage, transport and handling. | |
Magellan Midstream Partners L.P. | A publicly traded company whose business is the transportation, storage and distribution of refined petroleum products. | |
Maya | A heavy, sour crude oil from Mexico characterized by an API gravity of approximately 22.0 and a sulfur content of approximately 3.3 weight percent. | |
Midcontinent | Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and Iowa. |
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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. | |
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. | |
Naphtha | The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane. | |
Netbacks | Refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excludes shipment costs. Also referred to as plant gate price. | |
Operating units | Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on service. | |
Override units | The class of interests issued or to be issued under the limited liability company agreements governing Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, which represent profits interests in the respective limited liability companies. With respect to the override units issued under the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, the units are classified as either operating units or value units. | |
PADD I | East Coast Petroleum Area for Defense District which includes Connecticut, Delaware, District of Columbia, Florida, Georgia, Maine, Massachusetts, Maryland, New Hampshire, New Jersey, New York, North Carolina, Pennsylvania, Rhode Island, South Carolina, Vermont, Virginia and West Virginia. | |
PADD II | Midwest Petroleum Area for Defense District which includes Illinois, Indiana, Iowa, Kansas, Kentucky, Michigan, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Tennessee, and Wisconsin. | |
PADD III | Gulf Coast Petroleum Area for Defense District which includes Alabama, Arkansas, Louisiana, Mississippi, New Mexico, and Texas. | |
PADD IV | Rocky Mountains Petroleum Area for Defense District which includes Colorado, Idaho, Montana, Utah, and Wyoming. | |
PADD V | West Coast Petroleum Area for Defense District which includes Alaska, Arizona, California, Hawaii, Nevada, Oregon, and Washington. | |
Pet coke | A coal-like substance that is produced during the refining process. | |
Phantom performance points | Phantom points granted or to be granted pursuant to the Phantom Unit Plan I and Phantom Unit Plan II, which vest based on performance of the investment made by Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, respectively. |
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Phantom points | The class of interests to be issued under the Phantom Unit Plan I, and to be issued under the Phantom Unit Plan II, which represent or will represent the opportunity to receive a cash payment when distributions of profit are made pursuant to the limited liability company agreements of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Phantom points are classified as either phantom service points or phantom performance points. | |
Phantom service points | Phantom points granted or to be granted pursuant to the Phantom Unit Plan I and Phantom Unit Plan II, which vest based on service. | |
Phantom Unit Plan I | The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition LLC. | |
Phantom Unit Plan II | The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), which relates to distributions made by Coffeyville Acquisition II LLC. | |
Profits interests | Interests in the profits of Coffeyville Acquisition LLC, Coffeyville Acquisition II LLC and Coffeyville Acquisition III LLC, also referred to as “override units.” | |
Rack sales | Sales which are made into tanker truck (versus bulk pipeline batcher) via either a proprietary or third terminal facility designed for truck loading. | |
Recordable incident | An injury, as defined by OSHA. All work-related deaths and illnesses, and those work-related injuries which result in loss of consciousness, restriction of work or motion, transfer to another job, or require medical treatment beyond first aid. | |
Recordable injury rate | The number of recordable injuries per 200,000 hours rate worked. | |
Refined products | Petroleum products, such as gasoline, diesel fuel and jet fuel, that are produced by a refinery. | |
Refining margin | A measurement calculated as the difference between net sales and cost of products sold (exclusive of depreciation and amortization). | |
Reformer unit | A refinery unit that processes naphtha and converts it to high-octane gasoline by using a platinum/rhenium catalyst. Also known as a platformer. | |
Reformulated gasoline | Gasoline with compounds or properties which meet the requirements of the reformulated gasoline regulations. | |
Slag | A glasslike substance removed from the gasifier containing the metal impurities originally present in the coke. | |
Slurry | A byproduct of the fluid catalytic cracking process that is sold for further processing or blending with fuel oil. | |
Sour crude oil | A crude oil that is relatively high in sulfur content, requiring additional processing to remove the sulfur. Sour crude oil is typically less expensive than sweet crude oil. | |
Spot market | A market in which commodities are bought and sold for cash and delivered immediately. | |
Sweet crude oil | A crude oil that is relatively low in sulfur content, requiring less processing to remove the sulfur. Sweet crude oil is typically more expensive than sour crude oil. |
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Syngas | A mixture of gases (largely carbon monoxide and hydrogen) that results from heating coal in the presence of steam. | |
Throughput | The volume processed through a unit or a refinery. | |
Ton | One ton is equal to 2,000 pounds. | |
Turnaround | A periodically required standard procedure to refurbish and maintain a refinery that involves the shutdown and inspection of major processing units and occurs every three to four years. | |
UAN | UAN is a solution of urea and ammonium nitrate in water used as a fertilizer. | |
Utilization | Ratio of total refinery throughput to the rated capacity of the refinery. | |
Vacuum unit | Secondary refinery unit to process crude oil by separating product from the crude unit according to boiling point under high heat and low pressure to recover various hydrocarbons. | |
Value units | Override units granted pursuant to the limited liability company agreements governing Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC, which vest based on performance of the investment made by Coffeyville Acquisition LLC or Coffeyville Acquisition II LLC, respectively. | |
Wheat belt | The primary wheat producing region of the United States, which includes Oklahoma, Kansas, North Dakota, South Dakota and Texas. | |
WTI | West Texas Intermediate crude oil, a light, sweet crude oil, characterized by an API gravity between 39 and 41 and a sulfur content of approximately 0.4 weight percent that is used as a benchmark for other crude oils. | |
WTS | West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of 30-32 degrees and a sulfur content of approximately 2.0 weight percent. | |
Yield | The percentage of refined products that is produced from crude and other feedstocks. |
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Audited Consolidated Financial Statements: | ||||
Report of Independent Registered Public Accounting Firm | F-2 | |||
Consolidated Balance Sheets as of December 31, 2006 and December 31, 2007 | F-3 | |||
Consolidated Statements of Operations for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007 | F-4 | |||
Consolidated Statements of Changes in Stockholders’ Equity/Members’ Equity for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007 | F-5 | |||
Consolidated Statements of Cash Flows for the174-day period ended June 23, 2005, for the233-day period ended December 31, 2005, and for the years ended December 31, 2006 and December 31, 2007 | F-9 | |||
Notes to Consolidated Financial Statements | F-10 | |||
Unaudited Condensed Consolidated Financial Statements: | ||||
Condensed Consolidated Balance Sheets as of March 31, 2008 and December 31, 2007 (unaudited) | F-65 | |||
Condensed Consolidated Statements of Operations for the three months ended March 31, 2008 (unaudited) and the three months ended March 31, 2007 (unaudited) | F-66 | |||
Condensed Consolidated Statements of Cash Flows for the three months ended March 31, 2008 (unaudited) and the three months ended March 31, 2007 (unaudited) | F-67 | |||
Notes to Condensed Consolidated Financial Statements (unaudited) | F-68 |
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CVR Energy, Inc.:
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December 31, | December 31, | |||||||
2006 | 2007 | |||||||
(In thousands of dollars) | ||||||||
As restated(†) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 41,919 | $ | 30,509 | ||||
Accounts receivable, net of allowance for doubtful accounts of $375 and $391, respectively | 69,589 | 86,546 | ||||||
Inventories | 161,433 | 254,655 | ||||||
Prepaid expenses and other current assets | 18,525 | 14,186 | ||||||
Insurance receivable | — | 73,860 | ||||||
Income tax receivable | 32,099 | 31,367 | ||||||
Deferred income taxes | 18,889 | 79,047 | ||||||
Total current assets | 342,454 | 570,170 | ||||||
Property, plant, and equipment, net of accumulated depreciation | 1,007,156 | 1,192,174 | ||||||
Intangible assets, net | 638 | 473 | ||||||
Goodwill | 83,775 | 83,775 | ||||||
Deferred financing costs, net | 9,128 | 7,515 | ||||||
Insurance receivable | — | 11,400 | ||||||
Other long-term assets | 6,329 | 2,849 | ||||||
Total assets | $ | 1,449,480 | $ | 1,868,356 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 5,798 | $ | 4,874 | ||||
Note payable and capital lease obligations | — | 11,640 | ||||||
Payable to swap counterparty | 36,895 | 262,415 | ||||||
Accounts payable | 138,911 | 182,225 | ||||||
Personnel accruals | 24,731 | 36,659 | ||||||
Accrued taxes other than income taxes | 9,035 | 14,732 | ||||||
Deferred revenue | 8,812 | 13,161 | ||||||
Other current liabilities | 6,019 | 33,820 | ||||||
Total current liabilities | 230,201 | 559,526 | ||||||
Long-term liabilities: | ||||||||
Long-term debt, less current portion | 769,202 | 484,328 | ||||||
Accrued environmental liabilities | 5,395 | 4,844 | ||||||
Deferred income taxes | 284,123 | 286,986 | ||||||
Other long-term liabilities | — | 1,122 | ||||||
Payable to swap counterparty | 72,806 | 88,230 | ||||||
Total long-term liabilities | 1,131,526 | 865,510 | ||||||
Commitments and contingencies | ||||||||
Minority interest in subsidiaries | 4,326 | 10,600 | ||||||
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006 | 6,981 | — | ||||||
Stockholders’ equity/members’ equity | ||||||||
Voting common units, 22,614,937 units issued and outstanding in 2006 | 73,593 | — | ||||||
Management nonvoting override units, 2,976,353 units issued and outstanding in 2006 | 2,853 | — | ||||||
Common Stock $0.01 par value per share, 350,000,000 shares authorized; 86,141,291 shares issued and outstanding | — | 861 | ||||||
Additionalpaid-in-capital | — | 458,359 | ||||||
Retained deficit | — | (26,500 | ) | |||||
Total stockholders’ equity/members’ equity | 76,446 | 432,720 | ||||||
Total liabilities and stockholders’ equity/members’ equity | $ | 1,449,480 | $ | 1,868,356 | ||||
(†) | See Note 2 to consolidated financial statements. |
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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. |
F-4
Table of Contents
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 | ||||||||
F-5
Table of Contents
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. |
F-6
Table of Contents
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. |
F-7
Table of Contents
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. |
F-8
Table of Contents
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. |
F-9
Table of Contents
(1) | Organization and History of the Company |
F-10
Table of Contents
F-11
Table of Contents
• | 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
Table of Contents
• | a managing general partner interest, which is not entitled to any distributions, which is held by the Partnership’s managing general partner. |
• | 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. |
F-13
Table of Contents
F-14
Table of Contents
F-15
Table of Contents
Assets acquired | ||||
Cash | $ | 667,000 | ||
Accounts receivable | 37,329,000 | |||
Inventories | 156,171,000 | |||
Prepaid expenses and other current assets | 4,865,000 | |||
Intangibles, contractual agreements | 1,322,000 | |||
Goodwill | 83,775,000 | |||
Other long-term assets | 3,838,000 | |||
Property, plant, and equipment | 750,910,000 | |||
Total assets acquired | $ | 1,038,877,000 | ||
Liabilities assumed | ||||
Accounts payable | $ | 47,259,000 | ||
Other current liabilities | 16,017,000 | |||
Current income taxes | 5,076,000 | |||
Deferred income taxes | 276,889,000 | |||
Other long-term liabilities | 7,844,000 | |||
Total liabilities assumed | $ | 353,085,000 | ||
Cash paid for acquisition of Immediate Predecessor | $ | 685,792,000 | ||
(2) | Restatement of Financial Statements |
F-16
Table of Contents
F-17
Table of Contents
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
Table of Contents
December 31, 2007 | ||||||||||||
Previously | ||||||||||||
Reported | Adjustment | As Restated | ||||||||||
Net sales | $ | 2,966,865 | $ | — | $ | 2,966,865 | ||||||
Operating costs and expenses: | ||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 2,291,069 | 17,671 | 2,308,740 | |||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 276,138 | — | 276,138 | |||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 93,122 | — | 93,122 | |||||||||
Net costs associated with flood | 41,523 | — | 41,523 | |||||||||
Depreciation and amortization | 60,779 | — | 60,779 | |||||||||
Total operating costs and expenses | 2,762,631 | 17,671 | 2,780,302 | |||||||||
Operating income | 204,234 | (17,671 | ) | 186,563 | ||||||||
Other income (expense): | ||||||||||||
Interest expense and other financing costs | (61,126 | ) | — | (61,126 | ) | |||||||
Interest income | 1,100 | — | 1,100 | |||||||||
Gain (loss) on derivatives | (281,978 | ) | — | (281,978 | ) | |||||||
Loss on extinguishment of debt | (1,258 | ) | — | (1,258 | ) | |||||||
Other income (expense) | 356 | — | 356 | |||||||||
Total other income (expense) | (342,906 | ) | — | (342,906 | ) | |||||||
Income (loss) before income taxes and minority interest in subsidiaries | (138,672 | ) | (17,671 | ) | (156,343 | ) | ||||||
Income tax expense (benefit) | (81,639 | ) | (6,876 | ) | (88,515 | ) | ||||||
Minority interest in loss of subsidiaries | 210 | — | 210 | |||||||||
Net income (loss) | $ | (56,823 | ) | $ | (10,795 | ) | $ | (67,618 | ) | |||
Unaudited Pro Forma Information (Note 13) | ||||||||||||
Net earnings (loss) per share | ||||||||||||
Basic | $ | (0.66 | ) | $ | (0.12 | ) | $ | (0.78 | ) | |||
Diluted | $ | (0.66 | ) | $ | (0.12 | ) | $ | (0.78 | ) | |||
Weighted average common shares outstanding: | ||||||||||||
Basic | 86,141,291 | 86,141,291 | ||||||||||
Diluted | 86,141,291 | 86,141,291 |
(3) | Summary of Significant Accounting Policies |
F-19
Table of Contents
F-20
Table of Contents
Range of Useful | ||
Asset | Lives, in Years | |
Improvements to land | 15 to 20 | |
Buildings | 20 to 30 | |
Machinery and equipment | 5 to 30 | |
Automotive equipment | 5 | |
Furniture and fixtures | 3 to 7 |
F-21
Table of Contents
F-22
Table of Contents
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(4) | Members’ Equity and Share Based Compensation |
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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% |
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% |
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Forfeiture | ||||
Minimum Period Held | Percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
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% |
F-29
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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% |
Forfeiture | ||||
Minimum Period Held | Percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
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 | |||||
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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% |
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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 | ||||
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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 | — | — |
(5) | Inventories |
Successor | ||||||||
December 31, | December 31, | |||||||
2006 | 2007 | |||||||
As restated(†) | ||||||||
Finished goods | $ | 59,722 | $ | 109,394 | ||||
Raw materials and catalysts | 60,810 | 92,104 | ||||||
In-process inventories | 18,441 | 29,817 | ||||||
Parts and supplies | 22,460 | 23,340 | ||||||
$ | 161,433 | $ | 254,655 | |||||
(†) | See Note 2 to consolidated financial statements. |
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(6) | Property, Plant, and Equipment |
Successor | ||||||||
December 31, | December 31, | |||||||
2006 | 2007 | |||||||
Land and improvements | $ | 11,028 | $ | 13,058 | ||||
Buildings | 11,042 | 17,541 | ||||||
Machinery and equipment | 864,140 | 1,108,858 | ||||||
Automotive equipment | 4,175 | 5,171 | ||||||
Furniture and fixtures | 5,364 | 6,304 | ||||||
Leasehold improvements | 887 | 929 | ||||||
Construction in progress | 184,531 | 182,046 | ||||||
1,081,167 | 1,333,907 | |||||||
Accumulated depreciation | 74,011 | 141,733 | ||||||
$ | 1,007,156 | $ | 1,192,174 | |||||
(7) | Goodwill and Intangible Assets |
Contractual | ||||
Year Ending December 31, | Agreements | |||
2008 | 64 | |||
2009 | 33 | |||
2010 | 33 | |||
2011 | 33 | |||
2012 | 28 | |||
Thereafter | 282 | |||
473 | ||||
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(8) | Deferred Financing Costs |
December 31, | December 31, | |||||||
2006 | 2007 | |||||||
Deferred financing costs | $ | 11,065 | $ | 12,278 | ||||
Less accumulated amortization | 21 | 2,778 | ||||||
Unamortized deferred financing costs | 11,044 | 9,500 | ||||||
Less current portion | 1,916 | 1,985 | ||||||
$ | 9,128 | $ | 7,515 | |||||
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Deferred | ||||
Year Ending December 31, | Financing | |||
2008 | $ | 1,985 | ||
2009 | 1,968 | |||
2010 | 1,953 | |||
2011 | 1,436 | |||
2012 | 1,426 | |||
Thereafter | 732 | |||
$ | 9,500 | |||
(9) | Note Payable and Capital Lease Obligations |
(10) | Flood |
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F-37
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(11) | Income Taxes |
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 | ) | |||||||
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. |
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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. |
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Balance as of January 1, 2007 | $ | 0 | ||
Increase and decrease in prior year tax positions | — | |||
Increases and decrease in current year tax positions | — | |||
Settlements | — | |||
Reductions related to expirations of statute of limitations | — | |||
Balance as of December 31, 2007 | $ | 0 | ||
(12) | Long-Term Debt |
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F-41
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Minimum | ||||||||
Interest | Maximum | |||||||
Fiscal Quarter Ending | Coverage Ratio | Leverage Ratio | ||||||
March 31, 2008 | 3.25:1.00 | 3.25:1.00 | ||||||
June 30, 2008 | 3.25:1.00 | 3.00:1.00 | ||||||
September 30, 2008 | 3.25:1.00 | 2.75:1.00 | ||||||
December 31, 2008 | 3.25:1.00 | 2.50:1.00 | ||||||
March 31, 2009 — December 31, 2009 | 3.75:1.00 | 2.25:1.00 | ||||||
March 31, 2010 and thereafter | 3.75:1.00 | 2.00:1.00 |
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 | |||||||
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(13) | Pro Forma Earnings Per Share |
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December 31 | ||||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
(As restated)(†) | ||||||||
(in thousands) | ||||||||
Net income (loss) | $ | 191,571 | $ | (67,618 | ) | |||
Pro forma weighted average shares outstanding: | ||||||||
Original CVR common shares | 100 | 100 | ||||||
Effect of 628,667.20 to 1 stock split | 62,866,620 | 62,866,620 | ||||||
Issuance of common shares to management in exchange for subsidiary shares | 247,471 | 247,471 | ||||||
Issuance of common shares to employees | 27,100 | 27,100 | ||||||
Issuance of common shares in the initial public offering | 23,000,000 | 23,000,000 | ||||||
Basic weighted average shares outstanding | 86,141,291 | 86,141,291 | ||||||
Dilutive securities — issuance of nonvested common shares to board of directors | 17,500 | — | ||||||
Diluted weighted average shares outstanding | 86,158,791 | 86,141,291 | ||||||
Pro forma basic earnings (loss) per share | $ | 2.22 | $ | (0.78 | ) | |||
Pro forma dilutive earnings (loss) per share | $ | 2.22 | $ | (0.78 | ) |
(†) | See Note 2 to consolidated financial statements. |
(14) | Benefit Plans |
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(15) | Commitments and Contingent Liabilities |
Operating | Unconditional | |||||||
Year Ending December 31, | Leases | Purchase Obligations | ||||||
2008 | 4,207 | 25,235 | ||||||
2009 | 3,271 | 25,249 | ||||||
2010 | 1,679 | 52,781 | ||||||
2011 | 947 | 50,958 | ||||||
2012 | 195 | 48,352 | ||||||
Thereafter | 10 | 366,363 | ||||||
$ | 10,309 | $ | 568,938 | |||||
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F-46
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F-49
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Year Ending December 31, | Amount | |||
2008 | $ | 2,802 | ||
2009 | 687 | |||
2010 | 1,556 | |||
2011 | 313 | |||
2012 | 313 | |||
Thereafter | 3,282 | |||
Undiscounted total | 8,953 | |||
Less amounts representing interest at 3.90% | 1,307 | |||
Accrued environmental liabilities at December 31, 2007 | $ | 7,646 | ||
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(16) | Derivative Financial Instruments |
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 | ) | ||||||
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Notional | Fixed | |||||||
Period Covered | Amount | Interest Rate | ||||||
June 30, 2007 to March 31, 2008 | 325 million | 4.195 | % | |||||
March 31, 2008 to March 31, 2009 | 250 million | 4.195 | % | |||||
March 31, 2009 to March 31, 2010 | 180 million | 4.195 | % | |||||
March 31, 2010 to June 30, 2010 | 110 million | 4.195 | % |
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(17) | Related Party Transactions |
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F-54
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(18) | Business Segments |
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F-56
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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 | |||||||
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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 | ||||||
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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. |
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(19) | Major Customers and Suppliers |
Successor | |||||||||||||||||
Predecessor | |||||||||||||||||
174 Days | 233 Days | Year | Year | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
June 23, | December 31, | December 31, | December 31, | ||||||||||||||
2005 | 2005 | 2006 | 2007 | ||||||||||||||
Petroleum | |||||||||||||||||
Customer A | 17 | % | 16 | % | 2 | % | 3 | % | |||||||||
Customer B | 5 | % | 6 | % | 5 | % | 5 | % | |||||||||
Customer C | 17 | % | 15 | % | 15 | % | 12 | % | |||||||||
Customer D | 14 | % | 17 | % | 10 | % | 7 | % | |||||||||
Customer E | 11 | % | 11 | % | 10 | % | 9 | % | |||||||||
Customer F | 8 | % | 7 | % | 9 | % | 10 | % | |||||||||
72 | % | 72 | % | 51 | % | 46 | % | ||||||||||
Nitrogen Fertilizer | |||||||||||||||||
Customer G | 16 | % | 10 | % | 5 | % | 3 | % | |||||||||
Customer H | 9 | % | 10 | % | 7 | % | 18 | % | |||||||||
25 | % | 20 | % | 12 | % | 21 | % | ||||||||||
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. |
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 | % | |||||||||
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(20) | Selected Quarterly Financial and Information (Unaudited) |
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 |
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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 |
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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. |
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March 31, | December 31, | |||||||
2008 | 2007 | |||||||
(unaudited) | ||||||||
(in thousands of dollars) | ||||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 25,179 | $ | 30,509 | ||||
Accounts receivable, net of allowance for doubtful accounts of $597 and $391, respectively | 117,033 | 86,546 | ||||||
Inventories | 288,415 | 254,655 | ||||||
Prepaid expenses and other current assets | 13,071 | 14,186 | ||||||
Insurance receivable | 74,275 | 73,860 | ||||||
Income tax receivable | 26,166 | 31,367 | ||||||
Deferred income taxes | 78,325 | 79,047 | ||||||
Total current assets | 622,464 | 570,170 | ||||||
Property, plant, and equipment, net of accumulated depreciation | 1,192,542 | 1,192,174 | ||||||
Intangible assets, net | 450 | 473 | ||||||
Goodwill | 83,775 | 83,775 | ||||||
Deferred financing costs, net | 7,028 | 7,515 | ||||||
Insurance receivable | 11,400 | 11,400 | ||||||
Other long-term assets | 5,932 | 2,849 | ||||||
Total assets | $ | 1,923,591 | $ | 1,868,356 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 4,862 | $ | 4,874 | ||||
Note payable and capital lease obligations | 11,209 | 11,640 | ||||||
Payable to swap counterparty | 294,984 | 262,415 | ||||||
Accounts payable | 170,194 | 182,225 | ||||||
Personnel accruals | 34,954 | 36,659 | ||||||
Accrued taxes other than income taxes | 22,073 | 14,732 | ||||||
Deferred revenue | 29,784 | 13,161 | ||||||
Other current liabilities | 32,953 | 33,820 | ||||||
Total current liabilities | 601,013 | 559,526 | ||||||
Long-term liabilities: | ||||||||
Long-term debt, less current portion | 483,117 | 484,328 | ||||||
Accrued environmental liabilities | 4,924 | 4,844 | ||||||
Deferred income taxes | 287,974 | 286,986 | ||||||
Other long-term liabilities | 4,447 | 1,122 | ||||||
Payable to swap counterparty | 76,411 | 88,230 | ||||||
Total long-term liabilities | 856,873 | 865,510 | ||||||
Commitments and contingencies | ||||||||
Minority interest in subsidiaries | 10,600 | 10,600 | ||||||
Stockholders’ equity | ||||||||
Common stock $0.01 par value per share; 350,000,000 shares authorized; 86,141,291 shares issued and outstanding | 861 | 861 | ||||||
Additionalpaid-in-capital | 458,523 | 458,359 | ||||||
Retained earning (deficit) | (4,279 | ) | (26,500 | ) | ||||
Total stockholders’ equity | 455,105 | 432,720 | ||||||
Total liabilities and stockholders’ equity | $ | 1,923,591 | $ | 1,868,356 | ||||
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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 |
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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 |
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(1) | Organization and History of the Company and Basis of Presentation |
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• | 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. |
• | 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. |
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(2) | Recent Accounting Pronouncements |
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(3) | Share Based Compensation |
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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 |
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Remeasurement | ||||
Grant 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 |
Forfeiture | ||||
Minimum Period Held | Rate | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
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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 |
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 |
Subject to | ||||
Forfeiture | ||||
Minimum Period Held | Percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
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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 | |||||
Estimated forfeiture rate | None | |
March 31, 2008 estimated fair value | $0.004 per share | |
Marketability and minority interest discount | 15% discount | |
Volatility | 36.2% |
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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% |
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(4) | Inventories |
March 31, | December 31, | |||||||
2008 | 2007 | |||||||
Finished goods | $ | 123,814 | $ | 109,394 | ||||
Raw materials and catalysts | 123,042 | 92,104 | ||||||
In-process inventories | 17,045 | 29,817 | ||||||
Parts and supplies | 24,514 | 23,340 | ||||||
$ | 288,415 | $ | 254,655 | |||||
(5) | Property, Plant, and Equipment |
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 | |||||
(6) | Planned Major Maintenance Costs |
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(7) | Cost Classifications |
(8) | Note Payable and Capital Lease Obligations |
(9) | Flood and Insurance Related Matters |
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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 |
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(10) | Income Taxes |
(11) | Earnings (Loss) Per Share |
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 |
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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 |
Operating | Unconditional | |||||||
Leases | Purchase Obligations | |||||||
Nine months ending December 31, 2008 | $ | 2,833 | $ | 20,757 | ||||
Year ending December 31, 2009 | 3,266 | 28,229 | ||||||
Year ending December 31, 2010 | 1,680 | 55,762 | ||||||
Year ending December 31, 2011 | 948 | 53,939 | ||||||
Year ending December 31, 2012 | 196 | 51,333 | ||||||
Thereafter | 10 | 372,325 | ||||||
$ | 8,933 | $ | 582,345 | |||||
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Amount | ||||
Nine months ending December 31, 2008 | 2,617 | |||
Year ending December 31, 2009 | 687 | |||
Year ending December 31, 2010 | 1,556 | |||
Year ending December 31, 2011 | 313 | |||
Year ending December 31, 2012 | 313 | |||
Thereafter | 3,282 | |||
Undiscounted total | 8,768 | |||
Less amounts representing interest at 3.13% | 1,055 | |||
Accrued environmental liabilities at March 31, 2008 | $ | 7,713 | ||
(13) | Derivative Financial Instruments |
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 | ) | ||
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Notional | Fixed | |||||||
Period Covered | Amount | Interest Rate | ||||||
June 30, 2007 to March 31, 2008 | 325 million | 4.195 | % | |||||
March 31, 2008 to March 30, 2009 | 250 million | 4.195 | % | |||||
March 31, 2009 to March 30, 2010 | 180 million | 4.195 | % | |||||
March 31, 2010 to June 29, 2010 | 110 million | 4.195 | % |
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(14) | Fair Value Measurements |
• | 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) |
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 |
(15) | Related Party Transactions |
F-88
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F-89
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(16) | Business Segments |
F-90
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F-91
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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 | ||||
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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 | ||||
(17) | Subsequent Events |
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F-1 | ||||||||
EX-23.1: CONSENT OF KPMG LLP | ||||||||
EX-23.3: CONSENT OF BLUE, JOHNSON & ASSOCIATES |
Table of Contents
Item 13. | Other Expenses of Issuance and Distribution. |
SEC registration fee | $ | 11,530 | ||
FINRA filing fee | $ | 29,837 | ||
Accounting fees and expenses | ||||
Legal fees and expenses | ||||
Printing and engraving expenses | ||||
Transfer agent and registrar fees and expenses | ||||
Miscellaneous expenses | ||||
Total | $ | |||
Item 14. | Indemnification of Directors and Officers. |
• | for any breach of the director’s duty of loyalty to the Registrant or its stockholders; | |
• | for acts or omissions not in good faith or that involve intentional misconduct or a knowing violation of law; | |
• | under section 174 of the Delaware General Corporation Law regarding unlawful dividends and stock purchases; or | |
• | for any transaction for which the director derived an improper personal benefit. |
• | the Registrant is required to indemnify its directors and officers to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions; | |
• | the Registrant may indemnify its other employees and agents to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions; | |
• | the Registrant is required to advance expenses, as incurred, to its directors and officers in connection with a legal proceeding to the fullest extent permitted by the Delaware General Corporation Law, subject to very limited exceptions; | |
• | the Registrant may advance expenses, as incurred, to its employees and agents in connection with a legal proceeding; and | |
• | the rights conferred in the Bylaws are not exclusive. |
II-1
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Item 15. | Recent Sales of Unregistered Securities. |
Item 16. | Exhibits and Financial Statement Schedules. |
Item 17. | Undertakings. |
II-2
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By: | /s/ John J. Lipinski |
Signature | Title | Date | ||||
/s/ John J. Lipinski John J. Lipinski | Chief Executive Officer, President and Director (Principal Executive Officer) | June 19, 2008 | ||||
/s/ James T. Rens James T. Rens | Chief Financial Officer (Principal Financial and Accounting Officer) | June 19, 2008 | ||||
/s/ Scott L. Lebovitz Scott L. Lebovitz | Director | June 19, 2008 | ||||
/s/ Regis B. Lippert Regis B. Lippert | Director | June 19, 2008 | ||||
/s/ George E. Matelich George E. Matelich | Director | June 19, 2008 | ||||
/s/ Steve A. Nordaker Steve A. Nordaker | Director | June 19, 2008 |
II-3
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Signature | Title | Date | ||||
/s/ Stanley de J. Osborne Stanley de J. Osborne | Director | June 19, 2008 | ||||
/s/ Kenneth A. Pontarelli Kenneth A. Pontarelli | Director | June 19, 2008 | ||||
/s/ Mark Tomkins Mark Tomkins | Director | June 19, 2008 |
II-4
Table of Contents
Number | Exhibit Title | |||
1 | .1* | Form of Underwriting Agreement. | ||
3 | .1** | Amended and Restated Certificate of Incorporation of CVR Energy, Inc. (filed as Exhibit 10.1 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). | ||
3 | .2** | Amended and Restated Bylaws of CVR Energy, Inc. (filed as Exhibit 10.2 to the Company’s Quarterly Report onForm 10-Q for the quarterly period ended September 30, 2007 and incorporated by reference herein). | ||
4 | .1** | Specimen Common Stock Certificate (filed as Exhibit 4.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
5 | .1* | Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP. | ||
10 | .1** | Second Amended and Restated Credit and Guaranty Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .1.1** | First Amendment to Second Amended and Restated Credit and Guaranty Agreement, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto (filed as Exhibit 10.1.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .2** | Amended and Restated First Lien Pledge and Security Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC, CL JV Holdings, LLC, Coffeyville Pipeline, Inc., Coffeyville Refining and Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc., Coffeyville Terminal, Inc., Coffeyville Resources Pipeline, LLC, Coffeyville Resources Refining & Marketing, LLC, Coffeyville Resources Nitrogen Fertilizers, LLC, Coffeyville Resources Crude Transportation, LLC and Coffeyville Resources Terminal, LLC, as grantors, and Credit Suisse, as collateral agent (filed as Exhibit 10.2 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .3†** | Swap agreements with J. Aron & Company (filed as Exhibit 10.5 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .3.1** | Letter agreements between Coffeyville Resources, LLC and J. Aron & Company, dated as of June 26, 2007, July 11, 2007, July 26, 2007 and August 23, 2007 (filed as Exhibit 10.5.1 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .4†** | License Agreement For Use of the Texaco Gasification Process, Texaco Hydrogen Generation Process, and Texaco Gasification Power Systems, dated as of May 30, 1997 by and between Texaco Development Corporation and Farmland Industries, Inc., as amended (filed as Exhibit 10.4 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .5†** | Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The Linde Group (f/k/a The BOC Group, Inc.) and Coffeyville Resources Nitrogen Fertilizers, LLC (filed as Exhibit 10.6 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). | ||
10 | .6†** | Amended and Restated Crude Oil Supply Agreement, dated as of December 31, 2007, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC (filed as Exhibit 10.1 to the Company’s Current Report onForm 8-K, filed on January 7, 2008 and incorporated by reference herein). | ||
10 | .7†** | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC (filed as Exhibit 10.14 to the Company’s Original Registration Statement onForm S-1, FileNo. 333-137588 and incorporated by reference herein). |
Table of Contents
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). |
Table of Contents
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). |
Table of Contents
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). |
Table of Contents
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 amendment. | |
** | Previously filed. | |
† | Confidential treatment has been granted for certain provisions of this exhibit by the Securities and Exchange Commission. |