Table of Contents
Delaware | 2911 | 61-1512186 | ||
(State or Other Jurisdiction of | (Primary Standard Industrial | (I.R.S. Employer | ||
Incorporation or Organization) | Classification Code Number) | 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 |
Proposed Maximum | ||||||
Title of Each Class of | Aggregate Offering | |||||
Securities to be Registered | Price (1)(2) | Amount of Registration Fee (3) | ||||
Common Stock, $0.01 par value | $425,500,000 | $13,063 | ||||
(1) | Includes offering price of shares which the underwriters have the option to purchase. | |
(2) | Estimated solely for the purpose of calculating the registration fee pursuant to Rule 457(o) of the Securities Act of 1933, as amended. | |
(3) | The Registrant has previously paid $48,150 in connection with this Registration Statement. |
Table of Contents
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 | |||||||
Initial public offering price | $ | $ | ||||||
Underwriting discount | $ | $ | ||||||
Proceeds, before expenses, to us | $ | $ |
Goldman, Sachs & Co. | Deutsche Bank Securities |
Citi | Simmons & Company |
Table of Contents
Table of Contents
Table of Contents
1
Table of Contents
• | 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. |
2
Table of Contents
• | Continuing improvement in the supply and demand fundamentals of the global refining industry as projected by the Energy Information Administration of the U.S. Department of Energy, or the EIA. | |
• | Increasing demand for sweet crude oils and higher incremental production of lower cost sour crude that are expected to provide a cost advantage to sour crude processing refiners. | |
• | U.S. fuel specifications, including reduced sulfur content, reduced vapor pressure and the addition of oxygenates such as ethanol, that should benefit refiners who are able to efficiently produce fuels that meet these specifications. | |
• | Limited competitive threat from foreign refiners due to sophisticated U.S. fuel specifications and increasing foreign demand for refined products. | |
• | Refining capacity shortage in the mid-continent region, as certain regional markets in the U.S. are subject to insufficient local refining capacity to meet regional demands. This should result in local refiners earning higher margins on product sales than those who must rely on pipelines and other modes of transportation for supply. |
• | The impact of a growing world population combined with an expanded use of corn for the production of ethanol both of which are expected to drive worldwide grain demand and farm production, thereby increasing demand for nitrogen-based fertilizers. | |
• | High natural gas prices in North America that contribute to higher production costs for natural gas-based U.S. ammonia producers should result in elevated nitrogen fertilizer prices, as natural gas price trends generally correlate with nitrogen fertilizer price trends (based on data provided by Blue Johnson & Associates). |
3
Table of Contents
4
Table of Contents
• | Pursuing organic expansion opportunities; | |
• | Increasing the profitability of our existing assets; | |
• | Seeking both strategic and accretive acquisitions; and | |
• | Pursuing opportunities to maximize the value of the nitrogen fertilizer limited partnership. |
5
Table of Contents
6
Table of Contents
7
Table of Contents
• | Debt was used as part of the acquisition financing in June 2005 which required the introduction of a financial risk management tool that would mitigate a portion of 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. |
• | Prior to the consummation of this offering, Coffeyville Acquisition LLC will transfer half of its interests in each of Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy to Coffeyville Acquisition II LLC. Coffeyville Acquisition LLC will be owned by the Kelso Funds and our senior management and Coffeyville Acquisition II LLC will be owned by the Goldman Sachs Funds and our senior management. | |
• | We will then merge a newly formed direct subsidiary of ours with Coffeyville Refining & Marketing Holdings, Inc. (which owns Coffeyville Refining & Marketing, Inc.) and merge a separate newly formed direct subsidiary of ours with Coffeyville Nitrogen Fertilizers, Inc. which |
8
Table of Contents
will make Coffeyville Refining & Marketing, Inc. and Coffeyville Nitrogen Fertilizers, Inc. wholly owned subsidiaries of ours. These transactions will result in a structure with CVR Energy below Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and above the two subsidiaries, so that CVR Energy will become the parent of the two subsidiaries. CVR Energy has not commenced operations and has no assets or liabilities. In addition, there are no contingent liabilities and commitments attributable to CVR Energy. The mergers provide a tax free means to put an appropriate organizational structure in place to go public and give CVR Energy the flexibility to simplify its structure in a tax efficient manner in the future if necessary. |
• | In addition, we will transfer our nitrogen fertilizer business into a newly formed limited partnership and we will sell all of the interests of the managing general partner of this partnership to a new entity owned by our controlling stockholders and senior management at fair market value at such time. |
9
Table of Contents
* | Mr. John J. Lipinski, our chief executive officer, owns approximately 0.31% of Coffeyville Refining & Marketing Holdings, Inc. and approximately 0.64% of Coffeyville Nitrogen Fertilizers, Inc. It is expected that these interests will be exchanged for shares of our common stock (with an equivalent value) prior to the consummation of this offering. The mechanism for determining the equivalent value is described under “Certain Relationships and Related Party Transactions — Transactions with Senior Management.” |
10
Table of Contents
* | CVR GP, LLC, which we refer to as Fertilizer GP, will be the managing general partner of CVR Partners, LP. As managing general partner, Fertilizer GP will hold incentive distribution rights, or IDRs, which will entitle the managing general partner to receive increasing percentages of the Partnership’s quarterly distributions if the Partnership increases its distributions above an amount specified in the limited partnership agreement. The IDRs will only be payable after the Partnership has distributed all aggregated adjusted operating surplus (as defined on page 243) generated by the Partnership during the period from the Partnership’s formation through December 31, 2009. |
11
Table of Contents
Issuer | CVR Energy, Inc. | |
Common stock offered by us | 18,500,000 shares. | |
Option to purchase additional shares of common stock from us | 2,775,000 shares. | |
Common stock outstanding immediately after the offering | 81,641,591 shares. | |
Use of proceeds | We estimate that the net proceeds to us in this offering, after deducting the underwriters’ discount and the estimated expenses of the offering, will be approximately $318.65 million (based on the midpoint of the price range set forth on the cover page of this prospectus). We expect to use the net proceeds of this offering to repay $280 million of the term loans under our Credit Facility. To the extent there are outstanding revolving loans under our Credit Facility, we will use the remaining net proceeds to repay up to $50 million under our revolving loan facility. To the extent there are any excess proceeds thereafter, we will use such net proceeds to repay amounts under (i) our $25 million unsecured facility and (ii) our $25 million secured facility. If the underwriters exercise their option to purchase 2,775,000 additional shares from us in full, the additional net proceeds to us would be approximately $49.30 million (and the total net proceeds to us would be approximately $367.95 million) and we intend to use such additional net proceeds in the manner described above. Any remaining net proceeds would be used for general corporate purposes. See “Use of Proceeds.” | |
Proposed New York Stock Exchange symbol | “CVI.” | |
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. |
• | gives effect to a 628,667.20 for 1 split of our common stock; | |
• | excludes 10,300 shares of common stock issuable upon the exercise of stock options to be granted to two directors pursuant to our long-term incentive plan on the date of this prospectus; | |
• | excludes 17,500 shares of non-vested restricted stock to be awarded to two directors pursuant to our long-term incentive plan on the date of this prospectus; | |
• | includes 27,400 shares of common stock to be awarded to our employees in connection with this offering; and | |
• | assumes no exercise by the underwriters of their option to purchase up to 2,775,000 shares of common stock from us. |
12
Table of Contents
13
Table of Contents
14
Table of Contents
15
Table of Contents
Successor | Pro Forma | |||||||||||
Six Months | Six Months | Six Months | ||||||||||
Ended | Ended | Ended | ||||||||||
June 30, | June 30, | June 30, | ||||||||||
2006 | 2007 | 2007 | ||||||||||
(unaudited) | (unaudited) | (unaudited) | ||||||||||
(in millions, except as otherwise indicated) | ||||||||||||
Statement of Operations Data: | ||||||||||||
Net sales | $ | 1,550.6 | $ | 1,233.9 | $ | 1,233.9 | ||||||
Cost of product sold (exclusive of depreciation and amortization) | 1,203.4 | 873.3 | 873.3 | |||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 87.8 | 174.4 | 174.4 | |||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 20.5 | 28.1 | 28.1 | |||||||||
Costs associated with flood(1) | — | 2.1 | 2.1 | |||||||||
Depreciation and amortization | 24.0 | 32.2 | 32.2 | |||||||||
Operating income | $ | 214.9 | $ | 123.8 | $ | 123.8 | ||||||
Other income | 1.4 | 0.7 | 0.7 | |||||||||
Interest (expense) | (22.3 | ) | (27.6 | ) | (17.1 | ) | ||||||
Loss on derivatives | (126.5 | ) | (292.4 | ) | (292.4 | ) | ||||||
Income (loss) before income taxes and minority interest in subsidiaries | $ | 67.5 | $ | (195.5 | ) | $ | (185.0 | ) | ||||
Income tax (expense) benefit | (25.7 | ) | 141.0 | 136.8 | ||||||||
Minority interest in (income) loss of subsidiaries | — | 0.2 | 0.2 | |||||||||
Net income (loss)(2) | $ | 41.8 | $ | (54.3 | ) | $ | (48.0 | ) | ||||
Pro forma earnings (loss) per share, basic | 0.51 | (0.67 | ) | (0.59 | ) | |||||||
Pro forma earnings (loss) per share, diluted | 0.51 | (0.67 | ) | (0.59 | ) | |||||||
Pro forma weighted average shares, basic | 81,641,591 | 81,641,591 | 81,641,591 | |||||||||
Pro forma weighted average shares, diluted | 81,659,091 | 81,641,591 | 81,641,591 | |||||||||
Segment Financial Data: | ||||||||||||
Operating income (loss) | ||||||||||||
Petroleum | $ | 178.0 | $ | 102.9 | $ | 102.9 | ||||||
Nitrogen fertilizer | 37.1 | 21.0 | 21.0 | |||||||||
Other | (0.2 | ) | (0.1 | ) | (0.1 | ) | ||||||
Operating income | $ | 214.9 | $ | 123.8 | $ | 123.8 | ||||||
Depreciation and amortization | ||||||||||||
Petroleum | $ | 15.6 | $ | 23.1 | $ | 23.1 | ||||||
Nitrogen fertilizer | 8.4 | 8.8 | 8.8 | |||||||||
Other | — | 0.3 | 0.3 | |||||||||
Depreciation and amortization(3) | $ | 24.0 | $ | 32.2 | $ | 32.2 | ||||||
Other Financial Data: | ||||||||||||
Net income adjusted for unrealized gain or loss from Cash Flow Swap(4) | $ | 101.0 | $ | 59.0 | $ | 65.3 | ||||||
Cash flows provided by operating activities | 120.3 | 157.6 | ||||||||||
Cash flows (used in) investing activities | (86.2 | ) | (214.1 | ) | ||||||||
Cash flows provided by financing activities | 29.0 | 37.6 | ||||||||||
Capital expenditures for property, plant and equipment | 86.2 | 214.1 |
16
Table of Contents
Successor | ||||||||
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
(in millions, except as otherwise indicated) | ||||||||
Key Operating Statistics: | ||||||||
Petroleum Business | ||||||||
Production (barrels per day)(5) | 106,915 | 78,098 | ||||||
Crude oil throughput barrels per day(5) | 94,083 | 71,098 | ||||||
Refining margin per barrel(6) | $ | 15.69 | $ | 22.71 | ||||
NYMEX 2-1-1 crack spread(7) | $ | 12.02 | $ | 17.13 | ||||
Direct operating expenses exclusive of depreciation and amortization per barrel(8) | $ | 3.47 | $ | 10.96 | ||||
Gross profit (loss) per barrel(8) | $ | 11.30 | $ | 9.80 | ||||
Nitrogen Fertilizer Business | ||||||||
Production Volume: | ||||||||
Ammonia (tons in thousands) | 205.6 | 169.0 | ||||||
UAN (tons in thousands) | 328.3 | 304.6 | ||||||
On-stream factors(9): | ||||||||
Gasification | 97.3 | % | 90.6 | % | ||||
Ammonia | 94.7 | % | 86.8 | % | ||||
UAN | 93.8 | % | 81.9 | % |
17
Table of Contents
Original | |||||||||||||||||||||||||||||||
Predecessor | Immediate Predecessor | Successor | Successor | Pro Forma | |||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Year | |||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | December 31, | |||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | |||||||||||||||||||||||||
(unaudited) | |||||||||||||||||||||||||||||||
(in millions, except as otherwise indicated) | |||||||||||||||||||||||||||||||
Statement of Operations Data: | |||||||||||||||||||||||||||||||
Net sales | $ | 1,262.2 | $ | 261.1 | $ | 1,479.9 | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | $ | 3,037.6 | |||||||||||||||||
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 | 2,443.4 | ||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 133.1 | 23.4 | 117.0 | 80.9 | 85.3 | 199.0 | 199.0 | ||||||||||||||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 23.6 | 4.7 | 16.3 | 18.4 | 18.4 | 62.6 | 63.5 | ||||||||||||||||||||||||
Depreciation and amortization | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | 51.0 | ||||||||||||||||||||||||
Impairment, losses in joint ventures, and other charges(10) | 10.9 | — | — | — | — | — | — | ||||||||||||||||||||||||
Operating income | $ | 29.4 | $ | 11.2 | $ | 100.0 | $ | 112.3 | $ | 158.5 | $ | 281.6 | $ | 280.7 | |||||||||||||||||
Other income (expense)(11) | (0.5 | ) | — | (6.9 | ) | (8.4 | ) | 0.4 | (20.8 | ) | (20.8 | ) | |||||||||||||||||||
Interest (expense) | (1.3 | ) | — | (10.1 | ) | (7.8 | ) | (25.0 | ) | (43.9 | ) | (34.6 | ) | ||||||||||||||||||
Gain (loss) on derivatives | 0.3 | — | 0.5 | (7.6 | ) | (316.1 | ) | 94.5 | 94.5 | ||||||||||||||||||||||
Income (loss) before income taxes | $ | 27.9 | $ | 11.2 | $ | 83.5 | $ | 88.5 | $ | (182.2 | ) | $ | 311.4 | $ | 319.8 | ||||||||||||||||
Income tax (expense) benefit | — | — | (33.8 | ) | (36.1 | ) | 63.0 | (119.8 | ) | (123.2 | ) | ||||||||||||||||||||
Net income (loss)(2) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | 196.6 | ||||||||||||||||
Pro forma earnings per share, basic | $ | 2.26 | $ | 2.31 | |||||||||||||||||||||||||||
Pro forma earnings per share, diluted | 2.26 | 2.31 | |||||||||||||||||||||||||||||
Pro forma weighted average shares, basic | 84,716,785 | 85,011,044 | |||||||||||||||||||||||||||||
Pro forma weighted average shares, diluted | 84,734,285 | 85,028,544 | |||||||||||||||||||||||||||||
Segment Financial Data: | |||||||||||||||||||||||||||||||
Operating income (loss) | |||||||||||||||||||||||||||||||
Petroleum | $ | 21.5 | $ | 7.7 | $ | 77.1 | $ | 76.7 | $ | 123.0 | $ | 245.6 | 245.0 | ||||||||||||||||||
Nitrogen fertilizer | 7.8 | 3.5 | 22.9 | 35.3 | 35.7 | 36.8 | 36.5 | ||||||||||||||||||||||||
Other | 0.1 | — | — | 0.3 | (0.2 | ) | (0.8 | ) | (0.8 | ) | |||||||||||||||||||||
Operating income | $ | 29.4 | $ | 11.2 | $ | 100.0 | $ | 112.3 | $ | 158.5 | $ | 281.6 | 280.7 | ||||||||||||||||||
Depreciation and amortization | |||||||||||||||||||||||||||||||
Petroleum | $ | 2.1 | $ | 0.3 | $ | 1.5 | �� | $ | 0.8 | $ | 15.6 | $ | 33.0 | 33.0 | |||||||||||||||||
Nitrogen fertilizer | 1.2 | 0.1 | 0.9 | 0.3 | 8.4 | 17.1 | 17.1 | ||||||||||||||||||||||||
Other | — | — | — | — | — | 0.9 | 0.9 | ||||||||||||||||||||||||
Depreciation and amortization(3) | $ | 3.3 | $ | 0.4 | $ | 2.4 | $ | 1.1 | $ | 24.0 | $ | 51.0 | $ | 51.0 | |||||||||||||||||
Other Financial Data: | |||||||||||||||||||||||||||||||
Net income adjusted for unrealized gain or loss from Cash Flow Swap(4) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | 120.4 | |||||||||||||||||
Cash flows provided by operating activities | 20.3 | 53.2 | 89.8 | 12.7 | 82.5 | 186.6 | |||||||||||||||||||||||||
Cash flows (used in) investing activities | (0.8 | ) | — | (130.8 | ) | (12.3 | ) | (730.3 | ) | (240.2 | ) | ||||||||||||||||||||
Cash flows provided by (used in) financing activities | (19.5 | ) | (53.2 | ) | 93.6 | (52.4 | ) | 712.5 | 30.8 | ||||||||||||||||||||||
Capital expenditures for property, plant and equipment | 0.8 | — | 14.2 | 12.3 | 45.2 | 240.2 | |||||||||||||||||||||||||
18
Table of Contents
Original | ||||||||||||||||||||||||||
Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | |||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | |||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | |||||||||||||||||||||
(in millions, except as otherwise indicated) | ||||||||||||||||||||||||||
Key Operating Statistics: | ||||||||||||||||||||||||||
Petroleum Business | ||||||||||||||||||||||||||
Production (barrels per day)(5)(12) | 95,701 | 106,645 | 102,046 | 99,171 | 107,177 | 108,031 | ||||||||||||||||||||
Crude oil throughput (barrels per day)(5)(12) | 85,501 | 92,596 | 90,418 | 88,012 | 93,908 | 94,524 | ||||||||||||||||||||
Refining margin per barrel(6) | $ | 3.89 | $ | 4.23 | $ | 5.92 | $ | 9.28 | $ | 11.55 | $ | 13.27 | ||||||||||||||
NYMEX 2-1-1 crack spread(7) | $ | 5.53 | $ | 6.80 | $ | 7.55 | $ | 9.60 | $ | 13.47 | $ | 10.84 | ||||||||||||||
Direct operating expenses exclusive of depreciation and amortization per barrel(8) | $ | 2.57 | $ | 2.60 | $ | 2.66 | $ | 3.44 | $ | 3.13 | $ | 3.92 | ||||||||||||||
Gross profit per barrel(8) | $ | 1.25 | $ | 1.57 | $ | 3.20 | $ | 5.79 | $ | 7.55 | $ | 8.39 | ||||||||||||||
Nitrogen Fertilizer Business Production Volume: | ||||||||||||||||||||||||||
Ammonia (tons in thousands)(12) | 335.7 | 56.4 | 252.8 | 193.2 | 220.0 | 369.3 | ||||||||||||||||||||
UAN (tons in thousands)(12) | 510.6 | 93.4 | 439.2 | 309.9 | 353.4 | 633.1 | ||||||||||||||||||||
On-stream factors(9): | ||||||||||||||||||||||||||
Gasification | 90.1 | % | 93.5 | % | 92.2 | % | 97.4 | % | 98.7 | % | 92.5 | % | ||||||||||||||
Ammonia | 89.6 | % | 80.9 | % | 79.7 | % | 95.0 | % | 98.3 | % | 89.3 | % | ||||||||||||||
UAN | 81.6 | % | 88.7 | % | 82.2 | % | 93.9 | % | 94.8 | % | 88.9 | % | ||||||||||||||
Original | Immediate | Successor | ||||||||||||||||||||||||
Predecessor | Predecessor | Successor | Successor | Actual | As Adjusted | |||||||||||||||||||||
December 31, | December 31, | December 31, | December 31, | June 30, | June 30, | |||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2007 | 2007(16) | |||||||||||||||||||||
(unaudited) | (unaudited) | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||
Balance Sheet Data: | ||||||||||||||||||||||||||
Cash and cash equivalents | $ | — | $ | 52.7 | $ | 64.7 | $ | 41.9 | $ | 23.1 | $ | 61.1 | ||||||||||||||
Working capital(13) | 150.5 | 106.6 | 108.0 | 112.3 | 53.5 | 78.7 | ||||||||||||||||||||
Total assets | 199.0 | 229.2 | 1,221.5 | 1,449.5 | 1,826.2 | 1,855.2 | ||||||||||||||||||||
Liabilities subject to compromise(14) | 105.2 | — | — | — | — | — | ||||||||||||||||||||
Total debt, including current portion | — | 148.9 | 499.4 | 775.0 | 813.1 | 538.9 | ||||||||||||||||||||
Minority interest in subsidiaries(15) | — | — | — | 4.3 | 4.9 | 10.6 | ||||||||||||||||||||
Management units subject to redemption | — | — | 3.7 | 7.0 | 7.8 | — | ||||||||||||||||||||
Divisional/members equity | 58.2 | 14.1 | 115.8 | 76.4 | 21.7 | — | ||||||||||||||||||||
Stockholders’ equity | — | — | — | — | — | 328.9 | ||||||||||||||||||||
(1) | Represents thewrite-off of approximately $2.1 million of property, inventories and catalyst that were destroyed by the flood that occurred on June 30, 2007. See “Flood and Crude Oil Discharge.” |
19
Table of Contents
(2) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: |
Original | Immediate | Successor | Pro Forma | |||||||||||||||||||||||||||||||||||||||
Predecessor | Predecessor | Successor | Successor | Pro Forma | Six | Six | ||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Year | Months | Months | ||||||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | December 31, | June 30, | June 30, | ||||||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2006 | 2007 | 2007 | |||||||||||||||||||||||||||||||||
(unaudited) | (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 | 23.4 | — | — | — | ||||||||||||||||||||||||||||||||
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 | — | — | 0.6 | 0.2 | 0.2 | ||||||||||||||||||||||||||||||||
Major scheduled turnaround expense(e) | — | — | 1.8 | — | — | 6.6 | 6.6 | 0.3 | 76.8 | 76.8 | ||||||||||||||||||||||||||||||||
Loss on termination of swap(f) | — | — | — | — | 25.0 | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | — | — | — | 235.9 | (126.8 | ) | (126.8 | ) | 98.2 | 188.5 | 188.5 |
(a) | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. | |
(b) | Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004, 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 and the write-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006. | |
(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 expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery. | |
(f) | Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005. |
(3) | 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: |
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | |||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Six Months Ended | ||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | |||||||||||||||||||||||||||
(in millions) | (unaudited) | |||||||||||||||||||||||||||||||||
Depreciation and amortization included in cost of product sold | — | — | 0.2 | 0.1 | 1.1 | 2.2 | 1.0 | 1.2 | ||||||||||||||||||||||||||
Depreciation and amortization included in direct operating expense | 3.3 | 0.4 | 2.0 | 0.9 | 22.7 | 47.7 | 22.8 | 30.6 | ||||||||||||||||||||||||||
Depreciation and amortization included in selling, general and administrative expense | — | — | 0.2 | 0.1 | 0.2 | 1.1 | 0.2 | 0.4 | ||||||||||||||||||||||||||
Total depreciation and amortization | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | 24.0 | 32.2 | ||||||||||||||||||||||||||
(4) | Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. With crude oil capacity expected to reach 115,000 bpd by the end of |
20
Table of Contents
2007, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods January 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of the Credit Facility and upon meeting specific requirements related to an initial public offering, our leverage ratio and our credit ratings, and assuming our other credit facilities are terminated or amended to allow such actions, we may 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. See “Description of Our Indebtedness and the Cash Flow Swap.” | ||
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect in each period material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for unrealized gain or loss from Cash Flow Swap as a key indicator of our business performance. 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 U.S. GAAP net income results as well as Net income adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income 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 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 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 adjusted for unrealized gain or loss from Cash Flow Swap to Net income: |
Original Predecessor | Immediate Predecessor | Successor | Successor | Pro Forma | Successor | Pro Forma | ||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Six Months | Six Months | ||||||||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | Year Ended December 31, | June 30, | June 30, | |||||||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2006 | 2007 | 2007 | |||||||||||||||||||||||||||||||||
(unaudited) | (unaudited) | (unaudited) | (unaudited) | |||||||||||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||||||
Net income (loss) adjusted for unrealized loss from Cash Flow Swap | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | 120.4 | $ | 101.0 | $ | 59.0 | $ | 65.3 | ||||||||||||||||||||||
Plus: | ||||||||||||||||||||||||||||||||||||||||||
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit | — | — | — | — | (142.8 | ) | 76.2 | 76.2 | (59.2 | ) | (113.3 | ) | (113.3 | ) | ||||||||||||||||||||||||||||
Net income (loss) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | 196.6 | $ | 41.8 | $ | (54.3 | ) | $ | (48.0 | ) | |||||||||||||||||||
(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 is a measurement calculated as the difference between net sales and cost of products sold (exclusive of deprecation and amortization) which we use as a general indication of the amount above our cost of products sold at which we are able to sell refined products. Each of the components used to calculate refining margin (net sales and cost of products sold exclusive of deprecation and amortization) can be taken directly from our statement of operations. Refining margin per barrel is a measurement calculated by dividing the refining margin by our refinery’s crude oil throughput volumes for the respective periods presented. We use refining margin as the most direct and comparable metric to a crack spread which is an observable market indication of industry profitability. | |
Refining margin is a non-GAAP measure and should not be substituted for gross profit or operating income. Our calculations of refining margin and refining margin per barrel may differ from similar calculations of other companies in our industry, thereby limiting their usefulness as comparative measures. The table included in footnote 7 reconciles refining margin 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. | |
(8) | Direct operating expenses (exclusive of depreciation and amortization) per 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) 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 deprecation or amortization. We use direct operating expenses (exclusive of depreciation and amortization) as a measure of operating efficiency within the plant and as a control metric for expenditures. |
21
Table of Contents
Direct operating expenses (exclusive of depreciation and amortization) per refinery throughput barrel is a non-GAAP measure. Our calculations of direct operating expenses (exclusive of depreciation and amortization) per refinery 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 refinery throughput barrel. |
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | ||||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | |||||||||||||||||||||||||||||||
(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 | $ | 1,457.7 | $ | 1,161.4 | ||||||||||||||||||||||
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 | 1,190.5 | 869.1 | ||||||||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 59.1 | 141.1 | ||||||||||||||||||||||||||||||
Costs associated with flood | — | — | — | — | — | — | — | 2.0 | ||||||||||||||||||||||||||||||
Depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 15.6 | 23.1 | ||||||||||||||||||||||||||||||
Gross profit (loss) | $ | 39.1 | $ | 9.0 | $ | 88.0 | $ | 88.7 | $ | 135.4 | $ | 289.4 | $ | 192.5 | $ | 126.1 | ||||||||||||||||||||||
Plus direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 59.1 | 141.1 | ||||||||||||||||||||||||||||||
Plus costs associated with flood | — | — | — | — | — | — | — | 2.0 | ||||||||||||||||||||||||||||||
Plus depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 15.6 | 23.1 | ||||||||||||||||||||||||||||||
Refining margin | $ | 121.3 | $ | 24.2 | $ | 162.7 | $ | 142.1 | $ | 207.2 | $ | 457.7 | $ | 267.2 | $ | 292.3 | ||||||||||||||||||||||
Refining margin per refinery throughput barrel | $ | 3.89 | $ | 4.23 | $ | 5.92 | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 15.69 | $ | 22.71 | ||||||||||||||||||||||
Gross profit (loss) per refinery throughput barrel | $ | 1.25 | $ | 1.57 | $ | 3.20 | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 11.30 | $ | 9.80 | ||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per refinery throughput barrel | $ | 2.57 | $ | 2.60 | $ | 2.66 | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 3.47 | $ | 10.96 | ||||||||||||||||||||||
(9) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. | |
(10) | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code. | |
(11) | During the 304 days ended December 31, 2004, the 174 days ended June 23, 2005 and the year ended December 31, 2006, we recognized a loss of $7.2 million, $8.1 million and $23.4 million, respectively, on early extinguishment of debt. | |
(12) | 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. | |
(13) | 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. | |
(14) | 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 Bankruptcy Code.”SOP 90-7 requires that pre-petition liabilities be segregated in the Balance Sheet. | |
(15) | Minority interest reflects (a) on December 31, 2006 and June 30, 2007, respectively, common stock in two of our subsidiaries owned by John J. Lipinski (which will be exchanged for shares of our common stock with an equivalent value prior to the consummation of this offering) and (b) on June 30, 2007, as adjusted, the managing general partner interest in the Partnership held by our controlling stockholders and senior management. | |
(16) | A $1.00 increase (decrease) in the assumed initial public offering price of $19.00 per share, which is the midpoint of the price range set forth on the cover page of this prospectus, would (decrease) increase total debt and would increase (decrease) stockholders’ equity by approximately $17.3 million, assuming that the number of shares offered by us, as set forth on the cover page of this prospectus, remains the same and after deducting estimated underwriting discounts and commissions. In addition, depending on market conditions at the time of pricing of this offering, we may sell fewer or more shares than the number set forth on the cover page of this prospectus. The pro forma information presented above is illustrative only and following the completion of this offering will be adjusted based on the actual initial public offering price and other terms of the offering determined at pricing. |
22
Table of Contents
• | Original Predecessor refers to the former Petroleum Division and one facility within the eight-plant Nitrogen Fertilizer Manufacturing and Marketing Division of Farmland which Coffeyville Resources, LLC acquired on March 3, 2004 in a sales process under Chapter 11 of the U.S. Bankruptcy Code; | |
• | Initial Acquisition refers to the acquisition of Original Predecessor on March 3, 2004 by Coffeyville Resources, LLC; | |
• | Immediate Predecessor refers to Coffeyville Group Holdings, LLC and its subsidiaries, including Coffeyville Resources, LLC; | |
• | Subsequent Acquisition refers to the acquisition of Immediate Predecessor on June 24, 2005 by Coffeyville Acquisition LLC; and | |
• | Successor refers to Coffeyville Acquisition LLC and its consolidated subsidiaries. |
23
Table of Contents
24
Table of Contents
• | 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. |
25
Table of Contents
26
Table of Contents
27
Table of Contents
28
Table of Contents
29
Table of Contents
30
Table of Contents
31
Table of Contents
32
Table of Contents
33
Table of Contents
34
Table of Contents
35
Table of Contents
36
Table of Contents
• | 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; | |
• | amortization of acquired assets, which would reduce future reported earnings; | |
• | possible adverse short-term effects on our cash flows or operating results; | |
• | diversion of management’s attention from the ongoing operations of our petroleum business and the nitrogen fertilizer business; and | |
• | assumption of unknown material liabilities or regulatory non-compliance issues. |
37
Table of Contents
• | 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. |
38
Table of Contents
39
Table of Contents
• | 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 |
40
Table of Contents
• | 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. |
41
Table of Contents
• | the failure of securities analysts to cover our common stock after this offering or changes in financial estimates by analysts; | |
• | announcements by us or our competitors of significant contracts or acquisitions; | |
• | variations in quarterly results of operations; | |
• | loss of a large customer or supplier; | |
• | general economic conditions; | |
• | terrorist acts; | |
• | future sales of our common stock; and | |
• | investor perceptions of us and the industries in which our products are used. |
42
Table of Contents
43
Table of Contents
44
Table of Contents
45
Table of Contents
46
Table of Contents
• | Fertilizer GP, as managing general partner of the Partnership, will hold all of the incentive distribution rights in the Partnership. Incentive distribution rights will give Fertilizer GP a right to increasing percentages of the Partnership’s quarterly distributions after the Partnership has distributed all aggregate adjusted operating surplus generated by the Partnership during the period from its formation through December 31, 2009, assuming the Partnership and its subsidiaries are released from their guaranty of our credit facilities. Fertilizer GP may have an incentive to manage the Partnership in a manner which increases these future cash flows rather than in a manner which increases current cash flows. | |
• | The initial directors and executive officers of Fertilizer GP will also serve as directors and executive officers of CVR Energy. 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, will divide their time between our business and the business of the Partnership. These executive officers will face conflicts of interests from time to time in making decisions which may benefit either our company or the Partnership. However, when making decisions on behalf of the Partnership, they will be acting in their capacity as directors and officers of the managing general partner and not us. | |
• | The owners of Fertilizer GP, who are also our controlling stockholders and senior management, will be 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 will not be required to share business opportunities with us, and our owners will not be required to share business opportunities with the Partnership or Fertilizer GP. | |
• | Neither the partnership agreement nor any other agreement will require the owners of Fertilizer GP to pursue a business strategy that favors us or the Partnership. The owners of Fertilizer GP will 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 will be allowed to take into account the interests of parties other than us, such as its owners, in resolving conflicts of interest, which will have the effect of limiting its fiduciary duty to us. | |
• | The partnership agreement will limit the liability and reduce the fiduciary duties of Fertilizer GP, while also restricting the remedies available to the unit holders of the Partnership, including us, for actions that, without these limitations, might constitute breaches of fiduciary duty. Delaware partnership law permits such contractual reductions of fiduciary duty. As a result of our ownership interest in the Partnership, we may consent to some actions that might otherwise constitute a breach of fiduciary or other duties applicable under state law. | |
• | Fertilizer GP will determine the amount and timing of asset purchases and sales, capital expenditures, borrowings, repayment of indebtedness, issuances of additional partnership units and cash reserves maintained by the Partnership (subject to our specified joint management rights as holder of special GP 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. | |
• | In some instances Fertilizer GP may cause the Partnership to borrow funds in order to permit the payment of cash distributions, where the purpose or effect of the borrowing is to make incentive distributions which benefit Fertilizer GP. Fertilizer GP will also be able to determine |
47
Table of Contents
the amount and timing of any capital expenditures and whether a capital expenditure is for maintenance, which reduces operating surplus, or improvement, 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. |
• | 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 will control the enforcement of obligations owed to the Partnership by it and its affiliates. In addition, Fertilizer GP will decide whether to retain separate counsel or others to perform services for the Partnership. |
• | The partnership agreement permits Fertilizer GP to make a number of decisions in its individual capacity, as opposed to its capacity as a general partner. This entitles Fertilizer GP to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us or our affiliates. | |
• | 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. | |
• | 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 unit holders 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” to the Partnership and that, 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. |
48
Table of Contents
49
Table of Contents
50
Table of Contents
• | The Partnership’s managing general partner has broad discretion to establish reserves for the prudent conduct of the Partnership’s business. The establishment of those reserves could result in a reduction of the Partnership’s distributions. | |
• | The amount of distributions made by the Partnership and the decision to make any distribution is determined by the Partnership’s managing general partner, which we do not control. | |
• | UnderSection 17-607 of the Delaware Limited Partnership Act, the Partnership may not make a distribution to its unit holders if the distribution would cause its liabilities to exceed the fair value of its assets. | |
• | Although the partnership agreement requires the Partnership to distribute its available cash, the partnership agreement may be amended. | |
• | If the Partnership enters into its own credit facility in the future, the credit facility may limit the distributions which the Partnership can make. In addition, the credit facility will likely contain financial tests and covenants that the Partnership must satisfy; any failure to comply with these tests and covenants could result in the lenders prohibiting distributions by the Partnership. | |
• | The actual amount of cash available for distribution will depend on factors such as the level of capital expenditures made by the Partnership, the cost of acquisitions, if any, fluctuations in the Partnership’s working capital needs, the amount of fees and expenses incurred by the Partnership, and the Partnership’s ability to make working capital and other borrowings to make distributions to unit holders. | |
• | If the Partnership consummates one or more public or private offerings, because at least 40% (and potentially all) of our interest may be subordinated to common units we would be harmed if the MQD could not be paid on all units. |
51
Table of Contents
52
Table of Contents
53
Table of Contents
54
Table of Contents
• | volatile margins in the refining industry; | |
• | exposure to the risks associated with volatile crude prices; | |
• | disruption of our ability to obtain an adequate supply of crude oil; | |
• | decreases in the light/heavy and/or the sweet/sour crude oil price spreads; | |
• | refinery operating hazards and interruptions, including unscheduled maintenance or downtime, and the availability of adequate insurance coverage; | |
• | losses, damages and lawsuits related to the flood and crude oil discharge; | |
• | uncertainty regarding our ability to recover costs and losses resulting from 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 availability of adequate cash and other sources of liquidity for our capital needs; | |
• | a decline in the price of natural gas; | |
• | the cyclical nature of the nitrogen fertilizer business; | |
• | adverse weather conditions; | |
• | the supply and price levels of essential raw materials; | |
• | the volatile nature of ammonia, potential liability for accidents involving ammonia that cause severe damage to 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; | |
• | liabilities arising from current or future environmental contamination, including from the flood and crude oil discharge; | |
• | our limited operating history as a stand-alone company; |
55
Table of Contents
• | our commodity derivative activities; | |
• | our dependence on significant customers; | |
• | our potential inability to successfully implement our business strategies, including the completion of significant capital programs; | |
• | the success of our acquisition strategies; | |
• | our significant indebtedness; | |
• | the dependence on our subsidiaries for cash to meet our debt obligations; | |
• | whether we will be able to amend our credit facilities on acceptable terms if the Partnership seeks to consummate a public or private offering; | |
• | the potential loss of key personnel; | |
• | labor disputes and adverse employee relations; | |
• | potential increases in costs and distraction of management resulting from the requirements of being a public company; | |
• | risks relating to evaluations of internal controls required by Section 404 of the Sarbanes-Oxley Act; | |
• | the operation of our company as a “controlled company”; | |
• | new regulations concerning the transportation of hazardous chemicals, risks of terrorism and the security of chemical manufacturing facilities; | |
• | successfully defending against third-party claims of intellectual property infringement; | |
• | our ability to continue to license the technology used in our operations; | |
• | the Partnership’s ability to make distributions equal to the minimum quarterly distribution or any distributions at all; | |
• | the possibility that Partnership distributions to us will decrease if the Partnership issues additional equity interests and that our rights to receive distributions will be subordinated to the rights of third party investors; | |
• | the possibility that we will be required to deconsolidate the Partnership from our financial statements in the future; | |
• | the Partnership’s preferential right to pursue certain business opportunities before we pursue them; | |
• | reduction of our voting power in the Partnership if the Partnership completes a public offering or private placement; | |
• | whether we will be required to purchase the managing general partner interest in the Partnership, and whether we will have the requisite funds to do so; | |
• | the possibility that we will be required to sell a portion of our interests in the Partnership in the Partnership’s initial offering at an undesirable time or price; | |
• | the ability of the Partnership to manage the nitrogen fertilizer business in a manner adverse to our interests; | |
• | the conflicts of interest faced by our senior management, which operates both our company and the Partnership, and our controlling stockholders, who control our company and the managing general partner of the Partnership; |
56
Table of Contents
• | 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. |
57
Table of Contents
58
Table of Contents
59
Table of Contents
60
Table of Contents
• | on an actual basis for Coffeyville Acquisition LLC; and | |
• | as adjusted to give effect to the three new credit facilities we entered into in August 2007, the sale by us of 18,500,000 shares in this offering at an assumed initial offering price of $19.00 per share, the midpoint of the price range set forth on the cover page of this prospectus, the use of proceeds from this offering, the Transactions, the transfer of the nitrogen fertilizer business to the Partnership, the sale of the managing general partner interest in the Partnership to a new entity owned by our controlling stockholders and senior management, the termination fee payable in connection with the termination of the management agreements in conjunction with this offering, the issuance of shares of our common stock to our chief executive officer in exchange for shares in two of our subsidiaries and the payment of a dividend to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. |
As of June 30, 2007 | ||||||||||||
As Adjusted | As Adjusted | |||||||||||
before | after | |||||||||||
Underwriters’ | Underwriters’ | |||||||||||
Actual | Option | Option | ||||||||||
(in thousands) | ||||||||||||
Cash and cash equivalents | $ | 23,077 | $ | 61,108 | $ | 64,540 | ||||||
Debt (including current portion): | ||||||||||||
Revolving Credit Facility(1) | 40,000 | — | — | |||||||||
Term loan facility | 773,063 | 493,063 | 493,063 | |||||||||
$25 million secured facility | — | 20,865 | — | |||||||||
$25 million unsecured facility | — | 25,000 | — | |||||||||
$75 million unsecured facility | — | — | — | |||||||||
Total debt | 813,063 | 538,928 | 493,063 | |||||||||
Minority interest in subsidiaries(2) | 4,904 | 10,600 | 10,600 | |||||||||
Management voting common units subject to redemption, 201,063 units(3) | 7,795 | — | — | |||||||||
Members’ equity(3): | ||||||||||||
Members’ voting common equity, 22,614,937 units | 17,637 | — | — | |||||||||
Operating override units, 992,122 units | 2,524 | — | — | |||||||||
Value override units, 1,984,231 units | 1,532 | — | — | |||||||||
Total members’ equity | 21,693 | — | — | |||||||||
Stockholders’ equity(3): | ||||||||||||
Common stock, $0.01 par value per share, 350,000,000 shares authorized; 81,641,591 shares issued and outstanding as adjusted before underwriters’ option; 84,416,591 shares issued and outstanding as adjusted after underwriters’ option(4) | — | 816 | 844 | |||||||||
Preferred stock, $0.01 par value per share, 50,000,000 shares authorized; no shares issued and outstanding as adjusted | — | — | — | |||||||||
Additional paid-in capital(3) | — | 328,034 | 377,304 | |||||||||
Total stockholders’ equity | — | 328,850 | 378,148 | |||||||||
Total capitalization | $ | 847,455 | $ | 878,378 | $ | 881,811 | ||||||
61
Table of Contents
(1) | As of June 30, 2007, we had availability of $76.2 million under the revolving credit facility. As of September 30, 2007, we had outstanding $20.0 million of revolver borrowings and aggregate availability of $168.1 million under both the revolving credit facility and the $75 million unsecured facility. | |
(2) | The as adjusted column gives effect to (i) the exchange of our chief executive officer’s shares in two of our subsidiaries for shares of our common stock and (ii) the sale of the managing general partner interest in the Partnership. | |
(3) | On an actual basis, the Members’ equity reflects the unit ownership at Coffeyville Acquisition LLC which is structured as a partnership for tax purposes. Upon completion of this offering, the reporting entity will be CVR Energy, Inc., a corporation. The ownership at Coffeyville Acquisition LLC and, after the consummation of the Transactions, Coffeyville Acquisition II LLC will not be reported, and as such, the components of Members’ equity do not appear in the “As Adjusted” column. Upon completion of this offering, common stock in CVR Energy, Inc. will be issued and reflected in Common stock in the “As Adjusted” column. Members’ equity and Management’s voting common units subject to redemption will be eliminated and replaced with Stockholders’ equity to reflect the new corporate structure. Any difference in the total value of equity upon completion of this offering and the par value of the common stock issued will be reflected in Additional paid-in capital. | |
(4) | The number of shares of common stock to be outstanding after the offering: | |
• gives effect to a 628,667.20 for 1 split of our common stock; | ||
• gives effect to the issuance of 247,471 shares of our common stock to our chief executive officer in exchange for his shares in two of our subsidiaries; | ||
• gives effect to the issuance of 18,500,000 shares of our common stock in this offering; | ||
• excludes 10,300 shares of common stock issuable upon the exercise of stock options to be granted to two directors pursuant to our long-term incentive plan on the date of this prospectus; | ||
• excludes 17,500 shares of non-vested restricted stock to be awarded to two directors pursuant to our long-term incentive plan on the date of this prospectus; | ||
• includes 27,400 shares of common stock to be awarded to our employees in connection with this offering; and | ||
• assumes no exercise by the underwriters of their option to purchase up to 2,775,000 shares of common stock from us. |
62
Table of Contents
Assumed initial public offering price per share | $ | 19.00 | ||||||
Pro forma net tangible book value per share as of June 30, 2007, excluding the net proceeds of this offering | $ | (1.17 | ) | |||||
Pro forma increase per share attributable to new investors | $ | 4.17 | ||||||
Net tangible book value per share after the offering | $ | 3.00 | ||||||
Dilution per share to new investors | $ | 16.00 | ||||||
Shares Purchased | Total Consideration | Average Price | ||||||||||||||||||
Number | Percent | Amount | Percent | Per Share | ||||||||||||||||
Existing stockholders(1) | 63,141,591 | 77 | % | $ | (2,440,000 | ) | (1 | )% | $ | (0.04 | ) | |||||||||
New investors | 18,500,000 | 23 | 351,500,000 | 101 | 19.00 | |||||||||||||||
Total | 81,641,591 | 100 | % | $ | 349,060,000 | 100 | % | $ | 4.28 | |||||||||||
(1) | Total consideration and average price per share paid by the existing stockholders give effect to the $250.0 million distribution made to certain of the existing stockholders in December 2006 using proceeds from the Credit Facility and the $10.6 million dividend we intend to distribute to existing stockholders in connection with the Transactions. If the table were adjusted to not give effect to these payments, existing stockholders total consideration for their shares would be $258,160,000 with an average share price of $4.09. |
63
Table of Contents
64
Table of Contents
65
Table of Contents
Unaudited Pro Forma Condensed Consolidated Statement of Operations
For the Year Ended December 31, 2006
Pro Forma | Pro Forma | |||||||||||||||
Adjustments to | Adjustment | |||||||||||||||
Successor | Give Effect | to Give | Pro Forma | |||||||||||||
Year Ended | to the Refinancing | Effect to | Year Ended | |||||||||||||
December 31, | and New | Proceeds from | December 31, | |||||||||||||
2006 | Credit Facilities | the Offering | 2006 | |||||||||||||
Net Sales | $ | 3,037,567,362 | $ | — | $ | — | $ | 3,037,567,362 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 2,443,374,743 | — | — | 2,443,374,743 | ||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 198,979,983 | — | — | 198,979,983 | ||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 62,600,121 | 941,667 | (a) | — | 63,541,788 | |||||||||||
Depreciation and amortization | 51,004,582 | — | — | 51,004,582 | ||||||||||||
Total operating costs and expenses | 2,755,959,429 | 941,667 | — | 2,756,901,096 | ||||||||||||
Operating income (loss) | 281,607,933 | (941,667 | ) | — | 280,666,266 | |||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (43,879,644 | ) | (18,442,213 | )(b) | 27,714,963 | (d) | (34,606,894 | ) | ||||||||
Gain on derivatives | 94,493,141 | — | — | 94,493,141 | ||||||||||||
Loss on extinguishment of debt | (23,360,306 | ) | — | — | (23,360,306 | ) | ||||||||||
Other income | 2,550,359 | — | — | 2,550,359 | ||||||||||||
Income (loss) before income taxes | 311,411,483 | (19,383,880 | ) | 27,714,963 | 319,742,567 | |||||||||||
Income tax expense (benefit) | 119,840,160 | (7,729,322 | )(c) | 11,051,342 | (e) | 123,162,180 | ||||||||||
Net income (loss) | 191,571,323 | (11,654,558 | ) | 16,663,621 | 196,580,387 | |||||||||||
Pro forma earnings per share, basic(f) | $ | 2.26 | $ | 2.31 | ||||||||||||
Pro forma earnings per share, diluted(f) | $ | 2.26 | $ | 2.31 | ||||||||||||
Pro forma weighted average shares, basic(f) | 84,716,785 | 85,011,044 | ||||||||||||||
Pro forma weighted average shares, diluted(f) | 84,734,285 | 85,028,544 |
66
Table of Contents
(a) | To reflect the additional increase in fees related to the refinancing transaction and the related funded letter of credit in support of the Cash Flow Swap, which are required under the terms of the senior secured credit facility refinanced on December 28, 2006. | |
(b) | To increase the interest expense for (1) additional interest resulting from the refinancing of the Credit Facility on December 28, 2006 as if it had occurred on January 1, 2006 (an assumed average interest rate of 8.36% based on the interest rate in effect on the term loans as of December 28, 2006 was used to calculate interest expense on an average annual balance of $772 million of term debt); (2) amortization of the related deferred financing costs of $11.1 million amortized over the life of the related debt instrument; (3) additional interest resulting from the borrowings under the $25 million secured facility and the $25 million unsecured facility which occurred in August 2007, as if they had occurred on January 1, 2006 (an assumed average interest rate of 9.25% based on base rate interest in effect on August 23, 2007 was used to calculate interest expense on an average annual balance of $50 million of term debt); and (4) amortization of the related deferred financing costs of $2.0 million amortized over the life of the related debt instrument. Actual interest expense may be higher or lower depending upon fluctuations in interest rates. A1/8% change in interest rates would have resulted in a $1,034,833 change in interest expense for the twelve month period. | |
(c) | To reflect the income tax effect of the pro forma pre-tax loss adjustments of $(19,383,880) for the year ended December 31, 2006 using a combined federal and state statutory rate of approximately 39.875%. | |
(d) | To reflect the reduction in interest expense related to (1) the repayment of long-term debt of $280 million from the offering proceeds as if it had occurred on January 1, 2006 (an assumed average interest rate of 8.36% based on the interest rate in effect on the term loans as of December 28, 2006 was used to calculate the adjustment to interest expense) and (2) the repayment of the $25 million unsecured facility and $19.1 million of the $25 million secured facility from proceeds of this offering as if it had occurred on January 1, 2006 (an assumed average interest rate of 9.25% based on a base rate interest in effect as of August 23, 2007 was used to calculate the adjustment to the interest expense). Actual interest expense may be higher or lower depending upon fluctuations in interest rates. A1/8% change in interest rates would have resulted in a $632,292 change in interest expense for the twelve month period. | |
(e) | To reflect the income tax effect of the pro forma pre-tax income adjustments of $27,714,963 for the year ended December 31, 2006, using a combined federal and state statutory rate of approximately 39.875%. | |
(f) | To calculate earnings per share on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering. All information in this prospectus assumes that prior to the initial public offering, two newly formed direct wholly owned subsidiaries of ours will merge with Coffeyville Refinery and Marketing Holdings, Inc. (which owns Coffeyville Refining & Marketing, Inc.) and Coffeyville Nitrogen Fertilizers, Inc., we will effect a 628,667.20 for 1 stock split, 247,471 shares of our common stock will be issued to our chief executive officer in exchange for his shares in two of our subsidiaries, 27,400 shares of our common stock will be issued to our employees, 17,500 non-vested restricted shares of our common stock will be issued to two of our directors, and we will issue 18,500,000 shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering by us pursuant to the exercise by the underwriters of their option to purchase additional shares in the offering. The weighted average shares outstanding also gives effect to the increase in the number of shares which, when multiplied by the initial public offering price, would be sufficient to replace the capital in excess of earnings withdrawn, as a result of our paying dividends in the year ended December 31, 2006 in excess of earnings for such period, or 3,075,194 shares. The weighted average number of shares outstanding for the pro forma column also accounts for the additional $10.6 million dividend that will be paid to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. This excess number of shares for the pro forma column is 3,369,453 shares. The 17,500 non-vested restricted shares to be issued to two of our directors at the time of the offering are not included in the pro forma weighted average shares, basic, but are included in the pro forma weighted average shares, diluted. |
67
Table of Contents
Unaudited Pro Forma Condensed Consolidated Statement of Operations
For the Six Months Ended June 30, 2007
Pro Forma | Pro Forma | |||||||||||||||
Successor | Adjustments | Adjustments | Pro Forma | |||||||||||||
Six Months | to Give Effect | to Give Effect | Six Months | |||||||||||||
Ended | to New | to Proceeds from | Ended | |||||||||||||
June 30, 2007 | Credit Facilities | the Offering | June 30, 2007 | |||||||||||||
Net sales | $ | 1,233,895,912 | $ | — | $ | — | $ | 1,233,895,912 | ||||||||
Operating costs and expenses: | ||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 873,293,323 | — | — | 873,293,323 | ||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 174,366,084 | — | — | 174,366,084 | ||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 28,087,293 | — | — | 28,087,293 | ||||||||||||
Costs associated with flood | 2,138,942 | — | — | 2,138,942 | ||||||||||||
Depreciation and amortization | 32,192,458 | — | — | 32,192,458 | ||||||||||||
Total operating costs and expenses | 1,110,078,100 | — | — | 1,110,078,100 | ||||||||||||
Operating income | 123,817,812 | — | — | 123,817,812 | ||||||||||||
Other income (expense): | ||||||||||||||||
Interest expense | (27,619,423 | ) | (3,272,812 | )(a) | 13,785,278 | (d) | (17,106,957 | ) | ||||||||
Loss on derivatives | (292,444,434 | ) | — | — | (292,444,434 | ) | ||||||||||
Other income | 715,550 | — | — | 715,550 | ||||||||||||
Income (loss) before income taxes and minority interest in subsidiaries | (195,530,495 | ) | (3,272,812 | ) | 13,785,278 | (185,018,029 | ) | |||||||||
Income tax expense (benefit) | (140,966,282 | ) | (1,305,034 | )(b) | 5,496,880 | (e) | (136,774,436 | ) | ||||||||
Minority interest in (income) loss of subsidiaries | 256,748 | 8,432 | (c) | (35,517 | )(f) | 229,663 | ||||||||||
Net income (loss) | (54,307,465 | ) | (1,959,346 | ) | 8,252,881 | (48,013,930 | ) | |||||||||
Pro forma loss per share, basic(g) | $ | (0.67 | ) | $ | (0.59 | ) | ||||||||||
Pro forma loss per share, diluted(g) | $ | (0.67 | ) | $ | (0.59 | ) | ||||||||||
Pro forma weighted average shares, basic(g) | 81,641,591 | 81,641,591 | ||||||||||||||
Pro forma weighted average shares, diluted(g) | 81,641,591 | 81,641,591 |
68
Table of Contents
(a) | To increase the interest expense for (1) additional interest resulting from the borrowings under the $25 million secured facility and the $25 million unsecured facility which occurred in August 2007, as if they had occurred on January 1, 2007 and (2) amortization of the related deferred financing costs of $2.0 million amortized over the life of the related debt instrument. An assumed average interest rate of 9.25% based on base rate interest in effect on August 23, 2007 was used to calculate interest expense on an average annual balance of $50 million of term debt. Actual interest expense may be higher or lower depending upon fluctuations in interest rates. A1/8% change in interest rates would have resulted in a $30,993 change in interest expense for the six month period. | |
(b) | To reflect the income tax effect of the pro forma pre-tax loss adjustments of $(3,272,812) for the six months ended June 30, 2007 using a combined federal and state statutory rate of approximately 39.875%. | |
(c) | To reflect the adjustment to minority loss in subsidiaries for the net impact of the pro forma pre-tax loss adjustments of $(3,272,812) and the related income tax effect of the adjustment. | |
(d) | To reflect the reduction in interest expense related to (1) the repayment of long-term debt of $280 million from the offering proceeds as if it had occurred on January 1, 2007 (an assumed average interest rate of 8.35% based on the average interest rate in effect on the term loans as of June 30, 2007 was used to calculate the adjustment to interest expense) and (2) the repayment of the $25 million unsecured facility and $19.1 million of the $25 million secured facility from proceeds of this offering as if it had occurred on January 1, 2007 (an assumed average interest rate of 9.25% based on a base rate interest in effect as of August 23, 2007 was used to calculate the adjustment to interest expense). Actual interest expense may be higher or lower depending upon fluctuations in interest rates. A1/8% change in interest rates would have resulted in a $314,338 change in interest expense for the six month period. | |
(e) | To reflect the income tax effect of the pro forma pre-tax income adjustments of $13,785,278 for the six months ended June 30, 2007 using a combined federal and state statutory rate of approximately 39.875%. | |
(f) | To reflect the adjustment to minority loss in subsidiaries for the net impact of the pro forma pre-tax income adjustments of $13,785,278 and the related income tax effect of the adjustment. | |
(g) | To calculate earnings per share on a pro forma basis, based on an assumed number of shares outstanding at the time of the initial public offering. All information in this prospectus assumes that prior to the initial public offering, two newly formed direct wholly owned subsidiaries of CVR Energy will merge with Coffeyville Refining & Marketing Holdings, Inc. (which owns Coffeyville Refining & Marketing, Inc.) and Coffeyville Nitrogen Fertilizer, Inc., we will effect a 628,667.20 for 1 stock split, 247,471 shares of our common stock will be issued to our chief executive officer in exchange for his shares in two of our subsidiaries, 27,400 shares of our common stock will be issued to our employees, 17,500 non-vested restricted shares of our common stock will be issued to two of our directors, and we will issue 18,500,000 shares of common stock in this offering. No effect has been given to any shares that might be issued in this offering by us pursuant to the exercise by the underwriters of their option to purchase additional shares in the offering. The 17,500 non-vested restricted shares of our common stock to be issued to two of our directors have been excluded from the calculation of pro forma diluted earnings per share because the inclusion of such shares in the number of weighted shares outstanding would be antidilutive. |
69
Table of Contents
Unaudited Pro Forma Consolidated Balance Sheet at June 30, 2007
Pro Forma | ||||||||||||||||||||
Adjusted for | ||||||||||||||||||||
Underwriters’ | ||||||||||||||||||||
Pro Forma | Option | |||||||||||||||||||
Six Months | Six Months | Adjustments for | Six Months | |||||||||||||||||
Ended | Pro Forma | Ended | Underwriters’ | Ended | ||||||||||||||||
June 30, 2007 | Adjustments | June 30, 2007 | Option | June 30, 2007 | ||||||||||||||||
ASSETS | ||||||||||||||||||||
Current assets: | ||||||||||||||||||||
Cash and cash equivalents | $ | 23,077,422 | $ | (10,600,000 | )(a) | $ | 61,107,962 | $ | 52,725,000 | (k) | $ | 64,540,493 | ||||||||
10,600,000 | (b) | (3,427,125 | )(l) | |||||||||||||||||
351,500,000 | (c) | (45,865,344 | )(m) | |||||||||||||||||
(27,365,344 | )(d) | |||||||||||||||||||
(280,000,000 | )(e) | |||||||||||||||||||
(44,134,656 | )(f) | |||||||||||||||||||
48,030,540 | (g) | |||||||||||||||||||
(10,000,000 | )(h) | |||||||||||||||||||
Accounts receivable, net of allowance for doubtful accounts of $384,598 | 76,022,457 | 76,022,457 | 76,022,457 | |||||||||||||||||
Inventories | 179,243,439 | 179,243,439 | 179,243,439 | |||||||||||||||||
Prepaid expenses and other current assets | 23,255,906 | (7,435,453 | )(d) | 15,820,453 | 15,820,453 | |||||||||||||||
Income tax receivable | 133,467,799 | (4,226,750 | )(i) | 129,241,049 | 129,241,049 | |||||||||||||||
Deferred income taxes | 133,008,581 | 133,008,581 | 133,008,581 | |||||||||||||||||
Total current assets | 568,075,604 | 26,368,337 | 594,443,941 | 3,432,531 | 597,876,472 | |||||||||||||||
Property, plant, and equipment, net of accumulated depreciation | 1,157,972,453 | 632,509 | (j) | 1,158,604,962 | 1,158,604,962 | |||||||||||||||
Intangible assets, net | 535,525 | 535,525 | 535,525 | |||||||||||||||||
Goodwill | 83,774,885 | 83,774,885 | 83,774,885 | |||||||||||||||||
Deferred financing costs, net | 8,571,677 | 1,969,460 | (g) | 10,541,137 | 10,541,137 | |||||||||||||||
Other long-term assets | 7,305,374 | 7,305,374 | 7,305,374 | |||||||||||||||||
Total assets | $ | 1,826,235,518 | �� | $ | 28,970,306 | $ | 1,855,205,824 | $ | 3,432,531 | $ | 1,858,638,355 | |||||||||
LIABILITIES AND EQUITY | ||||||||||||||||||||
Current liabilities: | ||||||||||||||||||||
Current portion of long-term debt | $ | 7,701,683 | $ | (2,782,543 | )(e) | $ | 50,784,484, | $ | (45,865,344 | )(m) | $ | 4,919,140 | ||||||||
50,000,000 | (g) | |||||||||||||||||||
(4,134,656 | )(f) | |||||||||||||||||||
Revolving debt | 40,000,000 | (40,000,000 | ) (f) | — | — | |||||||||||||||
Accounts payable | 138,394,089 | (1,953,297 | )(d) | 136,440,792 | 136,440,792 | |||||||||||||||
Personnel accruals | 25,452,206 | 25,452,206 | 25,452,206 | |||||||||||||||||
Accrued taxes other than income taxes | 11,506,841 | 11,506,841 | 11,506,841 | |||||||||||||||||
Payable to swap counterparty | 267,118,025 | 267,118,025 | 267,118,025 | |||||||||||||||||
Deferred revenue | 1,383,699 | 1,383,699 | 1,383,699 | |||||||||||||||||
Other current liabilities | 23,024,739 | 23,024,739 | 23,024,739 | |||||||||||||||||
Total current liabilities | 514,581,282 | 1,129,504 | 515,710,786 | (45,865,344 | ) | 469,845,442 | ||||||||||||||
Long-term liabilities: | ||||||||||||||||||||
Long-term debt, less current portion | 765,360,817 | (277,217,457 | )(e) | 488,143,360 | 488,143,360 | |||||||||||||||
Accrued environmental liabilities | 5,612,516 | 5,612,516 | 5,612,516 | |||||||||||||||||
Deferred income taxes | 387,155,256 | 387,155,256 | 387,155,256 | |||||||||||||||||
Payable to swap counterparty | 119,133,755 | 119,133,755 | 119,133,755 | |||||||||||||||||
Total long-term liabilities | 1,277,262,344 | (277,217,457 | ) | 1,000,044,887 | — | 1,000,044,887 | ||||||||||||||
Minority interest in subsidiaries | 4,904,421 | 10,600,000 | (b) | 10,600,000 | 10,600,000 | |||||||||||||||
(4,904,421 | )(j) | |||||||||||||||||||
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2007 | 7,795,213 | (92,577 | )(a) | — | — | |||||||||||||||
Members’ equity: | (7,702,636 | )(c) | ||||||||||||||||||
Voting common units, 22,614,937 units issued and outstanding in 2007 | 17,636,575 | (10,412,886 | )(a) | — | — | |||||||||||||||
2,776,311 | (c) | |||||||||||||||||||
(10,000,000 | )(h) | |||||||||||||||||||
Management nonvoting override units, 2,976,353 units issued and outstanding in 2007 | 4,055,683 | (94,537 | )(a) | — | — | — | ||||||||||||||
(3,961,146 | )(c) | |||||||||||||||||||
Total members’ equity | $ | 21,692,258 | $ | (21,692,258 | ) | $ | — | $ | — | $ | — | |||||||||
PRO FORMA STOCKHOLDERS’ EQUITY | ||||||||||||||||||||
Stockholders’ equity: | ||||||||||||||||||||
Common stock, $0.01 par value per share, 350,000,000 shares authorized: 81,641,591 shares issued and outstanding as adjusted before underwriters option; 84,416,591 shares issued and outstanding as adjusted after underwriters’ option | — | 816,416 | (c) | 816,416 | 27,750 | (k) | 844,166 | |||||||||||||
Additional paid-in capital | — | (4,226,750 | )(i) | 328,033,735 | 52,697,250 | (k) | 377,303,860 | |||||||||||||
5,536,930 | (j) | (3,427,125 | )(l) | |||||||||||||||||
359,571,055 | (c) | |||||||||||||||||||
(32,847,500 | )(d) | |||||||||||||||||||
Retained earnings | ||||||||||||||||||||
Total pro forma stockholders’ equity | — | 328,850,151 | 328,850,151 | 49,297,875 | 378,148,026 | |||||||||||||||
Commitments and contingencies | ||||||||||||||||||||
Total liabilities and equity | $ | 1,826,235,518 | $ | 28,970,306 | $ | 1,855,205,824 | $ | 3,432,531 | $ | 1,858,638,355 | ||||||||||
70
Table of Contents
(a) | Reflects estimated payment of a $10.6 million dividend to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. | |
(b) | Reflects gross proceeds of $10.6 million received for the sale of the managing general partner interest in the Partnership, through sale of the managing general partner, to Coffeyville Acquisition III LLC at estimated fair market value as determined by our board of directors after consultation with management. | |
(c) | To reflect the public offering of 18,500,000 shares of common stock at an assumed initial offering price of $19.00 per share resulting in aggregate gross proceeds of $351.5 million, and in conjunction with the offering, to reflect the conversion from a partnership structure to a corporate structure of members’ equity and management voting common units subject to redemption. | |
(d) | To reflect the payment of underwriters’ discounts and commissions and estimated offering expenses totaling $32.8 million of which $5.5 million had been prepaid as of June 30, 2007 and $2.0 million has been accrued as of June 30, 2007. | |
(e) | To reflect the repayment of term debt of $280 million with the net proceeds of this offering. | |
(f) | To reflect the repayment of the revolving credit facility of $40.0 million and $4.1 million of the $25 million unsecured facility with the remaining net proceeds of this offering. | |
(g) | To reflect the funded new credit facilities entered into in August 2007 along with deferred financing fees associated with the facilities. | |
(h) | Reflects payment of a $10 million termination fee in connection with the termination of the management agreements payable to Goldman, Sachs & Co. and Kelso & Company, L.P. in conjunction with the offering. | |
(i) | Reflects the tax liability determined at a combined federal and state statutory rate of approximately 39.875% associated with the estimated tax gain recognized on the sale of the managing general partner interest at estimated fair market value. | |
(j) | Reflects the exchange of our chief executive officer’s shares in two of our subsidiaries for shares of our common stock at fair market value, resulting in an estimatedstep-up in basis in our property, plant and equipment of approximately $0.6 million. | |
(k) | To reflect the underwriters’ option to purchase 2,775,000 shares of common stock at an assumed initial offering price of $19.00 per share resulting in aggregate gross proceeds of $52.7 million. | |
(l) | To reflect the payment of underwriters’ discounts and commissions totaling $3.4 million in connection with the underwriters’ option to purchase 2,775,000 shares of common stock. | |
(m) | To reflect the repayment of term loans of $45.9 million to a related party from a portion of the remaining net proceeds of the sale of 2,775,000 shares of common stock to the underwriters. |
71
Table of Contents
72
Table of Contents
73
Table of Contents
Successor | ||||||||
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, 2006 | June 30, 2007 | |||||||
(unaudited) | (unaudited) | |||||||
(in millions, except as otherwise indicated) | ||||||||
Statement of Operations Data: | ||||||||
Net sales | $ | 1,550.6 | $ | 1,233.9 | ||||
Cost of product sold (exclusive of depreciation and amortization) | 1,203.4 | 873.3 | ||||||
Direct operating expenses (exclusive of depreciation and amortization) | 87.8 | 174.4 | ||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 20.5 | 28.1 | ||||||
Costs associated with flood(1) | — | 2.1 | ||||||
Depreciation and amortization | 24.0 | 32.2 | ||||||
Operating income | $ | 214.9 | $ | 123.8 | ||||
Other income | 1.4 | 0.7 | ||||||
Interest (expense) | (22.3 | ) | (27.6 | ) | ||||
Loss on derivatives | (126.5 | ) | (292.4 | ) | ||||
Income (loss) before income taxes and minority interest in subsidiaries | $ | 67.5 | $ | (195.5 | ) | |||
Income tax (expense) benefit | (25.7 | ) | 141.0 | |||||
Minority interest in (income) loss of subsidiaries | — | 0.2 | ||||||
Net income (loss)(2) | $ | 41.8 | $ | (54.3 | ) | |||
Pro forma earnings (loss) per share, basic | 0.51 | (0.67 | ) | |||||
Pro forma earnings (loss) per share, diluted | 0.51 | (0.67 | ) | |||||
Pro forma weighted average shares, basic | 81,641,591 | 81,641,591 | ||||||
Pro forma weighted average shares, diluted | 81,659,091 | 81,641,591 | ||||||
Balance Sheet Data: | ||||||||
Cash and cash equivalents | 127.9 | 23.1 | ||||||
Working capital | 139.7 | 53.5 | ||||||
Total assets | 1,406.1 | 1,826.2 | ||||||
Total debt, including current portion | 508.3 | 813.1 | ||||||
Minority interest in subsidiaries(3) | — | 4.9 | ||||||
Management units subject to redemption | 12.2 | 7.8 | ||||||
Divisional/members’ equity | 170.1 | 21.7 | ||||||
Other Financial Data: | ||||||||
Depreciation and amortization | $ | 24.0 | $ | 32.2 | ||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | 101.0 | 59.0 | ||||||
Cash flows provided by operating activities | 120.3 | 157.6 | ||||||
Cash flows (used in) investing activities | (86.2 | ) | (214.1 | ) | ||||
Cash flows provided by financing activities | 29.0 | 37.6 | ||||||
Capital expenditures for property, plant and equipment | 86.2 | 214.1 | ||||||
Key Operating Statistics: | ||||||||
Petroleum Business | ||||||||
Production (barrels per day)(5) | 106,915 | 78,098 | ||||||
Crude oil throughput (barrels per day)(5) | 94,083 | 71,098 | ||||||
Nitrogen Fertilizer Business | ||||||||
Production Volume: | ||||||||
Ammonia (tons in thousands) | 205.6 | 169.0 | ||||||
UAN (tons in thousands) | 328.3 | 304.6 |
74
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | ||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | |||||||||||||||||||||||||
2002 | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||||||||
(in millions, except as otherwise indicated) | ||||||||||||||||||||||||||||||
Statement of Operations Data: | ||||||||||||||||||||||||||||||
Net sales | $ | 887.5 | $ | 1,262.2 | $ | 261.1 | $ | 1,479.9 | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | ||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 765.8 | 1,061.9 | 221.4 | 1,244.2 | 768.0 | 1,168.1 | 2,443.4 | |||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 149.4 | 133.1 | 23.4 | 117.0 | 80.9 | 85.3 | 199.0 | |||||||||||||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 16.3 | 23.6 | 4.7 | 16.3 | 18.4 | 18.4 | 62.6 | |||||||||||||||||||||||
Depreciation and amortization | 30.8 | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | |||||||||||||||||||||||
Impairment, earnings (losses) in joint ventures, and other charges(6) | (375.1 | ) | (10.9 | ) | — | — | — | — | — | |||||||||||||||||||||
Operating income (loss) | $ | (449.9 | ) | $ | 29.4 | $ | 11.2 | $ | 100.0 | $ | 112.3 | $ | 158.5 | $ | 281.6 | |||||||||||||||
Other income (expense)(7) | 0.1 | (0.5 | ) | — | (6.9 | ) | (8.4 | ) | 0.4 | (20.8 | ) | |||||||||||||||||||
Interest (expense) | (11.7 | ) | (1.3 | ) | — | (10.1 | ) | (7.8 | ) | (25.0 | ) | (43.9 | ) | |||||||||||||||||
Gain (loss) on derivatives | (4.2 | ) | 0.3 | — | 0.5 | (7.6 | ) | (316.1 | ) | 94.5 | ||||||||||||||||||||
Income (loss) before income taxes | $ | (465.7 | ) | $ | 27.9 | $ | 11.2 | $ | 83.5 | $ | 88.5 | $ | (182.2 | ) | $ | 311.4 | ||||||||||||||
Income tax (expense) benefit | — | — | — | (33.8 | ) | (36.1 | ) | 63.0 | (119.8 | ) | ||||||||||||||||||||
Net income (loss)(2) | $ | (465.7 | ) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | ||||||||||||||
Pro forma earnings per share, basic | $ | 2.26 | ||||||||||||||||||||||||||||
Pro forma earnings per share, diluted | 2.26 | |||||||||||||||||||||||||||||
Pro forma weighted average shares, basic | 84,716,785 | |||||||||||||||||||||||||||||
Pro forma weighted average shares, diluted | 84,734,285 | |||||||||||||||||||||||||||||
Historical dividends: | ||||||||||||||||||||||||||||||
Preferred per unit(8) | $ | 1.50 | $ | 0.70 | ||||||||||||||||||||||||||
Common per unit(8) | $ | 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 | $ | 0.0 | $ | 52.7 | $ | 64.7 | $ | 41.9 | ||||||||||||||||||||
Working capital(9) | 122.2 | 150.5 | 106.6 | 108.0 | 112.3 | |||||||||||||||||||||||||
Total assets | 172.3 | 199.0 | 229.2 | 1,221.5 | 1,449.5 | |||||||||||||||||||||||||
Liabilities subject to compromise(10) | 105.2 | 105.2 | — | — | — | |||||||||||||||||||||||||
Total debt, including current portion | — | — | 148.9 | 499.4 | 775.0 | |||||||||||||||||||||||||
Minority Interest in subsidiaries(3) | — | — | — | — | 4.3 | |||||||||||||||||||||||||
Management units subject to redemption | — | — | — | 3.7 | 7.0 | |||||||||||||||||||||||||
Divisional/members’ equity | 49.8 | 58.2 | 14.1 | 115.8 | 76.4 | |||||||||||||||||||||||||
Other Financial Data: | ||||||||||||||||||||||||||||||
Depreciation and amortization | $ | 30.8 | $ | 3.3 | $ | 0.4 | $ | 2.4 | $ | 1.1 | $ | 24.0 | $ | 51.0 | ||||||||||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(4) | (465.7 | ) | 27.9 | 11.2 | 49.7 | 52.4 | 23.6 | 115.4 | ||||||||||||||||||||||
Cash flows provided by (used in) operating activities | (1.7 | ) | 20.3 | 53.2 | 89.8 | 12.7 | 82.5 | 186.6 | ||||||||||||||||||||||
Cash flows (used in) investing activities | (272.4 | ) | (0.8 | ) | — | (130.8 | ) | (12.3 | ) | (730.3 | ) | (240.2 | ) | |||||||||||||||||
Cash flows provided by (used in) financing activities | 274.1 | (19.5 | ) | (53.2 | ) | 93.6 | (52.4 | ) | 712.5 | 30.8 |
75
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | ||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | |||||||||||||||||||||||||
2002 | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||||||||
(in millions, except as otherwise indicated) | ||||||||||||||||||||||||||||||
Capital expenditures for property, plant and equipment | 272.4 | 0.8 | — | 14.2 | 12.3 | 45.2 | 240.2 | |||||||||||||||||||||||
Key Operating Statistics: | ||||||||||||||||||||||||||||||
Petroleum Business | ||||||||||||||||||||||||||||||
Production (barrels per day)(5)(11) | 84,343 | 95,701 | 106,645 | 102,046 | 99,171 | 107,177 | 108,031 | |||||||||||||||||||||||
Crude oil throughput (barrels per day)(5)(11) | 74,446 | 85,501 | 92,596 | 90,418 | 88,012 | 93,908 | 94,524 | |||||||||||||||||||||||
Nitrogen Fertilizer Business | ||||||||||||||||||||||||||||||
Production Volume: | ||||||||||||||||||||||||||||||
Ammonia (tons in thousands)(5) | 265.1 | 335.7 | 56.4 | 252.8 | 193.2 | 220.0 | 369.3 | |||||||||||||||||||||||
UAN (tons in thousands)(5) | 434.6 | 510.6 | 93.4 | 439.2 | 309.9 | 353.4 | 633.1 |
(1) | Represents thewrite-off of approximately $2.1 million of property, inventories and catalyst that were destroyed by the flood that occurred on June 30, 2007. See “Flood and Crude Oil Discharge.” | |
(2) | The following are certain charges and costs incurred in each of the relevant periods that are meaningful to understanding our net income and in evaluating our performance due to their unusual or infrequent nature: |
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | ||||||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||||
2002 | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||
Impairment of property, plant and equipment(a) | $ | 375.1 | $ | 9.6 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||||||||||||
Fertilizer lease payments(b) | 0.3 | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||
Loss on extinguishment of debt(c) | — | — | — | 7.2 | 8.1 | — | 23.4 | — | — | |||||||||||||||||||||||||||||
Inventory fair market value adjustment(d) | — | — | — | 3.0 | — | 16.6 | — | — | — | |||||||||||||||||||||||||||||
Funded letter of credit expense and interest rate swap not included in interest expense(e) | — | — | — | — | — | 2.3 | — | 0.6 | 0.2 | |||||||||||||||||||||||||||||
Major scheduled turnaround expense(f) | 17.0 | — | — | 1.8 | — | — | 6.6 | 0.3 | 76.8 | |||||||||||||||||||||||||||||
Loss on termination of swap(g) | — | — | — | — | — | 25.0 | — | — | — | |||||||||||||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | — | — | — | — | 235.9 | (126.8 | ) | 98.2 | 188.5 | ||||||||||||||||||||||||||||
(a) | During the year ended December 31, 2002, we recorded a $375.1 million asset impairment related to the write-down of our refinery and nitrogen fertilizer plant to estimated fair value. During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of our refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. | |
(b) | Reflects the impact of an operating lease structure utilized by Farmland to finance the nitrogen fertilizer plant which operating lease structure is not currently in use. The cost of this plant under the operating lease was $263.0 million and the rental payment was $0.3 million for the period ended December 31, 2002. In February 2002, Farmland refinanced |
76
Table of Contents
the operating lease into a secured loan structure, which effectively terminated the lease and all of Farmland’s obligations under the lease. | ||
(c) | Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004, 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 and thewrite-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006. | |
(d) | Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory. | |
(e) | Consists of fees which are expensed to Selling, general and administrative expenses in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the Credit Facility. | |
(f) | Represents expense associated with a major scheduled turnaround. | |
(g) | Represents the expense associated with the expiration of the crude oil, heating oil and gasoline option agreements entered into by Coffeyville Acquisition LLC in May 2005. |
(3) | Minority interest reflects common stock in two of our subsidiaries owned by John J. Lipinski (which will be exchanged for shares of our common stock with an equivalent value prior to the consummation of this offering). | |
(4) | Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned by Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. With crude oil capacity expected to reach 115,000 bpd by the end of 2007, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods January 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of the Credit Facility and upon meeting specific requirements related to an initial public offering, our leverage ratio and our credit ratings, and assuming our other credit facilities are terminated or amended to allow such actions, we may 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. See “Description of Our Indebtedness and the Cash Flow Swap.” | |
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements, which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for gain or loss from Cash Flow Swap as a key indicator of our business performance. 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 U.S. GAAP net income results as well as Net income adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income 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 adjusted for gain or loss from Cash Flow Swap is not a recognized term under GAAP and should not be substituted for net income as a measure of our performance but instead should be utilized as a supplemental measure of financial performance or liquidity in evaluating our business. Because Net income 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. |
77
Table of Contents
The following is a reconciliation of Net income adjusted for unrealized gain or loss from Cash Flow Swap to Net income: |
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | |||||||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||||||
2002 | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||||||||
Net income (loss) adjusted for unrealized gain (loss) from Cash Flow Swap | $ | (465.7 | ) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | 23.6 | $ | 115.4 | 101.0 | 59.0 | |||||||||||||||||||||
Plus: | ||||||||||||||||||||||||||||||||||||||
Unrealized gain (loss) from Cash Flow Swap, net of tax benefit | — | — | — | — | — | (142.8 | ) | 76.2 | (59.2 | ) | (113.3 | ) | ||||||||||||||||||||||||||
Net income (loss) | $ | (465.7 | ) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | 41.8 | $ | (54.3 | ) | |||||||||||||||||
(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) | Includes the following: |
• | During the year ended December 31, 2002, we recorded a $375.1 million asset impairment related to the write-down of the refinery and nitrogen fertilizer plant to estimated fair value. | |
• | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and 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. |
(7) | During the 304 days ended December 31, 2004, the 174 days ended June 23, 2005 and the year ended December 31, 2006, we recognized a loss of $7.2 million, $8.1 million and $23.4 million, respectively, on early extinguishment of debt. | |
(8) | 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. | |
(9) | Excludes liabilities subject to compromise due to Original Predecessor’s bankruptcy of $105.2 million as of December 31, 2002 and 2003 in calculating Original Predecessor’s working capital. | |
(10) | 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 Bankruptcy Code.”SOP 90-7 requires that pre-petition liabilities be segregated in the Balance Sheet. | |
(11) | 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. |
78
Table of Contents
79
Table of Contents
80
Table of Contents
81
Table of Contents
82
Table of Contents
83
Table of Contents
84
Table of Contents
• | a sale of some or all of our partnership interests to an unrelated party; |
85
Table of Contents
• | 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). |
86
Table of Contents
87
Table of Contents
88
Table of Contents
89
Table of Contents
90
Table of Contents
91
Table of Contents
92
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | ||||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Six Months | ||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | Ended June 30, | ||||||||||||||||||||||||||||
Consolidated Financial Results | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||
(in millions) | (unaudited) | |||||||||||||||||||||||||||||||||
Net sales | $ | 1,262.2 | $ | 261.1 | $ | 1,479.9 | $ | 980.7 | $ | 1,454.3 | $ | 3,037.6 | $ | 1,550.6 | $ | 1,233.9 | ||||||||||||||||||
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 | 1,203.4 | 873.3 | ||||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 133.1 | 23.4 | 117.0 | 80.9 | 85.3 | 199.0 | 87.8 | 174.4 | ||||||||||||||||||||||||||
Selling, general and administrative expense (exclusive of depreciation and amortization) | 23.6 | 4.7 | 16.3 | 18.4 | 18.4 | 62.6 | 20.5 | 28.1 | ||||||||||||||||||||||||||
Costs associated with flood(1) | — | — | — | — | — | — | — | 2.1 | ||||||||||||||||||||||||||
Depreciation and amortization(2) | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | 24.0 | 32.2 | ||||||||||||||||||||||||||
Impairment, (losses) in joint ventures, and other charges(3) | (10.9 | ) | — | — | — | — | — | — | — | |||||||||||||||||||||||||
Operating income | $ | 29.4 | $ | 11.2 | $ | 100.0 | $ | 112.3 | $ | 158.5 | $ | 281.6 | $ | 214.9 | $ | 123.8 | ||||||||||||||||||
Net income (loss)(4) | 27.9 | 11.2 | 49.7 | 52.4 | (119.2 | ) | 191.6 | 41.8 | (54.3 | ) | ||||||||||||||||||||||||
Net income (loss) adjusted for unrealized gain or loss from Cash Flow Swap(5) | 27.9 | 11.2 | 49.7 | 52.4 | 23.6 | 115.4 | 101.0 | 59.0 |
(1) | Represents thewrite-off of approximately $2.1 million of property, inventories and catalyst that were destroyed by the flood that occurred on June 30, 2007. 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: |
Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||
Year | 62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | |||||||||||||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | |||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||||
(in millions) | |||||||||||||||||||||||||||||||||||
(unaudited) | |||||||||||||||||||||||||||||||||||
Depreciation and amortization included in cost of product sold | — | — | 0.2 | 0.1 | 1.1 | 2.2 | 1.0 | 1.2 | |||||||||||||||||||||||||||
Depreciation and amortization included in direct operating expenses | 3.3 | 0.4 | 2.0 | 0.9 | 22.7 | 47.7 | 22.8 | 30.6 | |||||||||||||||||||||||||||
Depreciation and amortization included in selling, general and administrative expense | — | — | 0.2 | 0.1 | 0.2 | 1.1 | 0.2 | 0.4 | |||||||||||||||||||||||||||
Total depreciation and amortization | 3.3 | 0.4 | 2.4 | 1.1 | 24.0 | 51.0 | 24.0 | 32.2 | |||||||||||||||||||||||||||
(3) | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. In addition, we recorded a charge of $1.3 million for the rejection of existing contracts while operating under Chapter 11 of the U.S. Bankruptcy Code. |
93
Table of Contents
(4) | 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 | |||||||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | |||||||||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Six Months Ended | |||||||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | |||||||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||||||||
(in millions) | (unaudited) | ||||||||||||||||||||||||||||||||||||||
Impairment of property, plant and equipment(a) | $ | 9.6 | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | $ | — | |||||||||||||||||||||||
Loss of extinguishment of debt(b) | — | — | 7.2 | 8.1 | — | 23.4 | — | — | |||||||||||||||||||||||||||||||
Inventory fair market value adjustment(c) | — | — | 3.0 | — | 16.6 | — | — | — | |||||||||||||||||||||||||||||||
Funded letter of credit expense & interest rate swap not included in interest expense(d) | — | — | — | — | 2.3 | — | 0.6 | 0.2 | |||||||||||||||||||||||||||||||
Major scheduled turnaround expense(e) | — | — | 1.8 | — | — | 6.6 | 0.3 | 76.8 | |||||||||||||||||||||||||||||||
Loss on termination of swap(f) | — | — | — | — | 25.0 | — | — | — | |||||||||||||||||||||||||||||||
Unrealized (gain) loss from Cash Flow Swap | — | — | — | — | 235.9 | (126.8 | ) | 98.2 | 188.5 |
(a) | During the year ended December 31, 2003, we recorded an additional charge of $9.6 million related to the asset impairment of the refinery and nitrogen fertilizer plant based on the expected sales price of the assets in the Initial Acquisition. | |
(b) | Represents the write-off of $7.2 million of deferred financing costs in connection with the refinancing of our senior secured credit facility on May 10, 2004, 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 and thewrite-off of $23.4 million in connection with the refinancing of our senior secured credit facility on December 28, 2006. | |
(c) | Consists of the additional cost of product sold expense due to the step up to estimated fair value of certain inventories on hand at March 3, 2004 and June 24, 2005, as a result of the allocation of the purchase price of the Initial Acquisition and the Subsequent Acquisition to inventory. | |
(d) | Consists of fees which are expensed to selling, general and administrative expense in connection with the funded letter of credit facility of $150.0 million issued in support of the Cash Flow Swap. We consider these fees to be equivalent to interest expense and the fees are treated as such in the calculation of EBITDA in the Credit Facility. | |
(e) | Represents expenses associated with a major scheduled turnaround at the nitrogen fertilizer plant and our refinery. | |
(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. |
(5) | Net income adjusted for unrealized gain or loss from Cash Flow Swap results from adjusting for the derivative transaction that was executed in conjunction with the Subsequent Acquisition. On June 16, 2005, Coffeyville Acquisition LLC entered into the Cash Flow Swap with J. Aron, a subsidiary of The Goldman Sachs Group, Inc., and a related party of ours. The Cash Flow Swap was subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The derivative took the form of three NYMEX swap agreements whereby if crack spreads fall below the fixed level, J. Aron agreed to pay the difference to us, and if crack spreads rise above the fixed level, we agreed to pay the difference to J. Aron. With crude oil capacity expected to reach 115,000 bpd by the end of 2007, the Cash Flow Swap represents approximately 58% and 14% of crude oil capacity for the periods January 1, 2008 through June 30, 2009 and July 1, 2009 through June 30, 2010, respectively. Under the terms of the Credit Facility and upon meeting specific requirements related to an initial public offering, our leverage ratio and our credit ratings, and assuming our other credit facilities are terminated or amended to allow such actions, we may 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. See “Description of Our Indebtedness and the Cash Flow Swap.” | |
We have determined that the Cash Flow Swap does not qualify as a hedge for hedge accounting purposes under current GAAP. As a result, our periodic statements of operations reflect material amounts of unrealized gains and losses based on the increases or decreases in market value of the unsettled position under the swap agreements which is accounted for as a liability on our balance sheet. As the crack spreads increase we are required to record an increase in this liability account with a corresponding expense entry to be made to our statement of operations. Conversely, as crack spreads decline, we are required to record a decrease in the swap related liability and post a corresponding income entry to our statement of operations. Because of this inverse relationship between the economic outlook for our underlying business (as represented by crack spread levels) and the income impact of the unrecognized gains and losses, and given the significant periodic fluctuations in the amounts of unrealized gains and losses, management utilizes Net income adjusted for gain or loss from |
94
Table of Contents
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 U.S. GAAP net income results as well as Net income adjusted for unrealized gain or loss from Cash Flow Swap. We believe that Net income 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 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 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 adjusted for unrealized gain or loss from Cash Flow Swap to Net income: |
Original Predecessor | Immediate Predecessor | Successor | |||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | ||||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Ended | |||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | |||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||||
(in millions) | (unaudited) | ||||||||||||||||||||||||||||||||||
Net Income (loss) adjusted for unrealized gain or loss from Cash Flow Swap | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | 23.6 | $ | 115.4 | $ | 101.0 | $ | 59.0 | |||||||||||||||||||
Plus: | |||||||||||||||||||||||||||||||||||
Unrealized gain or (loss) from Cash Flow Swap, net of taxes | — | — | — | — | (142.8 | ) | 76.2 | (59.2 | ) | (113.3 | ) | ||||||||||||||||||||||||
Net income (loss) | $ | 27.9 | $ | 11.2 | $ | 49.7 | $ | 52.4 | $ | (119.2 | ) | $ | 191.6 | $ | 41.8 | $ | (54.3 | ) | |||||||||||||||||
95
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | ||||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Six Months Ended | ||||||||||||||||||||||||||||
December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | ||||||||||||||||||||||||||||
2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | |||||||||||||||||||||||||||
(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 | $ | 1,457.7 | $ | 1,161.4 | ||||||||||||||||||
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 | 1,190.5 | 869.1 | ||||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 59.1 | 141.1 | ||||||||||||||||||||||||||
Costs associated with flood | — | — | — | — | — | — | — | 2.0 | ||||||||||||||||||||||||||
Depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 15.6 | 23.1 | ||||||||||||||||||||||||||
Gross profit (loss) | $ | 39.1 | $ | 9.0 | $ | 88.0 | $ | 88.7 | $ | 135.4 | $ | 289.4 | $ | 192.5 | $ | 126.1 | ||||||||||||||||||
Plus direct operating expenses (exclusive of depreciation and amortization) | 80.1 | 14.9 | 73.2 | 52.6 | 56.2 | 135.3 | 59.1 | 141.1 | ||||||||||||||||||||||||||
Plus costs associated with flood | — | — | — | — | — | — | — | 2.0 | ||||||||||||||||||||||||||
Plus depreciation and amortization | 2.1 | 0.3 | 1.5 | 0.8 | 15.6 | 33.0 | 15.6 | 23.1 | ||||||||||||||||||||||||||
Refining margin | $ | 121.3 | $ | 24.2 | $ | 162.7 | $ | 142.1 | $ | 207.2 | $ | 457.7 | $ | 267.2 | $ | 292.3 | ||||||||||||||||||
Refining margin per refinery throughput barrel | $ | 3.89 | $ | 4.23 | $ | 5.92 | $ | 9.28 | $ | 11.55 | $ | 13.27 | $ | 15.69 | 22.71 | |||||||||||||||||||
Gross profit (loss) per refinery throughput barrel | $ | 1.25 | $ | 1.57 | $ | 3.20 | $ | 5.79 | $ | 7.55 | $ | 8.39 | $ | 11.30 | $ | 9.80 | ||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) per refinery throughput barrel | $ | 2.57 | $ | 2.60 | $ | 2.66 | $ | 3.44 | $ | 3.13 | $ | 3.92 | $ | 3.47 | $ | 10.96 | ||||||||||||||||||
Operating income (loss) | 21.5 | 7.7 | 77.1 | 76.7 | 123.0 | 245.6 | 178.0 | 102.9 | ||||||||||||||||||||||||||
Original | ||||||||||||||||||||||||
Predecessor | Immediate | |||||||||||||||||||||||
and Immediate | Predecessor | |||||||||||||||||||||||
Original | Predecessor | and Successor | Successor | |||||||||||||||||||||
Predecessor | Combined | Combined | Successor | Six Months Ended | ||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||
Market Indicators | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||
(dollars per barrel) | ||||||||||||||||||||||||
West Texas Intermediate (WTI) crude oil | $ | 30.99 | $ | 41.47 | $ | 56.70 | $ | 66.25 | $ | 67.13 | $ | 61.67 | ||||||||||||
NYMEX 2-1-1 Crack Spread | 5.53 | 7.43 | 11.62 | 10.84 | 12.02 | 17.13 | ||||||||||||||||||
Crude Oil Differentials: | ||||||||||||||||||||||||
WTI less WTS (sour) | 2.67 | 3.96 | 4.73 | 5.36 | 5.87 | 4.42 | ||||||||||||||||||
WTI less Maya (heavy sour) | 6.78 | 11.40 | 15.67 | 14.99 | 15.88 | 11.20 | ||||||||||||||||||
WTI less Dated Brent (foreign) | 2.16 | 3.20 | 2.18 | 1.13 | 1.47 | (1.54 | ) | |||||||||||||||||
PADD II Group 3 versus NYMEX Basis: | ||||||||||||||||||||||||
Gasoline | 0.62 | (0.52 | ) | (0.53 | ) | 1.52 | 0.74 | 2.59 | ||||||||||||||||
Heating Oil | 1.11 | 1.24 | 3.20 | 7.42 | 5.63 | 9.29 |
96
Table of Contents
Original | ||||||||||||||||||||||||
Predecessor | Immediate | Successor | ||||||||||||||||||||||
and Immediate | Predecessor | Six | ||||||||||||||||||||||
Original | Predecessor | and Successor | Months | |||||||||||||||||||||
Predecessor | Combined | Combined | Successor | Ended | ||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||
Company Operating Statistics | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||
(dollars per barrel) | ||||||||||||||||||||||||
Per barrel profit, margin and expense of crude oil throughput: | ||||||||||||||||||||||||
Refining margin | $ | 3.89 | $ | 5.62 | $ | 10.50 | $ | 13.27 | $ | 15.69 | $ | 22.71 | ||||||||||||
Gross profit | $ | 1.25 | $ | 2.92 | $ | 6.74 | $ | 8.39 | $ | 11.30 | $ | 9.80 | ||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 2.57 | 2.65 | 3.27 | 3.92 | 3.47 | 10.96 | ||||||||||||||||||
Per gallon sales price: | ||||||||||||||||||||||||
Gasoline | 0.91 | 1.19 | 1.61 | 1.88 | 1.94 | 2.09 | ||||||||||||||||||
Distillate | 0.84 | 1.15 | 1.71 | 1.99 | 1.97 | 2.03 |
Original | Immediate | |||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||
and Immediate | and | |||||||||||||||||||||||||||||||||||||||||||||||
Original | Predecessor | Successor | Successor | |||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Combined | Combined | Successor | Six Months Ended | ||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2006 | 2007 | |||||||||||||||||||||||||||||||||||||||||||
Selected Company | Barrels | Barrels | Barrels | Barrels | Barrels | Barrels | ||||||||||||||||||||||||||||||||||||||||||
Volumetric Data | Per Day | % | Per Day | % | Per Day | % | Per Day | % | Per Day | % | Per Day | % | ||||||||||||||||||||||||||||||||||||
Production: | ||||||||||||||||||||||||||||||||||||||||||||||||
Total gasoline | 48,230 | 50.4 | 48,420 | 47.1 | 45,275 | 43.8 | 48,248 | 44.7 | 48,250 | 45.1 | 31,971 | 40.9 | ||||||||||||||||||||||||||||||||||||
Total distillate | 34,363 | 35.9 | 38,104 | 37.1 | 39,997 | 38.7 | 42,175 | 39.0 | 42,275 | 39.5 | 32,592 | 41.7 | ||||||||||||||||||||||||||||||||||||
Total other | 13,108 | 13.7 | 16,301 | 15.9 | 18,090 | 17.5 | 17,608 | 16.3 | 16,390 | 15.3 | 13,535 | 17.3 | ||||||||||||||||||||||||||||||||||||
Total all production | 95,701 | 100.0 | 102,825 | 100.0 | 103,362 | 100.0 | 108,031 | 100.0 | 106,915 | 100.0 | 78,098 | 100.0 | ||||||||||||||||||||||||||||||||||||
Crude oil throughput | 85,501 | 93.4 | 90,787 | 92.8 | 91,097 | 92.6 | 94,524 | 92.1 | 94,083 | 92.8 | 71,098 | 95.0 | ||||||||||||||||||||||||||||||||||||
All other inputs | 6,085 | 6.6 | 7,023 | 7.2 | 7,246 | 7.4 | 8,067 | 7.9 | 7,276 | 7.2 | 3,763 | 5.0 | ||||||||||||||||||||||||||||||||||||
Total feedstocks | 91,586 | 100.0 | 97,810 | 100.0 | 98,343 | 100.0 | 102,591 | 100.0 | 101,359 | 100.0 | 74,861 | 100.0 |
Original | ||||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Immediate | |||||||||||||||||||||||||||||||||||||||||||||||
and Immediate | Predecessor and | |||||||||||||||||||||||||||||||||||||||||||||||
Original | Predecessor | Successor | ||||||||||||||||||||||||||||||||||||||||||||||
Predecessor | Combined | Combined | Successor | Successor | ||||||||||||||||||||||||||||||||||||||||||||
Year Ended December 31, | Six Months Ended June 30, | |||||||||||||||||||||||||||||||||||||||||||||||
2003 | 2004 | 2005 | 2006 | 2006 | 2007 | |||||||||||||||||||||||||||||||||||||||||||
Total | Total | Total | Total | Total | Total | |||||||||||||||||||||||||||||||||||||||||||
Barrels | % | Barrels | % | Barrels | % | Barrels | % | Barrels | % | Barrels | % | |||||||||||||||||||||||||||||||||||||
Crude oil throughput by crude type: | ||||||||||||||||||||||||||||||||||||||||||||||||
Sweet | 18,187,215 | 58.3 | 15,232,022 | 45.8 | 13,958,567 | 42.0 | 17,481,803 | 50.7 | 7,497,863 | 44.0 | 8,364,669 | 65.0 | ||||||||||||||||||||||||||||||||||||
Light/medium sour | 12,311,203 | 39.4 | 17,995,949 | 54.2 | 19,291,951 | 58.0 | 16,695,173 | 48.4 | 9,531,125 | 56.0 | 4,092,254 | 31.8 | ||||||||||||||||||||||||||||||||||||
Heavy sour | 709,300 | 2.3 | — | — | — | — | 324,312 | 0.9 | — | — | 411,799 | 3.2 | ||||||||||||||||||||||||||||||||||||
Total crude oil throughput | 31,207,718 | 100.0 | 33,227,971 | 100.0 | 33,250,518 | 100.0 | 34,501,288 | 100.0 | 17,028,988 | 100.0 | 12,868,722 | 100.0 |
97
Table of Contents
98
Table of Contents
99
Table of Contents
100
Table of Contents
101
Table of Contents
102
Table of Contents
103
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||||||||||||||
62 Days | 304 Days | 174 Days | 233 Days | Year | Six Months | |||||||||||||||||||||||||||||
Year Ended | Ended | Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||||||||||||
Nitrogen Fertilizer | December 31, | March 2, | December 31, | June 23, | December 31, | December 31, | June 30, | |||||||||||||||||||||||||||
Business Financial Results | 2003 | 2004 | 2004 | 2005 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||
(in millions) | (unaudited) | |||||||||||||||||||||||||||||||||
Net sales | $ | 100.9 | $ | 19.4 | $ | 93.4 | $ | 79.3 | $ | 93.7 | $ | 162.5 | $ | 95.6 | $ | 74.3 | ||||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 21.9 | 4.1 | 20.4 | 9.1 | 14.5 | 25.9 | 15.6 | 6.2 | ||||||||||||||||||||||||||
Depreciation and amortization | 1.2 | 0.1 | 0.9 | 0.3 | 8.4 | 17.1 | 8.4 | 8.8 | ||||||||||||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 53.0 | 8.4 | 43.8 | 28.3 | 29.2 | 63.7 | 28.7 | 33.2 | ||||||||||||||||||||||||||
Costs associated with flood | — | — | — | — | — | — | — | 0.1 | ||||||||||||||||||||||||||
Operating income | 7.8 | 3.5 | 22.9 | 35.3 | 35.7 | 36.8 | 37.1 | 21.0 |
Six Months | ||||||||||||||||||||||||
Ended | ||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||
Market Indicators | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||
Natural gas (dollars per million Btu) | $ | 5.49 | $ | 6.18 | $ | 9.01 | $ | 6.98 | $ | 7.24 | $ | 7.41 | ||||||||||||
Ammonia — southern plains (dollars per ton) | 274 | 297 | 356 | 353 | 387 | 395 | ||||||||||||||||||
UAN — corn belt (dollars per ton) | 143 | 171 | 212 | 197 | 208 | 265 |
104
Table of Contents
Original | ||||||||||||||||||||||||
Predecessor | Immediate | |||||||||||||||||||||||
and Immediate | Predecessor | |||||||||||||||||||||||
Original | Predecessor | and Successor | ||||||||||||||||||||||
Predecessor | Combined | Combined | Successor | |||||||||||||||||||||
Six Months | ||||||||||||||||||||||||
Year Ended December 31, | Ended June 30, | |||||||||||||||||||||||
Company Operating Statistics | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||
Production (thousand tons): | ||||||||||||||||||||||||
Ammonia | 335.7 | 309.2 | 413.2 | 369.3 | 205.6 | 169.0 | ||||||||||||||||||
UAN | 510.6 | 532.6 | 663.3 | 633.1 | 328.3 | 304.6 | ||||||||||||||||||
Total | 846.3 | 841.8 | 1,076.5 | 1,002.4 | 533.9 | 473.6 | ||||||||||||||||||
Sales (thousand tons)(1): | ||||||||||||||||||||||||
Ammonia | 134.8 | 103.9 | 141.8 | 117.3 | 66.3 | 34.1 | ||||||||||||||||||
UAN | 528.9 | 541.6 | 646.5 | 645.5 | 339.3 | 293.5 | ||||||||||||||||||
Total | 663.7 | 645.5 | 788.3 | 762.8 | 405.6 | 327.6 | ||||||||||||||||||
Product pricing (plant gate) (dollars per ton)(1): | ||||||||||||||||||||||||
Ammonia | $ | 235 | $ | 266 | $ | 324 | $ | 338 | $ | 376 | $ | 354 | ||||||||||||
UAN | 107 | 136 | 173 | $ | 162 | $ | 181 | $ | 190 | |||||||||||||||
On-stream factor(2): | ||||||||||||||||||||||||
Gasification | 90.1 | % | 92.4 | % | 98.1 | % | 92.5 | % | 97.3 | % | 90.6 | % | ||||||||||||
Ammonia | 89.6 | % | 79.9 | % | 96.7 | % | 89.3 | % | 94.7 | % | 86.8 | % | ||||||||||||
UAN | 81.6 | % | 83.3 | % | 94.3 | % | 88.9 | % | 93.8 | % | 81.9 | % | ||||||||||||
Capacity utilization: | ||||||||||||||||||||||||
Ammonia(3) | 83.6 | % | 76.8 | % | 102.9 | % | 92.0 | % | 103.2 | % | 84.9 | % | ||||||||||||
UAN(4) | 93.3 | % | 97.0 | % | 121.2 | % | 115.6 | % | 120.9 | % | 112.2 | % | ||||||||||||
Reconciliation to net sales (dollars in thousands): | ||||||||||||||||||||||||
Freight in revenue | $ | 12,535 | $ | 11,429 | $ | 15,010 | $ | 17,890 | $ | 9,441 | $ | 6,430 | ||||||||||||
Sales net plant gate | 88,373 | 101,439 | 157,989 | 144,575 | $ | 86,191 | $ | 67,905 | ||||||||||||||||
Total net sales | 100,908 | 112,868 | 172,999 | 162,465 | $ | 95,632 | $ | 74,334 |
(1) | Plant gate sales per ton represents net sales less freight revenue divided by sales tons. Plant gate pricing per ton is shown in order to provide industry comparability. |
(2) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. Excluding the impact of turnarounds at the fertilizer facility in the third quarter of 2004 and 2006, (i) the on-stream factors in 2004 would have been 95.6% for gasification, 82.8% for ammonia and 86.1% for UAN, and (ii) the on-stream factors in 2006 would have been 97.1% for gasification, 94.3% for ammonia and 93.6% for UAN. |
(3) | Based on nameplate capacity of 1,100 tons per day. | |
(4) | Based on nameplate capacity of 1,500 tons per day. |
105
Table of Contents
106
Table of Contents
107
Table of Contents
108
Table of Contents
109
Table of Contents
110
Table of Contents
111
Table of Contents
112
Table of Contents
113
Table of Contents
114
Table of Contents
115
Table of Contents
116
Table of Contents
117
Table of Contents
118
Table of Contents
119
Table of Contents
120
Table of Contents
121
Table of Contents
122
Table of Contents
123
Table of Contents
• | $685.8 million for cash proceeds to Immediate Predecessor ($1,038.9 million of assets acquired less $353.1 million of liabilities assumed), including $12.6 million of legal, accounting, advisory, transaction and other expenses associated with the Subsequent Acquisition; |
124
Table of Contents
• | $49.6 million of other fees and expenses related to the Subsequent Acquisition, including financing fees, risk management fees associated with option premiums for crack spread swaps, and title fees; and | |
• | $4.9 million of cash to fund our operating accounts. |
• | 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). Prior to the December 2006 amendment and restatement, first lien term loans accrued interest at (a) the greater of the prime rate and the federal funds rate plus 0.5%, plus in either case 1.25%, or, at the borrower’s option, (b) LIBOR plus 2.25% (with potential stepdowns to LIBOR plus 2.00% or the prime rate plus 1.00%), and second lien term loans accrued interest at a rate of LIBOR plus 6.75% or, at the borrower’s option, the prime rate plus 5.75%. | |
• | 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). Prior to the December 2006 amendment and restatement, revolving loans under the then-existing first lien credit facility accrued interest at (a) the greater of the prime rate and the federal funds effective rate plus 0.5%, plus in either case 1.50%, or, at the borrower’s option, (b) LIBOR plus 2.50% (with potential stepdowns to LIBOR plus 2.00% or the prime rate plus 1.00%). | |
• | 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; | |
• | 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 |
125
Table of Contents
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; and |
• | 100% of the cash proceeds received by us from any initial public offering or secondary registered offering of equity interests, until the aggregate amount of such proceeds is equal to $280 million. |
Minimum | Maximum | |||||
interest | leverage | |||||
Fiscal quarter ending | coverage ratio | ratio | ||||
June 30, 2007 | 2.50:1.00 | 4.50:1.00 | ||||
September 30, 2007 | 2.75:1.00 | 4.25:1.00 | ||||
December 31, 2007 | 2.75:1.00 | 4.00:1.00 | ||||
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 and thereafter | 3.75:1.00 | 2.25:1.00 to December 31, 2009, 2.00:1.00 thereafter |
126
Table of Contents
Original | ||||||||||||||||||||||||
Predecessor | Immediate | |||||||||||||||||||||||
and Immediate | Predecessor | |||||||||||||||||||||||
Predecessor | and Successor | |||||||||||||||||||||||
Original | Combined | Combined | ||||||||||||||||||||||
Predecessor | (non-GAAP) | (non-GAAP) | Successor | Successor | Successor | |||||||||||||||||||
Six Months Ended | ||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||
Consolidated Financial Results | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||
(unaudited) | (unaudited) | (unaudited) | (unaudited) | |||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||
Net income (loss) | $ | 27.9 | $ | 60.9 | $ | (66.8 | ) | $ | 191.6 | $ | 41.8 | $ | (54.3 | ) | ||||||||||
Plus: | ||||||||||||||||||||||||
Depreciation and amortization | 3.3 | 2.8 | 25.1 | 51.0 | 24.0 | 32.2 | ||||||||||||||||||
Interest expense | 1.3 | 10.1 | 32.8 | 43.9 | 22.3 | 27.6 | ||||||||||||||||||
Income tax expense (benefit) | — | 33.8 | (26.9 | ) | 119.8 | 25.7 | (141.0 | ) | ||||||||||||||||
Impairment of property, plant and equipment | 9.6 | — | — | — | — | — | ||||||||||||||||||
Loss on extinguishment of debt | — | 7.2 | 8.1 | 23.4 | — | — | ||||||||||||||||||
Inventory fair market value adjustment | — | 3.0 | 16.6 | — | — | — | ||||||||||||||||||
Funded letters of credit expenses and interest rate swap not included in interest expense | — | — | 2.3 | — | 0.6 | 0.2 | ||||||||||||||||||
Major scheduled turnaround expense | — | 1.8 | — | 6.6 | 0.3 | 76.8 | ||||||||||||||||||
Loss on termination of Swap | — | — | 25.0 | — | — | — | ||||||||||||||||||
Unrealized (gain) or loss on derivatives | — | — | 229.8 | (128.5 | ) | 92.1 | 190.0 | |||||||||||||||||
Non-cash compensation expense for equity awards | — | 1.1 | 1.8 | 16.9 | 2.3 | 6.8 | ||||||||||||||||||
(Gain) or loss on disposition of fixed assets | — | — | — | 1.2 | 0.4 | 1.2 | ||||||||||||||||||
Expenses related to acquisition | — | — | 3.5 | — | — | — | ||||||||||||||||||
Minority interest in subsidiaries | — | — | — | — | — | (0.2 | ) | |||||||||||||||||
Management fees | — | 0.5 | 2.3 | 2.3 | 1.0 | 1.1 | ||||||||||||||||||
Consolidated adjusted EBITDA | $ | 42.1 | $ | 121.2 | $ | 253.6 | $ | 328.2 | $ | 210.5 | $ | 140.4 | ||||||||||||
127
Table of Contents
128
Table of Contents
• | $25 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25 million senior secured term loan (the “$25 million secured facility”). The facility is secured by the same collateral that secures our existing Credit Facility. Interest is payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. As of September 30, 2007, $25 million was outstanding under this facility. | |
• | $25 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25 million senior unsecured term loan (the “$25 million unsecured facility”). Interest is payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. As of September 30, 2007, $25 million was outstanding under this facility. | |
• | $75 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75 million senior unsecured term loan (the “$75 million unsecured facility”). Drawings may be made from time to time in amounts of at least $5 million. Interest accrues, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest is paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrues and is paid by adding such fees to the principal amount of loans outstanding. As of September 30, 2007, $0.0 million was drawn under this facility. |
129
Table of Contents
• | 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 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 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 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35 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 |
130
Table of Contents
plus 1.50%. The letter agreement also amended the Cash Flow Swap to incorporate by reference the negative and financial covenants contained in Coffeyville Resources, LLC’s new $25 million senior secured credit agreement entered into in August 2007. |
131
Table of Contents
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental capital needs | $ | 144.6 | $ | 128.2 | $ | 28.2 | $ | 39.8 | $ | 42.2 | $ | 2.6 | $ | 2.1 | $ | 387.7 | ||||||||||||||||
Sustaining capital needs | 11.8 | 21.2 | 24.4 | 22.0 | 22.0 | 22.0 | 22.0 | 145.4 | ||||||||||||||||||||||||
156.4 | 149.4 | 52.6 | 61.8 | 64.2 | 24.6 | 24.1 | 533.1 | |||||||||||||||||||||||||
Major scheduled turnaround expenses | 4.0 | 77.0 | — | — | 50.0 | — | — | 131.0 | ||||||||||||||||||||||||
Total estimated non-discretionary spending | $ | 160.4 | $ | 226.4 | $ | 52.6 | $ | 61.8 | $ | 114.2 | 24.6 | 24.1 | $ | 664.1 |
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental capital needs | $ | 0.1 | $ | 0.7 | $ | 3.3 | $ | 2.9 | $ | 2.6 | 2.7 | 3.8 | $ | 16.1 | ||||||||||||||||||
Sustaining capital needs | 6.6 | 2.9 | 7.1 | 3.7 | 4.5 | 4.8 | 4.3 | 33.9 | ||||||||||||||||||||||||
6.7 | 3.6 | 10.4 | 6.6 | 7.1 | 7.5 | 8.1 | 50.0 | |||||||||||||||||||||||||
Major scheduled turnaround expenses | 2.6 | — | 2.3 | — | 2.6 | — | 2.8 | 10.3 | ||||||||||||||||||||||||
Total estimated non-discretionary spending | $ | 9.3 | $ | 3.6 | $ | 12.7 | $ | 6.6 | $ | 9.7 | $ | 7.5 | $ | 10.9 | $ | 60.3 |
132
Table of Contents
2006 | 2007 | 2008 | 2009 | 2010 | 2011 | 2012 | Cumulative | |||||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||||||
Environmental capital needs | $ | 144.7 | $ | 128.9 | $ | 31.5 | $ | 42.7 | $ | 44.8 | 5.3 | 5.9 | $ | 403.8 | ||||||||||||||||||
Sustaining capital needs | 18.4 | 24.1 | 31.5 | 25.7 | 26.5 | 26.8 | 26.3 | 179.3 | ||||||||||||||||||||||||
163.1 | 153.0 | 63.0 | 68.4 | 71.3 | 32.1 | 32.2 | 583.1 | |||||||||||||||||||||||||
Major scheduled turnaround expenses | 6.6 | 77.0 | 2.3 | — | 52.6 | — | 2.8 | 141.3 | ||||||||||||||||||||||||
Total estimated non-discretionary spending | $ | 169.7 | $ | 230.0 | $ | 65.3 | $ | 68.4 | $ | 123.9 | 32.1 | 35.0 | $ | 724.4 |
133
Table of Contents
134
Table of Contents
135
Table of Contents
136
Table of Contents
137
Table of Contents
138
Table of Contents
139
Table of Contents
140
Table of Contents
141
Table of Contents
Payments Due by Period | ||||||||||||||||||||||||||||
Six Months | ||||||||||||||||||||||||||||
Ending | ||||||||||||||||||||||||||||
December 31, | ||||||||||||||||||||||||||||
Total | 2007 | 2008 | 2009 | 2010 | 2011 | Thereafter | ||||||||||||||||||||||
(in millions) | ||||||||||||||||||||||||||||
Contractual Obligations | ||||||||||||||||||||||||||||
Long-term debt(1) | $ | 823.1 | $ | 3.9 | $ | 57.7 | $ | 7.6 | $ | 7.5 | $ | 7.4 | $ | 739.0 | ||||||||||||||
Operating leases(2) | 11.1 | 1.7 | 3.9 | 2.9 | 1.6 | 0.9 | 0.1 | |||||||||||||||||||||
Unconditional purchase obligations(3) | 516.9 | 13.0 | 21.1 | 21.1 | 46.2 | 44.3 | 371.2 | |||||||||||||||||||||
Environmental liabilities(4) | 9.7 | 1.0 | 1.0 | 0.9 | 0.6 | 0.3 | 5.9 | |||||||||||||||||||||
Funded letter of credit fees(5) | 15.9 | 2.7 | 5.3 | 5.3 | 2.6 | — | — | |||||||||||||||||||||
Interest payments(6) | 407.3 | 35.4 | 69.8 | 66.0 | 65.3 | 64.6 | 106.2 | |||||||||||||||||||||
Total | $ | 1,784.0 | $ | 57.7 | $ | 158.8 | $ | 103.8 | $ | 123.8 | $ | 117.5 | $ | 1,222.4 | ||||||||||||||
Other Commercial Commitments | ||||||||||||||||||||||||||||
Standby letters of credit(7) | $ | 33.8 | $ | 33.8 | $ | — | $ | — | $ | — | $ | — | $ | — |
(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. Subsequent to June 30, 2007, we entered into three additional credit facilities totaling $125 million. As of September 30, 2007, $50 million was outstanding under these new facilities. See “Description of Our Indebtedness and the Cash Flow Swap.” | |
(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 our estimated payments required by federaland/or state environmental agencies related to closure of hazardous waste management units at our sites in Coffeyville and Phillipsburg, Kansas. 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 June 30, 2007 and assume contractual amortization payments. | |
(7) | Standby letters of credit include our obligations under $3.2 million of letters of credit issued in connection with environmental liabilities and $30.6 million in letters of credit to secure transportation expenses related to the Transportation Services Agreement with CCPS Transportation, LLC. |
142
Table of Contents
143
Table of Contents
144
Table of Contents
• | lock in or fix a percentage of the anticipated or planned gross margin in future periods when the derivative market offers commodity spreads that generate positive cash flows; and | |
• | hedge the value of inventories in excess of minimum required inventories. |
• | Time Basis — In enteringover-the-counter swap agreements, the settlement price of the swap is typically the average price of the underlying commodity for a designated calendar period. This settlement price is based on the assumption that the underling physical commodity will price ratably over the swap period. If the commodity does not move ratably over the periods then weighted average physical prices will be weighted differently than the swap price as the result of timing. | |
• | Location Basis — In hedging NYMEX crack spreads, we experience location basis as the settlement of NYMEX refined products (related more to New York Harbor cash markets) which may be different than the prices of refined products in our Group 3 pricing area. |
145
Table of Contents
• | Successor’s Petroleum Segment holds commodity derivative contracts in the form of three swap agreements for the period from July 1, 2005 to June 30, 2010 with J. Aron, a subsidiary of The Goldman Sachs Group, Inc. and a related party of ours. The swap agreements were originally executed on June 16, 2005 in conjunction with the Subsequent Acquisition of Immediate Predecessor and required under the terms of our long-term debt agreements. These agreements were subsequently assigned from Coffeyville Acquisition LLC to Coffeyville Resources, LLC on June 24, 2005. The total notional quantities on the date of execution were 100,911,000 barrels of crude oil; 2,348,802,750 gallons of unleaded gasoline and 1,889,459,250 gallons of heating oil; pursuant to these swaps, we receive a fixed price with respect to the heating oil and the unleaded gasoline while we pay a fixed price with respect to crude oil. In June 2006, a subsequent swap was entered into with J. Aron to effectively reduce our unleaded notional quantity and increase our heating oil notional quantity by 229,671,750 gallons over the period July 2, 2007 to June 30, 2010. Additionally, several other swaps were entered into with J. Aron to adjust effective net notional amounts of the aggregate position to better align with actual production volumes. The swap agreements were executed at the prevailing market rate at the time of execution and management believed the swap agreements would provide an economic hedge on future transactions. At June 30, 2007 the net notional open amounts under these swap agreements were 54,783,750 barrels of crude oil, 1,148,358,750 gallons of heating oil and 1,152,558,750 gallons of unleaded gasoline. The purpose of these contracts is to economically hedge 27,341,875 barrels of heating oil crack spreads, the price spread between crude oil and heating oil, and 27,441,876 barrels of unleaded gasoline crack spreads, the price spread between crude oil and unleaded gasoline. These open contracts had a total unrealized net loss at June 30, 2007 of approximately $188.5 million. | |
• | Successor’s Petroleum Segment also holds various NYMEX positions through UBS Securities LLC. At June 30, 2007, we were short 250 crude contracts, 90 heating oil contracts and 150 unleaded contracts, reflecting an unrealized loss of $0.8 million on that date. |
146
Table of Contents
Effective | Termination | Fixed | ||||||||||
Notional Amount | Date | Date | Rate | |||||||||
$325.0 million | 6/29/07 | 3/30/08 | 4.195% | |||||||||
$250.0 million | 3/31/08 | 3/30/09 | 4.195% | |||||||||
$180.0 million | 3/31/09 | 3/30/10 | 4.195% | |||||||||
$110.0 million | 3/31/10 | 6/29/10 | 4.195% |
147
Table of Contents
148
Table of Contents
149
Table of Contents
150
Table of Contents
151
Table of Contents
152
Table of Contents
153
Table of Contents
Ammonia | UAN 32 | |||||||
State | Quantity | Quantity | ||||||
(thousand tons per year) | ||||||||
Texas | 2,300 | 850 | ||||||
Oklahoma | 80 | 225 | ||||||
Kansas | 370 | 670 | ||||||
Missouri | 325 | 250 | ||||||
Iowa | 690 | 865 | ||||||
Nebraska | 335 | 1,100 | ||||||
Minnesota | 335 | 195 |
154
Table of Contents
Natural Gas | WTI | Ammonia | ||||||||||
Year | ($/million btu) | ($/bbl) | ($/ton) | |||||||||
1990 | 1.78 | 24.53 | 125 | |||||||||
1991 | 1.53 | 21.55 | 130 | |||||||||
1992 | 1.73 | 20.57 | 134 | |||||||||
1993 | 2.11 | 18.43 | 139 | |||||||||
1994 | 1.94 | 17.16 | 197 | |||||||||
1995 | 1.69 | 18.38 | 238 | |||||||||
1996 | 2.50 | 22.01 | 217 | |||||||||
1997 | 2.48 | 20.59 | 220 | |||||||||
1998 | 2.16 | 14.43 | 162 | |||||||||
1999 | 2.32 | 19.26 | 145 | |||||||||
2000 | 4.32 | 30.28 | 208 | |||||||||
2001 | 4.06 | 25.92 | 262 | |||||||||
2002 | 3.39 | 26.19 | 191 | |||||||||
2003 | 5.49 | 31.03 | 292 | |||||||||
2004 | 5.90 | 41.47 | 326 | |||||||||
2005 | 8.92 | 56.58 | 394 | |||||||||
2006 | 6.73 | 66.09 | 379 | |||||||||
2007 (through June 30) | 7.36 | 61.58 | 432 |
155
Table of Contents
156
Table of Contents
• | Construction of a new 23,000 bpd high pressure diesel hydrotreater and associated new sulfur recovery unit, which will allow the facility to meet the EPA Tier II Ultra Low Sulfur Diesel federal regulations; and | |
• | Expansion of one of the two gasification units within the fertilizer complex, which is expected to increase ammonia production by over 6,500 tons per year. |
• | Refinery-wide capacity expansion by increasing throughput of the existing fluid catalytic cracking unit (the unit that converts gas oil from the crude unit or coker unit into liquified petroleum gas, distillates and gasoline blendstocks), the delayed coker (the unit that processes heavy feedstock and produces lighter products and pet coke), and other major process units; and | |
• | Construction of a new grass roots 24,000 bpd continuous catalytic reformer to be completed by the end of 2007. |
157
Table of Contents
158
Table of Contents
159
Table of Contents
• | Pursuing opportunities to expand UAN production and other efficiency-based projects. The nitrogen fertilizer business is pursuing a project that is expected to increase UAN production through the addition of a nitric acid plant, as a result of which the UAN manufacturing facility would substantially consume all of our net ammonia production. The UAN expansion is expected to be completed in 2010 and would result in an approximate 400,000 ton increase in annual UAN production. We believe that this expansion would help to improve our margins as UAN is a higher margin product as compared to ammonia. In addition, the nitrogen fertilizer business is expected to pursue several efficiency-based capital projects in order to reduce overall operating costs, or incrementally increase ammonia production for the nitrogen fertilizer business. | |
• | Leveraging the Partnership’s relationship with our petroleum business. We expect that over time, as our petroleum business grows, it will need incremental pipeline transportation and storage infrastructure services. The Partnership will be well-situated to meet these needs due to its historic relationship with and proximity to our petroleum facilities, combined with management’s knowledge and expertise in hydrocarbon storage and related disciplines. The Partnership may seek to acquire new assets (including pipeline assets and storage facilities) in order to service this potential new source of revenue from our petroleum business. | |
• | Acquiring assets from the petroleum business. The Partnership may seek to purchase specific assets from our petroleum business and enter into agreements with the refinery for crude oil transportation, crude oil storage and refined fuels terminalling services. Examples of assets under consideration include our crude gathering pipeline operations serving central |
160
Table of Contents
Kansas, northern Oklahoma, and southwest Nebraska, the refined fuels terminal operations in Phillipsburg, Kansas and our real estate in Cushing, Oklahoma purchased for the future construction of crude oil storage tanks. We have no agreements or understandings with respect to any such acquisitions or agreements at the present time. |
• | Pursuing opportunities in CO2 sequestration. The nitrogen fertilizer business is currently evaluating a development plan to either sell the currently vented 850,000 tons per year of high purity anthropogenic CO2 produced by the nitrogen fertilizer facilities into the enhanced oil recovery market or to pursue an economic means of geologically sequestering the CO2. This project is currently in development, but is expected to result in economic benefits including the direct sale of CO2 and the sale of verified emission credits on the open market should the credits accrete value in the future due to the implementation of mandatory emission caps for CO2. | |
• | Constructing a third gasification unit in the nitrogen fertilizer plant. The nitrogen fertilizer business intends to pursue the feasibility of the construction and operation of an additional gasification unit to produce a synthesis gas from petroleum coke. It is expected that the addition of a third gasification unit and an additional ammonia and UAN manufacturing facility to the nitrogen fertilizer operations could result, on a long-term basis, in an approximate 1.0 million ton per year increase in UAN production. This project is in its earliest stages of review and is still subject to numerous levels of internal analysis. |
• | Prior to the consummation of this offering, Coffeyville Acquisition LLC will redeem all of its outstanding common units held by the Goldman Sachs Funds, who will receive the same number of common units in Coffeyville Acquisition II LLC, a newly formed limited liability company to which Coffeyville Acquisition LLC will transfer half of its interests in each of |
161
Table of Contents
Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy. In addition, half of the common units and half of the profits interests in Coffeyville Acquisition LLC held by our executive officers will be redeemed in exchange for an equal number and type of limited liability interests in Coffeyville Acquisition II LLC. Following these redemptions, the Kelso Funds will own substantially all of the common units of Coffeyville Acquisition LLC, the Goldman Sachs Funds will own substantially all of the common units of Coffeyville Acquisition II LLC and our executive officers will own an equal number and type of interests in both Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC will own 50% of each of Coffeyville Refining & Marketing Holdings, Coffeyville Nitrogen Fertilizers and CVR Energy. |
• | Following the redemptions by Coffeyville Acquisition LLC, we will merge a newly formed direct subsidiary of ours with Coffeyville Refining & Marketing Holdings, Inc. (which owns Coffeyville Refining & Marketing, Inc.) and merge a separate newly formed direct subsidiary of ours with Coffeyville Nitrogen Fertilizers which will make Coffeyville Refining & Marketing and Coffeyville Nitrogen Fertilizers wholly owned subsidiaries of ours. These transactions will result in a structure with CVR Energy below Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC and above its two subsidiaries, so that CVR Energy will become the parent of the two subsidiaries. CVR Energy has not commenced operations and has no assets or liabilities. In addition, there are no contingent liabilities and commitments attributable to CVR Energy. The mergers provide a tax free means to put an appropriate organizational structure in place to go public and give CVR Energy the flexibility to simplify its structure in a tax efficient manner in the future if necessary. | |
• | In addition, we will transfer our nitrogen fertilizer business into a newly formed limited partnership and we will sell all of the interests of the managing general partner of this partnership to an entity owned by our controlling stockholders and senior management at fair market value on the date of the transfer. |
162
Table of Contents
• | Crude Oil Gathering System. We own and operate a 25,000 bpd crude oil gathering system comprised of over 300 miles of feeder and trunk pipelines, 40 trucks and associated storage facilities for gathering light, sweet Kansas and Oklahoma crude oils purchased from independent crude producers. We have also leased a section of a pipeline from Magellan Pipeline Company, L.P. that will allow us to gather additional volumes of attractively priced quality crudes. | |
• | Phillipsburg Terminal. We own storage and terminalling facilities for asphalt and refined fuels at Phillipsburg, Kansas. Our asphalt storage and terminalling facilities are used to receive, store and redeliver asphalt for another oil company for a fee pursuant to an asphalt services agreement. |
Six Months | ||||||||||||||||||||||||||||
Ended | ||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||||||
2002 | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||
(in barrels) | ||||||||||||||||||||||||||||
Crude oil | 27,172,830 | 31,207,718 | 33,227,971 | 33,250,518 | 34,501,288 | 17,028,988 | 12,868,722 | |||||||||||||||||||||
Natural gasoline | 1,093,629 | 483,362 | 317,874 | 455,587 | 373,667 | 163,371 | 48,996 | |||||||||||||||||||||
Normal butane | — | — | 530,575 | 467,176 | 483,131 | 163,116 | 135,680 | |||||||||||||||||||||
Isobutane | 1,037,855 | 1,627,989 | 1,615,898 | 1,398,694 | 1,460,893 | 745,698 | 380,111 | |||||||||||||||||||||
Alky feed | — | — | — | 68,636 | 170,542 | 24,796 | 14,075 | |||||||||||||||||||||
Gas oil | — | — | — | 155,344 | 425,319 | 189,744 | 69,272 | |||||||||||||||||||||
Vacuum tower bottom | 98,371 | 109,974 | 105,981 | 99,362 | 30,717 | 30,208 | 33,072 | |||||||||||||||||||||
Total Inputs | 29,402,685 | 33,429,043 | 35,798,299 | 35,895,317 | 37,445,557 | 18,345,921 | 13,549,928 | |||||||||||||||||||||
163
Table of Contents
Nominal | ||||
Pipeline | Capacity (bpd) | |||
Seaway Pipeline (TEPPCO) from U.S. Gulf Coast to Cushing, Oklahoma | 350,000 | |||
Spearhead (CCPS/Enbridge) from Griffith (Chicago) to Cushing, Oklahoma | 125,000 | |||
Coffeyville Crude Oil Pipeline System from Caney, Kansas to Oil Refinery | 145,000 | |||
Coffeyville Crude Oil Gathering and Trucking System | 25,000 | |||
Natural Gas Liquid (NGL) Connection from/to Conway, Kansas through MAPCO and ONEOK | 15,000 | |||
Plains-Cushing to Caney, Kansas | 97,000 | |||
Sun Logistics Pipeline from U.S.G.C. to Cushing, Oklahoma | 120,000 |
• | Gasoline. Gasoline typically accounts for approximately 43% of our refinery’s production. Our oil refinery produces various grades of gasoline, ranging from 84 sub-octane regular unleaded to 91 octane premium unleaded and uses a computerized component blending system to optimize gasoline blending. | |
• | Distillates. Distillates typically account for approximately 44% of the refinery’s production. The majority of the diesel fuel we produce is ultra low-sulfur. |
164
Table of Contents
Six Months | ||||||||||||||||||||||||||||
Ended | ||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||||||
2002 | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||
(in barrels) | ||||||||||||||||||||||||||||
Gasoline: | ||||||||||||||||||||||||||||
Regular unleaded | 14,071,304 | 16,531,362 | 16,703,566 | 16,154,172 | 16,836,946 | 8,382,403 | 5,737,930 | |||||||||||||||||||||
Premium unleaded | 306,334 | 298,789 | 220,908 | 261,467 | 479,211 | 270,207 | 48,857 | |||||||||||||||||||||
Sub-octane unleaded | 754,264 | 773,831 | 797,416 | 109,774 | 294,356 | 80,599 | — | |||||||||||||||||||||
Total gasoline | 15,131,902 | 17,603,982 | 17,721,890 | 16,525,413 | 17,610,513 | 8,733,209 | 5,786,787 | |||||||||||||||||||||
Distillate: | ||||||||||||||||||||||||||||
Kerosene | 26,085 | 25,149 | 23,256 | 32,302 | 22,195 | (5,542 | ) | 10,261 | ||||||||||||||||||||
Jet fuel | — | — | — | — | — | — | — | |||||||||||||||||||||
No. 1 distillate | 124,741 | 342,363 | 99,832 | 261,048 | 319,920 | 3,272 | 37,266 | |||||||||||||||||||||
No. 2 low sulfur distillate | 6,526,883 | 7,899,132 | 8,896,701 | 9,129,518 | 11,583,942 | 5,599,539 | 5,789,899 | |||||||||||||||||||||
No. 2 high sulfur distillate | 2,268,116 | 3,017,785 | 3,500,351 | 3,916,658 | 3,441,683 | 2,031,624 | — | |||||||||||||||||||||
Diesel | 1,923,370 | 1,258,279 | 1,425,897 | 1,259,308 | 26,113 | 22,869 | 61,732 | |||||||||||||||||||||
Total distillate | 10,869,195 | 12,542,708 | 13,946,037 | 14,598,834 | 15,393,853 | 7,651,762 | 5,899,158 | |||||||||||||||||||||
Liquid by-products: | ||||||||||||||||||||||||||||
NGL (propane, butane) | 583,095 | 734,737 | 1,137,645 | 696,637 | 705,869 | 342,989 | 226,004 | |||||||||||||||||||||
Slurry | 445,784 | 532,236 | 500,692 | 562,657 | 706,332 | 375,492 | 225,119 | |||||||||||||||||||||
Light cycle oil sales | 84,146 | 42,571 | — | — | — | — | — | |||||||||||||||||||||
VTB sales | 8,212 | 26,438 | 150,700 | 134,899 | 74,979 | 25,949 | — | |||||||||||||||||||||
Reformer feed sales | — | — | 79,906 | 230,785 | 357,411 | 180,360 | 52,304 | |||||||||||||||||||||
Gas oil sales | 84,673 | — | — | 66,274 | — | — | 18,860 | |||||||||||||||||||||
Total liquid by-products | 1,205,910 | 1,335,982 | 1,868,943 | 1,691,252 | 1,844,591 | 924,790 | 552,287 | |||||||||||||||||||||
Solid by-products: | ||||||||||||||||||||||||||||
Coke | 2,068,031 | 1,956,619 | 2,384,414 | 2,439,297 | 2,491,867 | 1,273,412 | 877,611 | |||||||||||||||||||||
Sulfur | 74,226 | 131,137 | 88,744 | 100,035 | 94,117 | 44,755 | 37,616 | |||||||||||||||||||||
Total solid by-products | 2,142,257 | 2,087,756 | 2,473,158 | 2,539,332 | 2,585,984 | 1,318,167 | 915,227 | |||||||||||||||||||||
NGL production | 52,682 | (8,539 | ) | — | 548,883 | 519,986 | 218,419 | 284,959 | ||||||||||||||||||||
In process change | 114,945 | (120,122 | ) | (12,369 | ) | 265,280 | (243,553 | ) | (307,639 | ) | 88,674 | |||||||||||||||||
Produced fuel | 1,268,388 | 1,489,030 | 1,636,665 | 1,557,689 | 1,719,345 | 812,823 | 638,648 | |||||||||||||||||||||
Processing loss (gain) | (1,382,594 | ) | (1,501,754 | ) | (1,836,025 | ) | (1,831,366 | ) | (1,985,162 | ) | (1,005,610 | ) | (585,812 | ) | ||||||||||||||
Total yields | 29,402,685 | 33,429,043 | 35,798,299 | 35,895,317 | 37,445,557 | 18,345,921 | 13,549,928 |
165
Table of Contents
Product | Capacity (barrels) | |||
Gasoline | 767,000 | |||
Distillates | 1,068,000 | |||
Intermediates | 1,004,000 | |||
Crude oil(1) | 2,594,000 |
(1) | Crude oil storage consists of 674,000 barrels of refinery storage capacity, 520,000 barrels of field storage capacity and 1,400,000 barrels of leased storage at Cushing, Oklahoma. |
Pipeline | Capacity (bpd) | |||
Magellan Pipeline #3-8” Line (from Coffeyville to northern cities via Caney, Kansas) | 32,000 | |||
Magellan Pipeline #2-10” Line (from Coffeyville to northern cities via Barnsdall, Oklahoma) | 81,000 | |||
Enterprise Pipeline (provides accessibility to Magellan (Mountain) and Valero systems at El Dorado, Kansas) | 12,000 | |||
Truck Loading Rack Delivery System | 40,000 |
166
Table of Contents
167
Table of Contents
Six Months | ||||||||||||||||||||||||||||||||
Ended | ||||||||||||||||||||||||||||||||
Year Ended December 31, | June 30, | |||||||||||||||||||||||||||||||
2002 | 2003 | 2004 | 2005 | 2006 | 2006 | 2007 | ||||||||||||||||||||||||||
Gasifier on-stream(1) | 78.6% | 90.1% | 92.4% | 98.1% | 92.5% | 97.3% | 90.6% | |||||||||||||||||||||||||
Ammonia capacity utilization(2) | 66.0% | 83.6% | 76.8% | 102.9% | 92.0% | 103.2% | 84.9% | |||||||||||||||||||||||||
UAN capacity utilization(3) | 79.4% | 93.3% | 97.0% | 121.2% | 115.6% | 120.9% | 112.2% |
(1) | On-stream factor is the total number of hours operated divided by the total number of hours in the reporting period. | |
(2) | Based on nameplate capacity of 1,100 tons per day. | |
(3) | Based on nameplate capacity of 1,500 tons per day. |
168
Table of Contents
169
Table of Contents
170
Table of Contents
171
Table of Contents
Crude Capacity | Solomon | |||||||||||
(barrels per | Complexity | |||||||||||
Company | Location | calendar day) | Index | |||||||||
ConocoPhillips | Ponca City, OK | 187,000 | 12.5 | |||||||||
CVR Energy | Coffeyville, KS | 113,500 | 10.0 | |||||||||
Frontier Oil | El Dorado, KS | 110,000 | 13.3 | |||||||||
Valero | Ardmore, OK | 88,000 | 11.3 | |||||||||
NCRA | McPherson, KS | 82,200 | 14.1 | |||||||||
Gary Williams Energy | Wynnewood, OK | 52,500 | 8.0 | |||||||||
Sinclair | Tulsa, OK | 50,000 | 8.3 | |||||||||
Mid-continent Total: | 677,700 | |||||||||||
172
Table of Contents
• | restrictions on operationsand/or the need to install enhanced or additional controls; | |
• | the need to obtain and comply with permits and authorizations; |
173
Table of Contents
• | 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 marketed by our petroleum business and the nitrogen fertilizer business, primarily gasoline, diesel fuel, UAN and ammonia. |
174
Table of Contents
175
Table of Contents
176
Table of Contents
177
Table of Contents
Total | ||||||||||||||||
Site | Total O&M | Estimated | ||||||||||||||
Investigation | Capital | Costs | Costs | |||||||||||||
Facility | Costs | Costs | Through 2011 | Through 2011 | ||||||||||||
Coffeyville Oil Refinery | $ | 0.3 | $ | – | $ | 0.6 | $ | 0.9 | ||||||||
Phillipsburg Terminal | 0.4 | – | 1.6 | 2.0 | ||||||||||||
Total Estimated Costs | $ | 0.7 | $ | – | $ | 2.2 | $ | 2.9 | ||||||||
178
Table of Contents
179
Table of Contents
• | services by our employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall 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; | |
• | managing the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; |
180
Table of Contents
• | recommending capital raising activities to the board of directors of the managing general partner of the Partnership 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; |
• | 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 | |||
Kansas City, KS | 18,400 (square feet) | Lease | Office space |
181
Table of Contents
182
Table of Contents
• | 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, 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. |
183
Table of Contents
184
Table of Contents
185
Table of Contents
• | Our primary property damage and business interruption insurance program provides $300 million of coverage forflood-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 provides coverage for property damage to buildings in the course of construction. Flood-related loss or damage is subject to a $100,000 deductible and sub-limit of $50 million. | |
• | Our environmental insurance coverage program provides 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 million aggregate limit of liability. This policy was subject to a $1 million self-insured retention and to a sub-limit of $10 million applicable to cleanup costs. In addition, at the time of the flood we had a $25 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 provides $100 million of coverage excess of $5 million and other applicable insurance for third-party claims of property damage and bodily injury arising out of the discharge of pollutants. |
186
Table of Contents
Name | Age | Position | ||||
John J. Lipinski | 56 | Chairman of the Board of Directors, Chief Executive Officer and President | ||||
Stanley A. Riemann | 56 | Chief Operating Officer | ||||
James T. Rens | 41 | Chief Financial Officer and Treasurer | ||||
Edmund S. Gross | 56 | Senior Vice President, General Counsel and Secretary | ||||
Robert W. Haugen | 49 | Executive Vice President, Refining Operations | ||||
Wyatt E. Jernigan | 55 | Executive Vice President, Crude Oil Acquisition and Petroleum Marketing | ||||
Kevan A. Vick | 53 | Executive Vice President and Fertilizer General Manager | ||||
Christopher G. Swanberg | 49 | Vice President, Environmental, Health and Safety | ||||
Wesley Clark | 62 | Director | ||||
Scott L. Lebovitz | 32 | Director | ||||
Regis B. Lippert | 67 | Director | ||||
George E. Matelich | 51 | Director | ||||
Stanley de J. Osborne | 36 | Director | ||||
Kenneth A. Pontarelli | 37 | Director | ||||
Mark Tomkins | 52 | Director |
187
Table of Contents
188
Table of Contents
189
Table of Contents
190
Table of Contents
191
Table of Contents
192
Table of Contents
• | 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 stake holders. |
193
Table of Contents
194
Table of Contents
• | Stan A. Riemann, our Chief Operating Officer, was responsible for the following key developments during 2006: (1) successful coordination of capital and expansion projects between our refining business and our nitrogen fertilizer business; (2) oversight of our improved crude oil gathering, storage and purchasing system which resulted in enhanced margins in our refining business; (3) revisions to our fertilizer sales effort, resulting in higher netbacks (unit price of fertilizer offered on a delivered basis, excluding shipping costs); and (4) realignment of the operating responsibilities of our senior management and other key employees in order to improve our day to day operations and facility safety. | |
• | James T. Rens, our Chief Financial Officer and Treasurer, was responsible for the following major achievements: (1) increasing the reliability and security of our computer information systems, including through the identification and hiring of a new chief information officer; (2) coordinating among management, underwriters, equity holders, auditors and counsel in connection with our initial public offering; (3) identification and hiring of a chief accounting officer in connection with our preparation for the initial public offering; and (4) supervising and managing the recapitalization of our credit facilities in 2006 which resulted in a $250 million dividend being paid in December 2006. | |
• | Robert Haugen, our Executive Vice President, Refining Operations, was given increased responsibilities during 2006. His position grew to include oversight of our overall refinery operations and our engineering and construction operations. Mr. Haugen was responsible for the increased crude throughput of our refinery operations which resulted from better balancing production across the individual units throughout our facility. In addition, Mr. Haugen developed and supervised the detailed processes involved in our plant expansion. | |
• | Wyatt Jernigan, our Executive Vice President for Crude Oil Acquisition & Petroleum Marketing, was responsible for the increased volume, efficiency and profitability of our crude gathering system. In particular, Mr. Jernigan (1) was instrumental in expanding our crude oil slate (the types of crudes we purchase) from just a few to approximately a dozen, contributing to the increased profitability of our refined fuel sales; (2) worked to improve our crude purchase cost discount to West Texas Intermediate crude (the industry benchmark); (3) expanded the areas in the United States where our crude oil gathering system operates; (4) helped to increase our rack marketing opportunities (sales into tanker trucks rather than through pipelines); (5) focused on increasing the types of crude oil available to us so that we could fine tune our crude oil slate as pricing and economics shifted in the market; and (6) incorporated price risk management into the operation of our crude gathering system. |
195
Table of Contents
196
Table of Contents
197
Table of Contents
198
Table of Contents
• | Significant operational improvement (in increased refinery throughput and yield) for an asset that emerged from bankruptcy just over 3 years ago, as described on page 2 of the prospectus. Upon assuming leadership of our company, Mr. Lipinski challenged existing management to optimize our refinery operations by focusing on plant operating limits each day. With over 35 years of experience in the refining and nitrogen fertilizer industries, Mr. Lipinski focused, and led management to focus, on the details ofday-to-day plant operations. Previously, the refinery had primarily operated based on a predetermined monthly plan which resulted in significant unused capacity. The result of this revised focus was to immediately increase operating rates with essentially no capital expenditures being incurred. | |
• | Initiation of refined fuels offsite rack marketing, as described more fully on page 2 of this prospectus. Under Mr. Lipinski’s direction and leadership, we have built our rack marketing sales — sales of refined products made at terminals into third party tanker trucks, as opposed to sales through third party pipelines — which has directly impacted and improved our profitability. Although we had the infrastructure in place to commence rack marketing, it had not been implemented at the time that Mr. Lipinski became chief executive officer in June 2005. Mr. Lipinski authorized additional company personnel to expand the rack marketing operation and it has served as a key factor in our company’s success over the past two years. | |
• | Revised linear program model and focus on quality control. Mr. Lipinski authorized a project to revise our linear program model which we use for refinery planning and optimization. A linear program is a computer program that simulates plant operations and profitability based on different pricing and operating environment assumptions. Mr. Lipinski also directed that additional company resources be applied to quality assurance and quality control activities throughout the organization. As a result of these efforts, we now have a better modeling tool to assess plant operating rates, sales opportunities and crude oil purchases along with an improved understanding of our operations and better control over product quality. | |
• | Technical focus and environmental stewardship. After becoming chief executive officer, Mr. Lipinski recognized that our organization needed a more technical focus in order to achieve superior performance and he approved the hiring of additional engineering and technical staff, particularly with respect to process engineering. He also fostered a renewed focus on environmental stewardship (evidenced by the construction of our plant wide flare) and safety (evidenced by a reduction in lost time accidents and reportable incidents). | |
• | Implementation and initiation of a refinery expansion project, as further described on page 2. In connection with the due diligence review of our company prior to becoming our chief executive officer, Mr. Lipinski recognized that there was a significant opportunity to more fully |
199
Table of Contents
utilize the facility’s crude capacity by expanding our downstream units. After assuming his position as CEO, Mr. Lipinski sought approval of a project to expand the refinery’s capacity to 115,000 barrels per day, compared to an average of less than 90,000 prior to June 2005. Through Mr. Lipinski’s leadership, we substantially implemented this project in less than twenty-months and currently benefit from improved capacity throughout the plant. |
200
Table of Contents
201
Table of Contents
Non-Equity | ||||||||||||||||||||||||||||
Incentive Plan | All Other | |||||||||||||||||||||||||||
Name and Principal | Salary | Bonus ($) | Stock | Compensation ($) | Compensation | Total | ||||||||||||||||||||||
Position | Year | ($) | (1) | Awards ($) | (1)(4) | ($) | ($) | |||||||||||||||||||||
John J. Lipinski | 2006 | 650,000 | 1,331,790 | 4,326,188(3 | ) | 487,500 | 5,007,935(5 | )(6) | 11,803,413 | |||||||||||||||||||
Chief Executive Officer | ||||||||||||||||||||||||||||
Stanley A. Riemann | 2006 | 350,000 | 772,917 | (2) | — | 210,000 | 943,789(5 | )(7) | 2,276,706 | |||||||||||||||||||
Chief Operating Officer | ||||||||||||||||||||||||||||
James T. Rens | 2006 | 250,000 | 205,000 | — | 130,000 | 695,316(5 | )(8) | 1,280,316 | ||||||||||||||||||||
Chief Financial Officer | ||||||||||||||||||||||||||||
Robert W. Haugen | 2006 | 225,000 | 205,000 | — | 117,000 | 695,471(5 | )(9) | 1,242,471 | ||||||||||||||||||||
Executive Vice President, Refining Operations | ||||||||||||||||||||||||||||
Wyatt E. Jernigan | 2006 | 225,000 | 140,000 | — | 117,000 | 318,000(5 | )(10) | 800,000 | ||||||||||||||||||||
Executive Vice President Crude Oil Acquisition and Petroleum Marketing |
(1) | Bonuses are reported for the year in which they were earned, though they may have been paid the following year. | |
(2) | Includes a retention bonus in the amount of $122,917. | |
(3) | Reflects the amount recognized for financial statement reporting purposes for the fiscal year ended December 31, 2006 with respect to shares of common stock of each of Coffeyville Refining and Marketing, Inc. and Coffeyville Nitrogen Fertilizer, Inc. granted to Mr. Lipinski effective December 28, 2006. | |
(4) | Reflects cash awards to the named individuals in respect of 2006 performance pursuant to our Variable Compensation Plan. | |
(5) | The amounts shown representing grants of profits interests in Coffeyville Acquisition LLC and phantom points reflect the dollar amounts recognized for financial statement reporting purposes for the year ended December 31, 2006 in accordance with FAS 123(R). Assumptions used in the calculation of these amounts are included in footnote 5 to our audited financial statements for the year ended December 31, 2006. The profits interests in Coffeyville Acquisition LLC and the phantom points are more fully described below under “ —Executives’ Interests in Coffeyville Acquisition LLC.” |
202
Table of Contents
(6) | 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 December 28, 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. | |
(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) profits interests in Coffeyville Acquisition LLC granted in 2005 in the amount of $279,670 and (d) phantom points granted to Mr. Riemann during the period ending December 31, 2006 in the amount of $651,299. | |
(8) | 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. Rens during the period ending December 31, 2006 in the amount of $541,061. | |
(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 $143,571 and (d) phantom points granted to Mr. Haugen during the period ending December 31, 2006 in the amount of $541,061. | |
(10) | 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. Jernigan during the period ending December 31, 2006 in the amount of $162,319. |
All other Stock | ||||||||||
Awards: | Grant Date | |||||||||
Number of | Fair Value | |||||||||
Shares of Stock or | of Stock and | |||||||||
Name | Grant Date | Units (#) | Option Awards | |||||||
John J. Lipinski | December 28, 2006 | (1) | $4,326,188(1) | |||||||
December 28, 2006 | 217,458(2) | $1,417,826(4) | ||||||||
December 11, 2006 | 2,737,142(3) | $4,252,562(4) | ||||||||
Stanley A. Riemann | December 11, 2006 | 1,192,266(3) | $1,852,367(4) | |||||||
James T. Rens | December 11, 2006 | 990,476(3) | $1,538,851(4) | |||||||
Robert W. Haugen | December 11, 2006 | 990,476(3) | $1,538,851(4) | |||||||
Wyatt E. Jernigan | December 11, 2006 | 297,142(3) | $461,656(4) | |||||||
(1) | Mr. Lipinski received a grant of shares of common stock of each of Coffeyville Refining and Marketing, Inc. and Coffeyville Nitrogen Fertilizer, Inc. effective December 28, 2006. The number of shares of Coffeyville Nitrogen Fertilizer, Inc. granted was 0.2125376, which equaled approximately 0.64% of the total shares outstanding. The number of shares of Coffeyville Refining and Marketing, Inc. granted was 0.1044200, which approximated 0.31% of the total shares outstanding. The dollar amount shown reflects the grant date fair value recognized for financial |
203
Table of Contents
statement reporting purposes in accordance with FAS 123(R). Assumptions used in the calculation of these amounts are included in footnote 5 to our audited financial statements for the year ended December 31, 2006. | ||
(2) | Represents the number of profits interests in Coffeyville Acquisition LLC granted to the executive on December 28, 2006. | |
(3) | Represents the number of phantom points granted to the executive on December 11, 2006. | |
(4) | The dollar amount shown reflects the fair value as of December 31, 2006 recognized for financial reporting purposes in accordance with FAS 123(R). Assumptions used in the calculation of this amount are included in footnote 5 to our audited financial statements for the year ended December 31, 2006. |
204
Table of Contents
205
Table of Contents
206
Table of Contents
207
Table of Contents
208
Table of Contents
209
Table of Contents
210
Table of Contents
211
Table of Contents
212
Table of Contents
Stock Awards | ||||||||
Number of Shares or Units of | Market Value of Shares or Units | |||||||
Stock That Have Not Vested | of Stock That Have Not Vested | |||||||
Name | (1) (2) (12) | (11) | ||||||
John J. Lipinski | 947,455 | (3) | $ | 28,038,350 | ||||
217,458 | (4) | $ | 1,417,826 | |||||
2,737,142 | (5) | $ | 4,252,562 | |||||
Stanley A. Riemann | 420,556 | (6) | $ | 12,445,652 | ||||
1,192,266 | (7) | $ | 1,852,367 | |||||
James T. Rens | 215,896 | (8) | $ | 6,389,080 | ||||
990,476 | (9) | $ | 1,538,851 | |||||
Robert W. Haugen | 215,896 | (8) | $ | 6,389,080 | ||||
990,476 | (9) | $ | 1,538,851 | |||||
Wyatt E. Jernigan | 215,896 | (8) | $ | 6,389,080 | ||||
297,142 | (10) | $ | 461,656 |
(1) | The profits interests in Coffeyville Acquisition 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 “ — Executives’ Interests in Coffeyville Acquisition LLC.” | |
(2) | The phantom points granted pursuant to the Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I) 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) | Represents profits interests in Coffeyville Acquisition LLC (315,818 operating units and 631,637 value units) granted to the executive on June 24, 2005. These profits interests have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. | |
(4) | Represents profits interests in Coffeyville Acquisition LLC (72,492 operating units and 144,966 value units) granted to the executive on December 28, 2006. These profits interests have been transferred to trusts for the benefit of members of Mr. Lipinski’s family. | |
(5) | Represents phantom points (1,368,571 phantom service points and 1,368,571 phantom performance points) granted to the executive on December 11, 2006. | |
(6) | Represents profits interests in Coffeyville Acquisition LLC (140,185 operating units and 280,371 value units) granted to the executive on June 24, 2005. | |
(7) | Represents phantom points (596,133 phantom service points and 596,133 phantom performance points) granted to the executive on December 11, 2006. | |
(8) | Represents profits interests in Coffeyville Acquisition LLC (71,965 operating units and 143,931 value units) granted to the executive on June 24, 2005. | |
(9) | Represents phantom points (495,238 phantom service points and 495,238 phantom performance points) granted to the executive on December 11, 2006. | |
(10) | Represents phantom points (148,571 phantom service points and 148,571 phantom performance points) granted to the executive on December 11, 2006. | |
(11) | The dollar amount shown reflects the fair value as of December 31, 2006, based upon an independent valuation prepared with a combination of a binomial model and a probability-weighted expected return method. Assumptions used in the calculation of this amount are included in footnote 5 to our audited financial statements for the year ended December 31, 2006. |
213
Table of Contents
(12) | Following the consummation of the Transactions, each of the named executive officers will hold half of the number of profits interests set forth above in each of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. |
Stock Awards | ||||
Number of Shares | Value Realized | |||
Acquired | on Vesting | |||
Name | on Vesting (#) | ($) | ||
John J. Lipinski | (1) | 4,326,188(1) |
(1) | Mr. Lipinski received a grant of shares of common stock of each of Coffeyville Refining and Marketing, Inc. and Coffeyville Nitrogen Fertilizer, Inc. effective December 28, 2006. These shares were fully vested as of the date of grant. The number of shares of Coffeyville Nitrogen Fertilizer, Inc. granted was 0.2125376, which approximated 0.64% of the total shares outstanding. The number of shares of Coffeyville Refining and Marketing, Inc. granted was 0.1044200, which approximated 0.31% of the total shares outstanding. In connection with the formation of Coffeyville Refining & Marketing Holdings, Inc., Mr. Lipinski’s shares of common stock in Coffeyville Refining & Marketing, Inc. were exchanged for an equivalent number of shares of common stock in Coffeyville Refining & Marketing Holdings, Inc. Prior to the consummation of this offering, Mr. Lipinski’s shares of common stock of each of Coffeyville Refining and Marketing Holdings, Inc. and Coffeyville Nitrogen Fertilizer, Inc. will be exchanged for shares of common stock of CVR Energy having an equivalent value. |
214
Table of Contents
Estimated Dollar Value of | ||||||||
Name | Total Severance Payments | Medical Benefits | ||||||
John J. Lipinski (severance if terminated without cause or resigns for good reason) | $ | 1,950,000 | $ | 20,307 | ||||
John J. Lipinski (supplemental disability payments if terminated due to disability) | $ | 650,000 | — | |||||
Stanley A. Riemann | $ | 525,000 | $ | 10,154 | ||||
James T. Rens | $ | 250,000 | $ | 9,713 | ||||
Robert W. Haugen | $ | 225,000 | $ | 9,713 | ||||
Wyatt E. Jernigan | $ | 225,000 | $ | 3,154 |
215
Table of Contents
Fees Earned or Paid | All Other | |||||||||||
Name | in Cash | Compensation | Total | |||||||||
Wesley Clark | $ | 40,000 | $ | 257,352 | (1) | $ | 297,352 | |||||
Scott L. Lebovitz, George E. Matelich, Stanley de J. Osborne and Kenneth A. Pontarelli | $ | 0 | $ | 0 | $ | 0 |
(1) | 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. 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 is performed at the end of each reporting period using a binomial model based on company projections of undiscounted future cash flows. Assumptions used in the calculation of these amounts are included in footnote 5 to our audited financial statements for the year ended December 31, 2006. 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).” |
216
Table of Contents
• | each of our directors; | |
• | each of our named executive officers; | |
• | each stockholder known by us to beneficially hold five percent or more of our common stock; and | |
• | all of our executive officers and directors as a group. |
217
Table of Contents
Shares Beneficially | Shares Beneficially | |||||||||||||||||||||||
Shares Beneficially | Owned After this Offering | Owned After this Offering | ||||||||||||||||||||||
Owned Prior | Assuming the | Assuming the | ||||||||||||||||||||||
to this | Underwriters’ Option Is | Underwriters’ Option Is | ||||||||||||||||||||||
Offering | Not Exercised(1) | Exercised In Full (1) | ||||||||||||||||||||||
Name and Address | Number | Percent | Number | Percent | Number | Percent | ||||||||||||||||||
Coffeyville Acquisition LLC(2)(3) | 31,433,360 | 49.8 | % | 31,433,360 | 38.5 | % | 31,433,360 | 37.2 | % | |||||||||||||||
Coffeyville Acquisition II LLC(4)(5) | 31,433,360 | 49.8 | % | 31,433,360 | 38.5 | % | 31,433,360 | 37.2 | % | |||||||||||||||
The Goldman Sachs Group, Inc.(4) | 31,125,918 | 49.3 | % | 31,125,918 | 38.1 | % | 31,125,918 | 36.9 | % | |||||||||||||||
85 Broad Street | ||||||||||||||||||||||||
New York, New York 10004 | ||||||||||||||||||||||||
Kelso Investment Associates VII, L.P.(2) | 24,557,883 | 38.9 | % | 24,557,883 | 30.1 | % | 24,557,883 | 29.1 | % | |||||||||||||||
KEP VI, LLC(2) | 6,081,000 | 9.6 | % | 6,081,000 | 7.4 | % | 6,081,000 | 7.2 | % | |||||||||||||||
320 Park Avenue, 24th Floor | ||||||||||||||||||||||||
New York, New York 10022 | ||||||||||||||||||||||||
John J. Lipinski(6) | 405,756 | * | 405,756 | * | 405,756 | * | ||||||||||||||||||
Stanley A. Riemann(7) | 97,408 | * | 97,408 | * | 97,408 | * | ||||||||||||||||||
James T. Rens(7) | 60,879 | * | 60,879 | * | 60,879 | * | ||||||||||||||||||
Edmund S. Gross(7) | 7,305 | * | 7,305 | * | 7,305 | * | ||||||||||||||||||
Robert W. Haugen(7) | 24,352 | * | 24,352 | * | 24,352 | * | ||||||||||||||||||
Wyatt E. Jernigan(7) | 24,352 | * | 24,352 | * | 24,352 | * | ||||||||||||||||||
Kevan A. Vick(7) | 60,880 | * | 60,880 | * | 60,880 | * | ||||||||||||||||||
Christopher G. Swanberg(7) | 6,087 | * | 6,087 | * | 6,087 | * | ||||||||||||||||||
Wesley Clark(7) | 60,880 | * | 60,880 | * | 60,880 | * | ||||||||||||||||||
Scott L. Lebovitz | — | * | — | * | — | * | ||||||||||||||||||
Regis B. Lippert(8) | — | * | 5,000 | * | 5,000 | * | ||||||||||||||||||
George E. Matelich(2) | 30,638,883 | 48.5 | % | 30,638,883 | 37.5 | % | 30,638,883 | 36.3 | % | |||||||||||||||
Stanley de J. Osborne | — | * | — | * | — | * | ||||||||||||||||||
Kenneth A. Pontarelli(4) | 31,125,918 | 49.3 | % | 31,125,918 | 38.1 | % | 31,125,918 | 36.9 | % | |||||||||||||||
Mark Tomkins(9) | — | * | 12,500 | * | 12,500 | * | ||||||||||||||||||
All directors and executive officers, as a group (15 persons) | 62,530,200 | 99.0 | % | 62,530,200 | 76.6 | % | 62,530,200 | 74.1 | % |
* | Less than 1% | |
(1) | The underwriters have an option to purchase up to an additional 2,775,000 shares from us in this offering. | |
(2) | Coffeyville Acquisition LLC directly owns 31,433,360 shares of common stock. The number of shares indicated as owned by the Kelso Funds reflects the number of shares of common stock that corresponds to the number of common units held by the Kelso Funds in Coffeyville Acquisition LLC. With respect to the total number of shares of common stock deemed to be beneficially owned prior to this offering, the share amount includes (1) 24,557,883 shares of common stock deemed to be beneficially owned by Kelso Investment Associates VII, L.P., a Delaware limited partnership, or KIA VII, and (2) 6,081,000 shares of common stock deemed to be beneficially owned by KEP VI, LLC, a Delaware limited liability company, or KEP VI. KIA VII and KEP VI, due to their common control, could be deemed to beneficially own each of the other’s shares but each disclaims such beneficial ownership. Shares and percentages indicated represent the upper limit of the expected ownership of our equity securities by these persons and entities. Messrs. Nickell, Wall, Matelich, Goldberg, Wahrhaftig, Bynum, Berney, Loverro and Connors may be deemed to share beneficial ownership of shares of common stock owned of record, by virtue of their status as managing members of KEP VI and of Kelso GP VII, LLC, a Delaware limited liability company, the principal business of which is serving as the general partner of Kelso GP VII, L.P., a Delaware limited partnership, the principal business of which is serving as the general |
218
Table of Contents
partner of KIA VII. Each of Messrs. Nickell, Wall, Matelich, Goldberg, Wahrhaftig, Bynum, Berney, Loverro and Connors share investment and voting power with respect to the ownership interests owned by KIA VII and KEP VI but disclaim beneficial ownership of such interests. | ||
(3) | The board of directors of Coffeyville Acquisition LLC has the power to dispose of the securities of Coffeyville Acquisition LLC. | |
(4) | Coffeyville Acquisition II LLC directly owns 31,433,360 shares of common stock. The number of shares indicated as owned by The Goldman Sachs Group, Inc. reflects the number of shares of common stock that corresponds to the number of common units held by the Goldman Sachs Funds in Coffeyville Acquisition II LLC. The Goldman Sachs Group, Inc., and certain affiliates, including Goldman, Sachs & Co., may be deemed to directly or indirectly own in the aggregate 31,125,918 shares of common stock which are deemed to be beneficially owned directly or indirectly by investment partnerships, which we refer to as the Goldman Sachs Funds, of which affiliates of The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. are the general partner, managing limited partner or the managing partner. Goldman, Sachs & Co. is the investment manager for certain of the Goldman Sachs Funds. Goldman, Sachs & Co. is a direct and indirect, wholly owned subsidiary of The Goldman Sachs Group, Inc. The Goldman Sachs Group, Inc., Goldman, Sachs & Co. and the Goldman Sachs Funds share voting power and investment power with certain of their respective affiliates. Shares deemed to be beneficially owned by the Goldman Sachs Funds consist of: (1) 16,389,665 shares of common stock deemed to be beneficially owned by GS Capital Partners V Fund, L.P., (2) 8,466,218 shares of common stock deemed to be beneficially owned by GS Capital Partners V Offshore Fund, L.P., (3) 5,620,242 shares of common stock deemed to be beneficially owned by GS Capital Partners V Institutional, L.P., and (4) 649,793 shares of common stock deemed to be beneficially owned by GS Capital Partners V GmbH & Co. KG. Ken Pontarelli is a managing director of Goldman, Sachs & Co. Mr. Pontarelli, The Goldman Sachs Group, Inc. and Goldman, Sachs & Co. each disclaims beneficial ownership of the shares of common stock owned directly or indirectly by the Goldman Sachs Funds, except to the extent of their pecuniary interest therein, if any. | |
(5) | The board of directors of Coffeyville Acquisition II LLC has the power to dispose of the securities of Coffeyville Acquisition II LLC. | |
(6) | Of the 405,756 shares of common stock indicated above, 247,471 shares are owned directly by Mr. Lipinski and 158,285 shares represent shares Mr. Lipinski owns 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. | |
(7) | Reflects the number of shares of common stock that corresponds to such holder’s interest in common units of Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. Such holder does not have the power to vote or dispose of such shares and thus does not have beneficial ownership of such shares. | |
(8) | In connection with this offering, our board of directors has awarded 5,000 shares of non-vested restricted stock to Mr. Lippert. The restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. In addition, our board of directors has awarded Mr. Lippert options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. | |
(9) | In connection with this offering, our board of directors has awarded 12,500 shares of non-vested restricted stock to Mark Tomkins. The restrictions on these shares will generally lapse in one-third annual increments beginning on the first anniversary of the date of grant. In addition, our board of directors has awarded Mr. Tomkins options to purchase 5,150 shares of common stock with an exercise price equal to the initial public offering price. These options will generally vest in one-third annual increments beginning on the first anniversary of the date of grant. |
219
Table of Contents
220
Table of Contents
221
Table of Contents
222
Table of Contents
223
Table of Contents
224
Table of Contents
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, this offering and employee shares | 63,114,191 | ||
N: = L/M | Mr. Lipinski’s percentage of pre-offering shares | 0.3921% |
225
Table of Contents
226
Table of Contents
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 |
227
Table of Contents
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 |
228
Table of Contents
229
Table of Contents
• | the formation and capitalization of the partnership, as described in “— Formation Transactions;” | |
• | a right for the managing general partner to cause the Partnership to pursue an initial public or initial private offering of its limited partner interests; and | |
• | a restructuring of our interest in the Partnership, including a potential sale of a portion of our interest, in connection with any initial public or initial private offering by the Partnership, as described in “— Initial Offering Transactions.” |
230
Table of Contents
Contributing Parties | Amount Contributed | |||
The Goldman Sachs Funds | $ | 5,248,060 | ||
The Kelso Funds | 5,165,380 | |||
John J. Lipinski | 26,500 | |||
Stanley A. Riemann | 15,900 | |||
James T. Rens | 10,600 | |||
Edmund S. Gross | 1,060 | |||
Robert W. Haugen | 4,240 | |||
Wyatt E. Jernigan | 4,240 | |||
Kevan A. Vick | 10,600 | |||
Christopher G. Swanberg | 1,060 | |||
Wesley Clark | 10,600 | |||
Others | 101,760 | |||
Total Contribution: | $ | 10,600,000 | ||
231
Table of Contents
232
Table of Contents
233
Table of Contents
Initial | Following Partnership Initial Offering | |||||
Special Units | Common Units | Subordinated Units | ||||
Owned by us | 30,303,000 special GP units | 9,990,000 common GP units | 13,320,000 subordinated LP units | |||
30,333 special LP units | 10,000 common LP units | 13,333 subordinated LP units | ||||
Owned by public | — | 10,000,000 common LP units | — |
234
Table of Contents
235
Table of Contents
• | joint 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 (or comparable governing body) of the managing general partner and one such director to any committee thereof (subject to certain exceptions); | |
• | joint management 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 unit holders of the Partnership; |
236
Table of Contents
• | 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 unit holders of the Partnership; and | |
• | for so long as we own more than 15% of the all 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 unit holders of the Partnership; |
• | joint management rights over any fundamental change in the business of the Partnership from that conducted by the nitrogen fertilizer business; | |
• | joint management 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 current asset value of the Partnership; and | |
• | joint management 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’ overallotment 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. |
237
Table of Contents
• | $60 million; 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 (i) borrowings that are not working capital borrowings, (ii) sales of equity interests and debt securities and (iii) sales or other dispositions of assets outside the ordinary course of business; plus | |
• | interest (after giving effect to any interest rate swap agreements) paid on debt incurred by the Partnership, and cash distributions paid on the equity interests issued by the Partnership, in each case, to finance all or any portion of the construction, expansion or improvement of its 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 | |
• | interest (after giving effect to any interest rate swap agreements) paid on debt incurred by the Partnership, and cash distributions paid on the equity interests issued by the Partnership, in each case, to pay the construction period interest on debt incurred, or to pay construction period distributions on equity issued, to finance the construction projects referred to above; plus | |
• | working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; 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 capital expenditures for acquisitions or for capital improvements). |
238
Table of Contents
239
Table of Contents
Marginal Percentage Interest | ||||||||||
in Distributions | ||||||||||
Total Quarterly | Special Units; | |||||||||
Distribution | Common and | Managing | ||||||||
Target Amount | Subordinated Units | General Partner | ||||||||
Minimum Quarterly Distribution | $0.375 | 100 | % | 0 | % | |||||
First Target Distribution | up to $0.4313 | 100 | % | 0 | % | |||||
Second Target Distribution | above $0.4313 and | 87 | % | 13 | % | |||||
up to $0.4688 | ||||||||||
Third Target Distribution | above $0.4688 and | 77 | % | 23 | % | |||||
up to $0.5625 | ||||||||||
Thereafter | above $0.5625 | 52 | % | 48 | % |
• | the minimum quarterly distribution; | |
• | the target distribution levels; and | |
• | the initial unit price, as described below under “ — Distributions of Cash Upon Liquidation.” |
240
Table of Contents
• | First, to the special units, until each special unit has received a total quarterly distribution equal to $0.4313 (the first target distribution); | |
• | Second, (i) 13% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to the special units until each special unit has received a total quarterly amount equal to $0.4688 (the second target distribution); | |
• | Third, (i) 23% to the managing general partner interest (in respect of the IDRs) and (ii) 77% to the special units, until each special unit has received a total quarterly amount equal to $0.5625 (the third target distribution); and | |
• | Thereafter, (i) 48% to the managing general partner interest (in respect of the IDRs) and (ii) 52% to the special units. |
241
Table of Contents
• | First, to the common units, until each common unit has received an amount equal to the MQD plus any arrearages from prior quarters; | |
• | Second, to the subordinated units, until each subordinated unit has received an amount equal to the MQD; and | |
• | Thereafter, to all common units and subordinated units, pro rata. |
• | First, to all common units, until each common unit has received a total quarterly distribution equal to the MQD plus any arrearages for prior quarters; | |
• | Second, to all subordinated units, until each subordinated unit has received a total quarterly distribution equal to the MQD; | |
• | Third, to all common units and subordinated units, pro rata, until each common unit and subordinated unit has received a total quarterly distribution equal to $0.4313 (excluding any distribution in respect of arrearages) (the first target distribution); | |
• | Fourth, (i) 13% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to all common units and subordinated units, pro rata, until each common unit and subordinated unit has received a total quarterly distribution equal to $0.4688 (excluding any distribution in respect of arrearages) (the second target distribution); | |
• | Fifth, (i) 23% to the managing general partner interest (in respect of the IDRs) and (ii) 77% to all common units and subordinated units, pro rata, until each common unit and subordinated unit has received a total quarterly distribution equal to $0.5625 (excluding any distribution in respect of arrearages) (the third target distribution); and | |
• | Thereafter, (i) 48% to the managing general partner interest (in respect of the IDRs) and (ii) 52% to all common units and subordinated units, pro rata. |
• | First, to all common units, until each common unit has received a total quarterly distribution equal to $0.4313 (the first target distribution); | |
• | Second, (i) 13% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to all common units, pro rata, until each common unit has received a total quarterly distribution equal to $0.4688 (the second target distribution); | |
• | Third, (i) 23% to the managing general partner interest (in respect of the IDRs) and (ii) 87% to all common units, pro rata, until each common unit has received a total quarterly distribution equal to $0.5625 (the third target distribution); and | |
• | Thereafter,(i) 48% to the managing general partner interest (in respect of the IDRs) and (ii) 52% to all common units, pro rata. |
242
Table of Contents
• | the Partnership to have “earned” and “paid” the MQD on all of the Partnership’s outstanding units during specified periods; and | |
• | there to be no arrearages in payment of the MQD on the common units. |
• | operating surplus generated with respect to that period; 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 required by any debt instrument for the repayment of principal, interest or premium. |
243
Table of Contents
• | First, to all unit holders, pro rata, until the minimum quarterly distribution is reduced to zero, as described below; | |
• | Second, to the common unit holders, if any, pro rata, until the Partnership distributes for each common unit an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the common units; and | |
• | Thereafter, the Partnership will make all distributions of available cash from capital surplus as if they were from operating surplus. |
244
Table of Contents
• | our nitrogen fertilizer business was contributed to the Partnership on January 1, 2006; | |
• | the agreements described in “— Other Intercompany Agreements” were entered into on January 1, 2006; and | |
• | the termination of the management agreements with Goldman, Sachs & Co. and Kelso and Company, L.P. occurred on or prior to December 31, 2005. |
Unaudited Pro Forma Cash Available to Make Distributions
Pro Forma | ||||||||||||
Nitrogen Fertilizer | Nitrogen Fertilizer | |||||||||||
Segment Cash Flow | Segment Cash Flow | |||||||||||
for the Year Ended | Pro Forma | for the Year Ended | ||||||||||
December 31, 2006 | Adjustments | December 31, 2006 | ||||||||||
(Unaudited) | (Unaudited) | (Unaudited) | ||||||||||
Net sales | $ | 162,464,532 | $ | — | $ | 162,464,532 | ||||||
Operating costs and expenses: | ||||||||||||
Cost of product sold (exclusive of depreciation & amortization) | 25,898,902 | (3,494,618 | )(a) | 22,404,284 | ||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 63,683,224 | (72,451 | )(b) | 63,610,773 | ||||||||
Selling, general and administrative expenses (exclusive of depreciation & amortization) | 18,914,256 | (6,876,482 | )(c) | 12,037,774 | ||||||||
Depreciation and amortization | 17,125,898 | — | 17,125,898 | |||||||||
Total operating costs and expenses | 125,622,280 | (10,443,551 | ) | 115,178,729 | ||||||||
Operating income | 36,842,252 | 10,443,551 | 47,285,803 | |||||||||
Other income (expense) | 180,680 | — | 180,680 | |||||||||
Income (loss) before provision for income taxes | 37,022,932 | 10,443,551 | 47,466,483 | |||||||||
Adjustments to Cash | ||||||||||||
Depreciation | 17,106,734 | — | 17,106,734 | |||||||||
Amortization | 19,164 | — | 19,164 | |||||||||
Capital expenditures | (13,257,681 | ) | — | (13,257,681 | ) | |||||||
Revolving credit borrowings to fund discretionary capital expenditures | — | 8,917,655 | (d) | 8,917,655 |
245
Table of Contents
Pro Forma | ||||||||||||
Nitrogen Fertilizer | Nitrogen Fertilizer | |||||||||||
Segment Cash Flow | Segment Cash Flow | |||||||||||
for the Year Ended | Pro Forma | for the Year Ended | ||||||||||
December 31, 2006 | Adjustments | December 31, 2006 | ||||||||||
(Unaudited) | (Unaudited) | (Unaudited) | ||||||||||
Changes in working capital | (1,990,000 | ) | — | (1,990,000 | ) | |||||||
Gain/loss on the Disposition of Assets | 1,056,791 | — | 1,056,791 | |||||||||
Total adjustments to cash flow | 2,935,008 | 8,917,655 | 11,852,663 | |||||||||
Cash available for distribution | $ | 39,957,940 | $ | 19,361,206 | $ | 59,319,146 |
a) | Reflects the lower price for pet coke to be supplied by the refinery to the Partnership under the terms of the coke supply agreement to be entered into between us and the Partnership. The actual results for the year ended December 31, 2006 included a coke transfer price of $15 per short ton of coke. The price would have been $5 per ton under the terms of the coke supply agreement. The refinery transferred 349,462 tons of pet coke to the nitrogen fertilizer segment during the year ended December 31, 2006. Under the terms of the coke supply agreement the Partnership would not have been required to purchase more than 349,462 tons of pet coke. | |
b) | Represents a decrease in costs of general environmental insurance allocable to the Partnership under the terms of the services agreement. The actual results for the year ended December 31, 2006 reflect a simple 1/3 allocation to the nitrogen fertilizer segment. The allocation under the services agreement would have been based on payroll. | |
c) | Represents a lower allocation of selling general and administrative expenses under the terms of the services agreement. The actual results for the year ended December 31, 2006 reflect a simple 1/3 allocation to the nitrogen fertilizer segment. The allocation under the services agreement would have been based on payroll. In addition, the pro forma adjustment reflects the reversal of the allocation to the nitrogen fertilizer segment of a portion of a related party management fee which will not be included in actual charges for future years. The pro forma selling, general and administrative expenses does not include any estimated incremental general and administrative expenses that we expect the Partnership would incur if the Partnership were a publicly traded partnership, such as costs associated with annual and quarterly reports to unit holders, tax return andSchedule K-1 preparation and distribution, independent auditor fees, investor relations activities, registrar and transfer agent fees, SEC reporting and filing requirements, incremental director and officer liability insurance costs and director compensation. We estimate that these incremental general and administrative expenses would not exceed approximately $2.0 million per year. | |
d) | For purposes of determining pro forma cash available for distribution, we have assumed that the Partnership was operated during 2006 consistent with the manner in which we assume it would operate as a publicly traded partnership, including borrowing the amounts necessary to cover discretionary capital expenditures, as well as interest payments on such borrowings, as reflected in the table. The nitrogen fertilizer segment incurred significant expenditures related to discretionary capital expenditure projects which we assume would not have been funded from cash from operations if the Partnership were operated as a publicly traded partnership. We assume the Partnership would either reserve adequate cash to complete discretionary capital expenditures or would raise additional capital to fund projects that are not required to sustain operations. The managing general partner will determine how capital expenditures will be funded. |
246
Table of Contents
• | First, to the managing general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances; | |
• | Second, to the common unit holders, pro rata, until the capital account for each common unit is equal to the sum of: |
(2) | the amount of the minimum quarterly distribution for the quarter during which the liquidation occurs; and |
• | Third, to the subordinated unit holders, pro rata, until the capital account for each subordinated unit is equal to the sum of: |
(2) | the amount of the minimum quarterly distribution for the quarter during which the liquidation occurs; |
247
Table of Contents
• | Fourth, to all unit holders, pro rata, until the Partnership allocates under this paragraph an amount per unit equal to: |
(1) | the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of the Partnership’s existence; less | |
(2) | the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that the Partnership distributed to the unit holders, pro rata, for each quarter of the Partnership’s existence; |
• | Fifth, 87% to all unit holders, pro rata, and 13% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to: |
(1) | the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of the Partnership’s existence; less | |
(2) | the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that the Partnership distributed 87% to the unit holders, pro rata, and 13% to the managing general partner for each quarter of the Partnership’s existence; |
• | Sixth, 77% to all unit holders, pro rata, and 23% to the managing general partner, until the Partnership allocates under this paragraph an amount per unit equal to: |
(1) | the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of the Partnership’s existence; less | |
(2) | the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that the Partnership distributed 77% to the unit holders, pro rata, and 23% to the managing general partner for each quarter of the Partnership’s existence; and |
• | Thereafter, 52% to all unit holders, pro rata, and 48% to the managing general partner. |
• | First, to holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the subordinated unit holders have been reduced to zero; | |
• | Second, to the holders of common units in proportion to the positive balances in their capital accounts, until the capital accounts of the common unit holders have been reduced to zero; and | |
• | Thereafter, 100% to the managing general partner. |
248
Table of Contents
• | the subordination period will end and all outstanding subordinated units will immediately convert into common units on aone-for-one basis; and | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished. |
249
Table of Contents
• | Issuance of additional units: no vote required. | |
• | Amendment of the partnership agreement: certain amendments may be made by the managing general partner without the approval of the unit holders. 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. See “ — Merger, Sale or Other Disposition of Assets.” In addition, the holder of special GP rights has joint management rights with respect to some mergers. | |
• | Continuation of the Partnership upon dissolution: unit majority. See “ — Termination and Dissolution.” | |
• | 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 |
250
Table of Contents
manner which would cause a dissolution of the Partnership. See “ — Withdrawal of the Managing General Partner.” |
• | Removal of the managing general partner: generally not less than 80% of the outstanding common and subordinated units, voting as a single class, including units held by the managing general partner and its affiliates. See “ — Removal of the Managing General Partner.” | |
• | Transfer of the managing general partner’s general partner interest: the managing general partner may transfer all, but not less than all, of its managing general partner interest in the Partnership without a vote of the unit holders to an affiliate or to another person in connection with its merger or consolidation with or into, or sale of all or substantially all of the managing general partner’s assets to, such person. A unit majority is required in other circumstances for a transfer of the managing general partner interest to a third party prior to June 30, 2017. See “ — Transfer of Managing General Partner Interest.” | |
• | Transfer of ownership interests in the managing general partner: no approval required at any time. See “ — Transfer of Ownership Interests in the Managing General Partner.” |
251
Table of Contents
• | a change in the Partnership’s name, the location of its principal place of business, its registered agent or its registered office; | |
• | the admission, substitution, withdrawal or removal of partners in accordance with the partnership agreement; | |
• | a change that the managing general partner determines to be necessary or appropriate for the Partnership to qualify or to continue its qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that the Partnership will not be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes (to the extent not already so treated or taxed); | |
• | an amendment that is necessary, in the opinion of the Partnership’s counsel, to prevent the Partnership or its managing general partner or its directors, officers, agents, or trustees or CVR Energy from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisors Act of 1940, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974 (“ERISA”), whether or not substantially similar to plan asset regulations currently applied or proposed; | |
• | an amendment that the managing general partner determines to be necessary or appropriate for the authorization of additional partnership interests or rights to acquire partnership interests; | |
• | any amendment expressly permitted in our partnership agreement to be made by the Partnership’s managing general partner acting alone; | |
• | an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of the partnership agreement; | |
• | any amendment that the Partnership’s managing general partner determines to be necessary or appropriate for the formation by the Partnership of, or its investment in, any corporation, partnership or other entity, as otherwise permitted by the partnership agreement; | |
• | a change in the Partnership’s fiscal year or taxable year and related changes; |
252
Table of Contents
• | mergers with or conveyances to another limited liability entity that is newly formed and has no assets, liabilities or operations at the time of the merger or conveyance other than those it receives by way of the merger or conveyance; or | |
• | any other amendments substantially similar to any of the matters described above. |
• | do not adversely affect the partners (or any particular class of partners) in any material respect; | |
• | are necessary or appropriate to satisfy any requirements, conditions, or guidelines contained in any opinion, directive, order, ruling, or regulation of any federal or state agency or judicial authority or contained in any federal or state statute; | |
• | are necessary or appropriate to facilitate the trading of partner interests or to comply with any rule, regulation, guideline, or requirement of any securities exchange on which the partner interests are or will be listed for trading; | |
• | are necessary or appropriate for any action taken by the managing general partner relating to splits or combinations of units under the provisions of the partnership agreement; or | |
• | are required to effect the intent of the provisions of the partnership agreement or this registration statement or are otherwise contemplated by the partnership agreement. |
253
Table of Contents
254
Table of Contents
255
Table of Contents
• | the subordination period will end and all outstanding subordinated units will immediately convert into common units on aone-for-one basis; and | |
• | any existing arrearages in payment of the minimum quarterly distribution on the common units will be extinguished. |
256
Table of Contents
• | approved by Fertilizer GP’s conflicts committee, although Fertilizer GP is not obligated to seek such approval; |
257
Table of Contents
• | 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 on 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. |
258
Table of Contents
• | The partnership agreement provides that Fertilizer GP shall not have any liability to the Partnership or its unit holders (including us) for decisions made in its capacity as managing general partner so long as it acted in good faith, meaning it believed that the decision was in the best interests of the Partnership. | |
• | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee of the board of directors of Fertilizer GP and not involving a vote of unit holders must be on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to the Partnership, as determined by Fertilizer GP in good faith, and that, in determining whether a transaction or resolution is “fair and reasonable,” Fertilizer GP may consider the totality of the relationships between the parties involved, including other transactions that may be particularly advantageous or beneficial to the Partnership. | |
• | The partnership agreement provides that Fertilizer GP and its officers and directors will not be liable for monetary damages to the Partnership or its partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or its officers or directors acted in bad faith or engaged in fraud or willful misconduct. |
• | 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. |
259
Table of Contents
• | 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). |
• | 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; |
260
Table of Contents
• | the negotiation, execution and performance of any contracts, conveyances or other instruments; | |
• | the distribution of Partnership cash; | |
• | the selection and dismissal of employees and agents, outside attorneys, accountants, consultants and contractors and the determination of their compensation and other terms of employment or hiring; | |
• | the maintenance of insurance for the Partnership’s benefit and the benefit of its partners; | |
• | the formation of, or acquisition of an interest in, and the contribution of property and the making of loans to, any further limited or general partnerships, joint ventures, corporations, limited liability companies or other relationships; | |
• | the control of any matters affecting the Partnership’s rights and obligations, including the bringing and defending of actions at law or in equity and otherwise engaging in the conduct of litigation, arbitration or mediation and the incurring of legal expense and the settlement of claims and litigation; | |
• | the indemnification of any person against liabilities and contingencies to the extent permitted by law; | |
• | the purchase, sale or other acquisition or disposition of Partnership interests, or the issuance of additional options, rights, warrants and appreciation rights relating to Partnership interests; and | |
• | the entering into of agreements with any affiliates to render services to the Partnership or to itself in the discharge of its duties as the Partnership’s managing general partner. |
261
Table of Contents
• | State law fiduciary duty standards are generally considered to include an obligation to act in good faith and with due care and loyalty. The duty of care, in the absence of a provision in a partnership agreement providing otherwise, would generally require a general partner to act for the partnership in the same manner as a prudent person would act on his own behalf. The duty of loyalty, in the absence of a provision in a partnership agreement providing otherwise, would generally prohibit a general partner of a Delaware limited partnership from taking any action or engaging in any transaction where the general partner has a conflict of interest. | |
• | The partnership agreement contains provisions that waive or consent to conduct by the Partnership’s general partners and their affiliates that might otherwise raise issues as to compliance with fiduciary duties or applicable law. For example, the partnership agreement provides that when either of the general partners is acting in its capacity as a general partner, as opposed to in its individual capacity, it must act in “good faith” and will not be subject to any other standard under applicable law. In addition, when either of the general partners is acting in its individual capacity, as opposed to in its capacity as a general partner, it may act without any fiduciary obligation to the Partnership or the unit holders whatsoever. These standards reduce the obligations to which the Partnership’s general partners would otherwise be held. | |
• | The partnership agreement generally provides that affiliated transactions and resolutions of conflicts of interest not involving a vote of unit holders and that are not approved by the conflicts committee of the board of directors of the Partnership’s managing general partner must be (1) on terms no less favorable to the Partnership than those generally being provided to or available from unrelated third parties or (2) “fair and reasonable” to the Partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership). | |
• | If the Partnership’s managing general partner does not seek approval from the conflicts committee or the common unit holders and its board of directors determines that the resolution or course of action taken with respect to the conflict of interest satisfies either of the standards set forth in the bullet point above, then it will be presumed that, in making its decision, the board of directors of the managing general partner, which may include board members affected by the conflict of interest, acted in good faith, and in any proceeding brought by or on behalf of any partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. These standards reduce the obligations to which the Partnership’s managing general partner would otherwise be held. | |
• | In addition to the other more specific provisions limiting the obligations of the Partnership’s general partners, the partnership agreement further provides that the Partnership’s general partners and their officers and directors will not be liable for monetary damages to the Partnership or its partners for errors of judgment or for any acts or omissions unless there has been a final and non-appealable judgment by a court of competent jurisdiction determining that the general partner or its officers and directors acted in bad faith or engaged in fraud or willful misconduct. |
262
Table of Contents
263
Table of Contents
264
Table of Contents
• | we avoid the capital cost and operating expenses associated with coke handling; | |
• | we enjoy flexibility in our refinery’s crude slate and operations as a result of not being required to meet a specific coke quality (which most other pet coke users would otherwise require); | |
• | we avoid the administration, credit risk and marketing fees associated with selling coke; and | |
• | we obtain a contractual right of first refusal to a secure and reliable long-term source of hydrogen from the fertilizer business to back up the refinery’s own internal hydrogen production. This beneficial redundancy could only otherwise be achieved through significant capital investment. Hydrogen is required by the refinery to remove sulfur from diesel fuel and gasoline and if hydrogen is not available to the refinery for even short periods of the time, it would have a significant negative financial consequence to the refinery. |
265
Table of Contents
266
Table of Contents
267
Table of Contents
268
Table of Contents
269
Table of Contents
• | 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 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 to us 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 paragraph pending the managing general partner’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 managing general partner has previously advised us that the managing general partner’s board of directors has elected not to cause the Partnership or its controlled affiliates to acquire such businesses; or | |
• | acquiring up to 9.9% of any class of securities of any publicly-traded company that engages in any fertilizer restricted business. |
• | 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 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 to the Partnership 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 paragraph 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 a 9.9% ownership of any class of securities of any publicly-traded company that engages in any refinery restricted business. |
270
Table of Contents
• | services by our employees in capacities equivalent to the capacities of corporate executive officers, except that those who serve in such capacities under the agreement shall 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; | |
• | managing the property of the Partnership and Coffeyville Resources Nitrogen Fertilizers, LLC, a subsidiary of the Partnership, in the ordinary course of business; | |
• | recommending capital raising activities to the board of directors of the managing general partner of the Partnership, 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. |
271
Table of Contents
272
Table of Contents
273
Table of Contents
274
Table of Contents
• | 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; | |
• | 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 and 25% if the total leverage ratio as of the end of such fiscal year is less than 1.00:1.00; and | |
• | 100% of the cash proceeds received by Parent, Holdings or any subsidiary of Holdings from any initial public offering or secondary registered offering of equity interests, until the aggregate amount of such proceeds is equal to $280 million. |
275
Table of Contents
Minimum | ||||||
interest | Maximum | |||||
Fiscal quarter ending | coverage ratio | leverage ratio | ||||
June 30, 2007 | 2.50:1.00 | 4.50:1.00 | ||||
September 30, 2007 | 2.75:1.00 | 4.25:1.00 | ||||
December 31, 2007 | 2.75:1.00 | 4.00:1.00 | ||||
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 and thereafter | 3.75:1.00 | 2.25:1.00 to 12/31/09, 2.00:1.00 thereafter |
276
Table of Contents
277
Table of Contents
• | $25 Million Secured Facility. Coffeyville Resources, LLC entered into a new $25 million senior secured term loan (the “$25 million secured facility”). The facility is secured by the same collateral that secures our existing Credit Facility. Interest is payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. As of September 30, 2007, $25 million was outstanding under this facility. | |
• | $25 Million Unsecured Facility. Coffeyville Resources, LLC entered into a new $25 million senior unsecured term loan (the “$25 million unsecured facility”). Interest is payable in cash, at our option, at the base rate plus 1.00% or at the reserve adjusted eurodollar rate plus 2.00%. As of September 30, 2007, $25 million was outstanding under this facility. | |
• | $75 Million Unsecured Facility. Coffeyville Refining & Marketing Holdings, Inc. entered into a new $75 million senior unsecured term loan (the “$75 million unsecured facility”). Drawings may be made from time to time in amounts of at least $5 million. Interest accrues, at our option, at the base rate plus 1.50% or at the reserve adjusted eurodollar rate plus 2.50%. Interest is paid by adding such interest to the principal amount of loans outstanding. In addition, a commitment fee equal to 1.00% accrues and is paid by adding such fees to the principal amount of loans outstanding. As of September 30, 2007, $0.0 million was drawn under this facility. |
278
Table of Contents
• | 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. |
279
Table of Contents
• | guaranteed by Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc., Coffeyville Crude Transportation, Inc. Coffeyville Terminal, Inc., CL JV Holdings, LLC and their domestic subsidiaries; | |
• | secured by a $150 million funded letter of credit issued under the Credit Facility in favor of J. Aron; and | |
• | to the extent J. Aron’s exposure under the derivative transaction exceeds $150 million, secured by the same collateral that secures our Credit Facility. |
• | 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 million funded letter of credit in favor of J. Aron. |
280
Table of Contents
• | 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 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 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 million payment due September 7, 2007 (and accrued interest), the $43.7 million payment due September 7, 2007 (and accrued interest) and the $35 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%. The letter agreement also amended the Cash Flow Swap to incorporate by reference the negative and financial covenants contained in Coffeyville Resources, LLC’s new $25 million senior secured credit agreement entered into in August 2007. |
281
Table of Contents
• | 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. |
282
Table of Contents
283
Table of Contents
284
Table of Contents
• | one percent of the number of shares of common stock then outstanding, which will equal approximately 816,416 shares immediately after this offering; or | |
• | the average weekly trading volume of the common stock during the four calendar weeks preceding the sale. |
285
Table of Contents
• | 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. |
286
Table of Contents
• | 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; |
287
Table of Contents
• | 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 | |
• | 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. |
288
Table of Contents
• | 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, |
289
Table of Contents
Underwriters | Number of Shares | |||
Goldman, Sachs & Co. | ||||
Deutsche Bank Securities Inc. | ||||
Credit Suisse Securities (USA) LLC | ||||
Citigroup Global Markets Inc. | ||||
Simmons & Company International | ||||
Total | 18,500,000 | |||
No Exercise | Full Exercise | |||||||
Per Share | $ | $ | ||||||
Total | $ | $ |
290
Table of Contents
• | the history and prospects for our industry; | |
• | our historical performance, including our net sales, net income, margins and certain other financial information; | |
• | estimates of our business potential and earnings prospects; | |
• | an assessment of our management; | |
• | investor demand for our shares of common stock; | |
• | market valuations of companies that we and the representatives believe to be comparable; and | |
• | prevailing securities markets at the time of this offering. |
291
Table of Contents
292
Table of Contents
293
Table of Contents
294
Table of Contents
295
Table of Contents
2-1-1 crack spread | The approximate gross margin resulting from processing two barrels of crude oil to produce one barrel of gasoline and one barrel of diesel fuel. | |
Barrel | Common unit of measure in the oil industry which equates to 42 gallons. | |
Blendstocks | Various compounds that are combined with gasoline or diesel from the crude oil refining process to make finished gasoline and diesel fuel; these may include natural gasoline, FCC unit gasoline, ethanol, reformate or butane, among others. | |
Bonus plan | The CVR Partners, LP Profit Bonus Plan, which the managing general partner of the Partnership intends to adopt on behalf of the Partnership prior to the consummation of this offering, and which will relate to distributions of profit made by Coffeyville Acquisition III LLC. | |
Bonus points | The class of interests to be issued under the bonus plan, which will represent the opportunity to receive a cash payment when distributions of profit are made pursuant to the limited liability company agreement of Coffeyville Acquisition III LLC. | |
bpd | Abbreviation for barrels per day. | |
Btu | British thermal units: a measure of energy. One Btu of heat is required to raise the temperature of one pound of water one degree Fahrenheit. | |
Bulk sales | Volume sales through third party pipelines, in contrast to tanker truck quantity sales. | |
Bulk spot basis | Prompt bulk sales (as compared to outer month sales). | |
By-products | Products that result from extracting high value products such as gasoline and diesel fuel from crude oil; these include black oil, sulfur, propane, pet coke and other products. | |
Capacity | Capacity is defined as the throughput a process unit is capable of sustaining, either on a calendar or stream day basis. The throughput may be expressed in terms of maximum sustainable, nameplate or economic capacity. The maximum sustainable or nameplate capacities may not be the most economical. The economic capacity is the throughput that generally provides the greatest economic benefit based on considerations such as feedstock costs, product values and downstream unit constraints. | |
Catalyst | A substance that alters, accelerates, or instigates chemical changes, but is neither produced, consumed nor altered in the process. | |
Coffeyville supply area | Refers to the states of Kansas, Oklahoma, Missouri, Nebraska and Iowa. |
296
Table of Contents
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. | |
Crude slate optimization | The process of determining the most economic crude oils to be refined based upon the prevailing product values, crude prices, crude oil yields and refinery process unit operating unit constraints to maximize profit. | |
Crude unit | The initial refinery unit to process crude oil by separating the crude oil according to boiling point under high heat to recover various hydrocarbon fractions. | |
Delayed coker | A refinery unit that processes heavy feedstock using high temperature and produces lighter products and petroleum coke. | |
Distillates | Primarily diesel fuel, kerosene and jet fuel. | |
Ethanol | A clear, colorless, flammable oxygenated hydrocarbon. Ethanol is typically produced chemically from ethylene, or biologically from fermentation of various sugars from carbohydrates found in agricultural crops and cellulosic residues from crops or wood. It is used in the United States as a gasoline octane enhancer and oxygenate. | |
Farm belt | Refers to the states of Illinois, Indiana, Iowa, Kansas, Minnesota, Missouri, Nebraska, North Dakota, Ohio, Oklahoma, South Dakota, Texas and Wisconsin. | |
Feedstocks | Petroleum products, such as crude oil and natural gas liquids, that are processed and blended into refined products. | |
Fluid catalytic cracking unit | Converts gas oil from the crude unit or coker unit into liquefied petroleum gas, distillates and gasoline blendstocks by applying heat in the presence of a catalyst. |
297
Table of Contents
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. | |
Modified Solomon complexity | Standard industry measure of a refinery’s ability to process less expensive feedstock, such as heavier and high-sulfur content crude oils, into value-added products. The weighted average of the Solomon complexity factors for each operating unit multiplied by the throughput of each refinery unit, divided by the crude capacity of the refinery. | |
MTBE | Methyl Tertiary Butyl Ether, an ether produced from the reaction of isobutylene and methanol specifically for use as a gasoline blendstock. The EPA required MTBE or other oxygenates to be blended into reformulated gasoline. | |
Naphtha | The major constituent of gasoline fractionated from crude oil during the refining process, which is later processed in the reformer unit to increase octane. | |
Netbacks | Refers to the unit price of fertilizer, in dollars per ton, offered on a delivered basis and excludes shipment costs. Also referred to as plant gate price. | |
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. |
298
Table of Contents
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. | |
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. |
299
Table of Contents
Phantom Unit Plan II | The Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II), which we intend to adopt prior to the consummation of this offering, and which will relate 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. | |
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 |
300
Table of Contents
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 38 and 40 and a sulfur content of approximately 0.3 weight percent that is used as a benchmark for other crude oils. | |
WTS | West Texas Sour crude oil, a relatively light, sour crude oil characterized by an API gravity of 32-33 degrees and a sulfur content of approximately 2 weight percent. | |
Yield | The percentage of refined products that is produced from crude and other feedstocks. |
301
Table of Contents
Audited Financial Statements: | ||||
F-2 | ||||
F-3 | ||||
F-4 | ||||
F-5 | ||||
F-8 | ||||
F-9 | ||||
Unaudited Condensed Consolidated Financial Statements: | ||||
F-51 | ||||
F-52 | ||||
F-53 | ||||
F-54 |
F-1
Table of Contents
CVR Energy, Inc.:
F-2
Table of Contents
Coffeyville Acquisition LLC | ||||||||
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
ASSETS | ||||||||
Current assets: | ||||||||
Cash and cash equivalents | $ | 64,703,524 | $ | 41,919,260 | ||||
Accounts receivable, net of allowance for doubtful accounts of $275,188 and $375,443, respectively | 71,560,052 | 69,589,161 | ||||||
Inventories | 154,275,818 | 161,432,793 | ||||||
Prepaid expenses and other current assets | 14,709,309 | 18,524,017 | ||||||
Deferred income taxes | 31,059,748 | 18,888,660 | ||||||
Income tax receivable | — | 32,099,163 | ||||||
Total current assets | 336,308,451 | 342,453,054 | ||||||
Property, plant, and equipment, net of accumulated depreciation | 772,512,884 | 1,007,155,873 | ||||||
Intangible assets, net | 1,008,547 | 638,456 | ||||||
Goodwill | 83,774,885 | 83,774,885 | ||||||
Deferred financing costs, net | 19,524,839 | 9,128,258 | ||||||
Other long-term assets | 8,418,297 | 6,328,989 | ||||||
Total assets | $ | 1,221,547,903 | $ | 1,449,479,515 | ||||
LIABILITIES AND EQUITY | ||||||||
Current liabilities: | ||||||||
Current portion of long-term debt | $ | 2,235,973 | $ | 5,797,981 | ||||
Accounts payable | 87,914,833 | 138,911,088 | ||||||
Personnel accruals | 10,796,896 | 24,731,283 | ||||||
Accrued taxes other than income taxes | 4,841,234 | 9,034,841 | ||||||
Accrued income taxes | 4,939,614 | — | ||||||
Payable to swap counterparty | 96,688,956 | 36,894,802 | ||||||
Deferred revenue | 12,029,987 | 8,812,350 | ||||||
Other current liabilities | 8,831,937 | 6,017,435 | ||||||
Total current liabilities | 228,279,430 | 230,199,780 | ||||||
Long-term liabilities: | ||||||||
Long-term debt, less current portion | 497,201,527 | 769,202,019 | ||||||
Accrued environmental liabilities | 7,009,388 | 5,395,105 | ||||||
Deferred income taxes | 209,523,747 | 284,122,958 | ||||||
Payable to swap counterparty | 160,033,333 | 72,806,486 | ||||||
Total long-term liabilities | 873,767,995 | 1,131,526,568 | ||||||
Minority interest in subsidiaries | — | 4,326,188 | ||||||
Management voting common units subject to redemption, 227,500 and 201,063 units issued and outstanding in 2005 and 2006, respectively | 4,172,350 | 6,980,907 | ||||||
Less: note receivable from management unit holder | (500,000 | ) | — | |||||
Total management voting common units subject to redemption, net | 3,672,350 | 6,980,907 | ||||||
Members’ equity: | ||||||||
Voting common units, 23,588,500 and 22,614,937 units issued and outstanding in 2005 and 2006, respectively | 114,830,560 | 73,593,326 | ||||||
Management nonvoting override units, 2,758,895 and 2,976,353 units issued and outstanding in 2005 and 2006, respectively | 997,568 | 2,852,746 | ||||||
Total members’ equity | 115,828,128 | 76,446,072 | ||||||
Total liabilities and equity | $ | 1,221,547,903 | $ | 1,449,479,515 | ||||
F-3
Table of Contents
Coffeyville Group | ||||||||||||||||||||||
Farmland Industries | Holdings, LLC | Coffeyville Acquisition LLC | ||||||||||||||||||||
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||
62 Days Ended | 304 Days Ended | 174 Days Ended | 233 Days Ended | Year Ended | ||||||||||||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||||||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||
Net sales | $ | 261,086,529 | $ | 1,479,893,189 | $ | 980,706,261 | $ | 1,454,259,542 | $ | 3,037,567,362 | ||||||||||||
Operating costs and expenses: | ||||||||||||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | 221,449,177 | 1,244,207,423 | 768,067,178 | 1,168,137,217 | 2,443,374,743 | |||||||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | 23,353,462 | 116,984,384 | 80,913,862 | 85,313,202 | 198,979,983 | |||||||||||||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 4,649,145 | 16,284,084 | 18,341,522 | 18,320,030 | 62,600,121 | |||||||||||||||||
Depreciation and amortization | 432,003 | 2,445,961 | 1,128,005 | 23,954,031 | 51,004,582 | |||||||||||||||||
Total operating costs and expenses | 249,883,787 | 1,379,921,852 | 868,450,567 | 1,295,724,480 | 2,755,959,429 | |||||||||||||||||
Operating income | 11,202,742 | 99,971,337 | 112,255,694 | 158,535,062 | 281,607,933 | |||||||||||||||||
Other income (expense): | ||||||||||||||||||||||
Interest expense and other financing costs | — | (10,058,450 | ) | (7,801,821 | ) | (25,007,159 | ) | (43,879,644 | ) | |||||||||||||
Interest income | — | 169,652 | 511,687 | 972,264 | 3,450,190 | |||||||||||||||||
Gain (loss) on derivatives | — | 546,604 | (7,664,725 | ) | (316,062,111 | ) | 94,493,141 | |||||||||||||||
Loss on extinguishment of debt | — | (7,166,110 | ) | (8,093,754 | ) | — | (23,360,306 | ) | ||||||||||||||
Other income (expense) | 9,345 | 52,659 | (762,616 | ) | (563,190 | ) | (899,831 | ) | ||||||||||||||
Total other income (expense) | 9,345 | (16,455,645 | ) | (23,811,229 | ) | (340,660,196 | ) | 29,803,550 | ||||||||||||||
Income (loss) before income taxes | 11,212,087 | 83,515,692 | 88,444,465 | (182,125,134 | ) | 311,411,483 | ||||||||||||||||
Income tax expense (benefit) | — | 33,805,480 | 36,047,516 | (62,968,044 | ) | 119,840,160 | ||||||||||||||||
Net income (loss) | $ | 11,212,087 | $ | 49,710,212 | $ | 52,396,949 | $ | (119,157,090 | ) | $ | 191,571,323 | |||||||||||
Unaudited Pro Forma Information (Note 2) | ||||||||||||||||||||||
Basic earnings per common share | $ | 2.26 | ||||||||||||||||||||
Diluted earnings per common share | $ | 2.26 | ||||||||||||||||||||
Basic weighted average common shares outstanding | 84,716,785 | |||||||||||||||||||||
Diluted weighted average common shares outstanding | 84,734,285 | |||||||||||||||||||||
F-4
Table of Contents
Divisional | Voting | Nonvoting | Unearned | |||||||||||||||||
Equity | Preferred | Common | Compensation | Total | ||||||||||||||||
Original Predecessor | ||||||||||||||||||||
For the 62 days ended March 2, 2004 | ||||||||||||||||||||
Balance, December 31, 2003 | $ | 58,191,489 | $ | — | $ | — | $ | — | $ | 58,191,489 | ||||||||||
Net income | 11,212,087 | — | — | — | 11,212,087 | |||||||||||||||
Net distribution to Farmland Industries, Inc. | (53,216,357 | ) | — | — | — | (53,216,357 | ) | |||||||||||||
Balance, March 2, 2004 | $ | 16,187,219 | $ | — | $ | — | $ | — | $ | 16,187,219 | ||||||||||
Immediate Predecessor | ||||||||||||||||||||
For the 304 days ended December 31, 2004 and the 174 days ended June 23, 2005 | ||||||||||||||||||||
Members’ Equity, March 3, 2004 | $ | — | $ | — | $ | — | $ | — | $ | — | ||||||||||
Issuance of 63,200,000 preferred units for cash | — | 63,200,000 | — | — | 63,200,000 | |||||||||||||||
Issuance of 11,152,941 common units to management for recourse promissory notes and unearned compensation | — | — | 3,100,000 | (3,037,000 | ) | 63,000 | ||||||||||||||
Issuance of 500,000 common units to management for recourse promissory notes and unearned compensation | — | — | 2,047,450 | (2,044,600 | ) | 2,850 | ||||||||||||||
Recognition of earned compensation expense related to common units | — | — | — | 1,095,609 | 1,095,609 | |||||||||||||||
Dividends on preferred units ($1.50 per unit) | — | (94,686,276 | ) | — | — | (94,686,276 | ) | |||||||||||||
Dividends to management on common units ($0.48 per unit) | — | — | (5,301,233 | ) | — | (5,301,233 | ) | |||||||||||||
Net income | — | 41,971,436 | 7,738,776 | — | 49,710,212 | |||||||||||||||
Members’ Equity, December 31, 2004 | — | 10,485,160 | 7,584,993 | (3,985,991 | ) | 14,084,162 | ||||||||||||||
Recognition of earned compensation expense related to common units | — | — | — | 3,985,991 | 3,985,991 | |||||||||||||||
Contributed capital | — | 728,724 | — | — | 728,724 | |||||||||||||||
Dividends on preferred units ($0.70 per unit) | — | (44,083,323 | ) | — | — | (44,083,323 | ) | |||||||||||||
Dividends to management on common units ($0.70 per unit) | — | — | (8,128,170 | ) | — | (8,128,170 | ) | |||||||||||||
Net income | — | 44,239,908 | 8,157,041 | — | 52,396,949 | |||||||||||||||
Members’ Equity, June 23, 2005 | $ | — | $ | 11,370,469 | $ | 7,613,864 | $ | — | $ | 18,984,333 | ||||||||||
F-5
Table of Contents
Management Voting | Note Receivable | |||||||||||||||
Common Units | from Management | |||||||||||||||
Subject to Redemption | Unit Holder | Total | ||||||||||||||
Units | Dollars | Dollars | Dollars | |||||||||||||
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 | 1,775,000 | — | 1,775,000 | ||||||||||||
Issuance of 50,000 common units for note receivable | 50,000 | 500,000 | (500,000 | ) | — | |||||||||||
Adjustment to fair value for management common units | — | 3,035,586 | — | 3,035,586 | ||||||||||||
Net loss allocated to management common units | — | (1,138,236 | ) | — | (1,138,236 | ) | ||||||||||
Balance at December 31, 2005 | 227,500 | 4,172,350 | (500,000 | ) | 3,672,350 | |||||||||||
Payment of note receivable | — | — | 150,000 | 150,000 | ||||||||||||
Forgiveness of note receivable | — | — | 350,000 | 350,000 | ||||||||||||
Adjustment to fair value for management common units | — | 4,239,548 | — | 4,239,548 | ||||||||||||
Prorata reduction of management common units outstanding | (26,437 | ) | — | — | — | |||||||||||
Distributions to management on common units | — | (3,119,188 | ) | — | (3,119,188 | ) | ||||||||||
Net income allocated to management common units | — | 1,688,197 | — | 1,688,197 | ||||||||||||
Balance at December 31, 2006 | 201,063 | $ | 6,980,907 | $ | — | $ | 6,980,907 | |||||||||
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 | ||||||||||||||||||||||
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 | 235,885,000 | — | — | — | — | 235,885,000 | |||||||||||||||||||||
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 | — | — | — | 602,381 | — | 395,187 | 997,568 | |||||||||||||||||||||
Adjustment to fair value for management common units | — | (3,035,586 | ) | — | — | — | — | (3,035,586 | ) | |||||||||||||||||||
Net loss allocated to common units | — | (118,018,854 | ) | — | — | — | — | (118,018,854 | ) | |||||||||||||||||||
Balance at December 31, 2005 | 23,588,500 | 114,830,560 | 919,630 | 602,381 | 1,839,265 | 395,187 | 115,828,128 | |||||||||||||||||||||
Issuance of 2,000,000 common units for cash | 2,000,000 | 20,000,000 | — | — | — | — | 20,000,000 | |||||||||||||||||||||
Recognition of share-based compensation expense related to override units | — | — | — | 1,160,530 | — | 694,648 | 1,855,178 | |||||||||||||||||||||
Adjustment to fair value for management common units | — | (4,239,548 | ) | — | — | — | — | (4,239,548 | ) | |||||||||||||||||||
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 | — | (246,880,812 | ) | — | — | — | — | (246,880,812 | ) | |||||||||||||||||||
Net income allocated to common units | — | 189,883,126 | — | — | — | — | 189,883,126 | |||||||||||||||||||||
Balance at December 31, 2006 | 22,614,937 | $ | 73,593,326 | 992,122 | $ | 1,762,911 | 1,984,231 | $ | 1,089,835 | $ | 76,446,072 | |||||||||||||||||
F-7
Table of Contents
Coffeyville Group | Coffeyville | |||||||||||||||||||||
Farmland Industries | Holdings, LLC | Acquisition LLC | ||||||||||||||||||||
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||
62 Days Ended | 304 Days Ended | 174 Days Ended | 233 Days Ended | Year Ended | ||||||||||||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||||||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||
Cash flows from operating activities: | ||||||||||||||||||||||
Net income (loss) | $ | 11,212,087 | $ | 49,710,212 | $ | 52,396,949 | $ | (119,157,090 | ) | $ | 191,571,323 | |||||||||||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||||||||||||||||
Depreciation and amortization | 432,003 | 2,445,961 | 1,128,005 | 23,954,031 | 51,004,582 | |||||||||||||||||
Provision for doubtful accounts | — | 190,468 | (190,468 | ) | 275,189 | 100,255 | ||||||||||||||||
Amortization of deferred financing costs | — | 1,332,890 | 812,166 | 1,751,041 | 3,336,795 | |||||||||||||||||
Loss on disposition of fixed assets | — | — | — | — | 1,188,360 | |||||||||||||||||
Loss on extinguishment of debt | — | 7,166,110 | 8,093,754 | — | 23,360,306 | |||||||||||||||||
Forgiveness of note receivable | — | — | — | — | 350,000 | |||||||||||||||||
Share-based compensation | — | 1,095,609 | 3,985,991 | 997,568 | 6,181,366 | |||||||||||||||||
Changes in assets and liabilities, net of effect of acquisition: | ||||||||||||||||||||||
Accounts receivable | 19,635,303 | (23,571,436 | ) | (11,334,177 | ) | (34,506,244 | ) | 1,870,636 | ||||||||||||||
Inventories | (6,399,677 | ) | 20,068,625 | (59,045,550 | ) | 1,895,473 | (7,156,975 | ) | ||||||||||||||
Prepaid expenses and other current assets | 25,716,107 | (6,758,666 | ) | (937,543 | ) | (6,491,633 | ) | (5,383,117 | ) | |||||||||||||
Other long-term assets | 715,132 | (5,379,727 | ) | 3,036,659 | (4,651,733 | ) | 1,971,859 | |||||||||||||||
Accounts payable | (6,759,702 | ) | 31,059,282 | 16,124,794 | 40,655,763 | 5,004,826 | ||||||||||||||||
Accrued income taxes | — | 1,301,160 | 4,503,574 | (136,398 | ) | (37,038,777 | ) | |||||||||||||||
Deferred revenue | 8,319,913 | 1,209,008 | (9,073,050 | ) | 9,983,132 | (3,217,637 | ) | |||||||||||||||
Other current liabilities | 364,555 | 12,967,500 | 1,254,196 | 10,499,712 | 15,313,492 | |||||||||||||||||
Payable to swap counterparty | — | — | — | 256,722,289 | (147,021,001 | ) | ||||||||||||||||
Accrued environmental liabilities | (20,057 | ) | (1,746,043 | ) | (1,553,184 | ) | (538,365 | ) | (1,614,283 | ) | ||||||||||||
Other long-term liabilities | — | (689,372 | ) | (297,105 | ) | (295,776 | ) | — | ||||||||||||||
Deferred income taxes | — | (615,680 | ) | 3,803,937 | (98,424,817 | ) | 86,770,299 | |||||||||||||||
Net cash provided by operating activities | 53,215,664 | 89,785,901 | 12,708,948 | 82,532,142 | 186,592,309 | |||||||||||||||||
Cash flows from investing activities: | ||||||||||||||||||||||
Cash paid for acquisition of Original Predecessor | — | (116,599,329 | ) | — | — | — | ||||||||||||||||
Cash paid for acquisition of Immediate Predecessor, net of cash acquired | — | — | — | (685,125,669 | ) | — | ||||||||||||||||
Capital expenditures | — | (14,160,280 | ) | (12,256,793 | ) | (45,172,134 | ) | (240,225,392 | ) | |||||||||||||
Net cash used in investing activities | — | (130,759,609 | ) | (12,256,793 | ) | (730,297,803 | ) | (240,225,392 | ) | |||||||||||||
Cash flows from financing activities: | ||||||||||||||||||||||
Revolving debt payments | — | (57,686,789 | ) | (343,449 | ) | (69,286,016 | ) | (900,000 | ) | |||||||||||||
Revolving debt borrowings | — | 57,743,299 | 492,308 | 69,286,016 | 900,000 | |||||||||||||||||
Proceeds from issuance of long-term debt | — | 171,900,000 | — | 500,000,000 | 805,000,000 | |||||||||||||||||
Principal payments on long-term debt | — | (23,025,000 | ) | (375,000 | ) | (562,500 | ) | (529,437,500 | ) | |||||||||||||
Repayment of capital lease obligation | — | (1,176,424 | ) | — | — | — | ||||||||||||||||
Net divisional equity distribution | (53,216,357 | ) | — | — | — | — | ||||||||||||||||
Payment of financing costs | — | (16,309,917 | ) | — | (24,628,315 | ) | (9,363,681 | ) | ||||||||||||||
Prepayment penalty on extinguishment of debt | — | (1,095,000 | ) | — | — | (5,500,000 | ) | |||||||||||||||
Payment of note receivable | — | — | — | — | 150,000 | |||||||||||||||||
Issuance of members’ equity | — | 63,263,000 | — | 237,660,000 | 20,000,000 | |||||||||||||||||
Distribution of members’ equity | — | (99,987,509 | ) | (52,211,493 | ) | — | (250,000,000 | ) | ||||||||||||||
Net cash provided by (used in) financing activities | (53,216,357 | ) | 93,625,660 | (52,437,634 | ) | 712,469,185 | 30,848,819 | |||||||||||||||
Net increase (decrease) in cash and cash equivalents | (693 | ) | 52,651,952 | (51,985,479 | ) | 64,703,524 | (22,784,264 | ) | ||||||||||||||
Cash and cash equivalents, beginning of period | 2,250 | — | 52,651,952 | — | 64,703,524 | |||||||||||||||||
Cash and cash equivalents, end of period | $ | 1,557 | $ | 52,651,952 | $ | 666,473 | $ | 64,703,524 | $ | 41,919,260 | ||||||||||||
Supplemental disclosures | ||||||||||||||||||||||
Cash paid for income taxes | $ | — | $ | 33,820,000 | $ | 27,040,000 | $ | 35,593,172 | $ | 70,108,638 | ||||||||||||
Cash paid for interest | $ | — | $ | 8,570,069 | $ | 7,287,351 | $ | 23,578,178 | $ | 51,854,047 | ||||||||||||
Non-cash investing and financing activities: | ||||||||||||||||||||||
Accrual of construction in progress additions | $ | — | $ | — | $ | — | $ | — | $ | 45,991,429 | ||||||||||||
Contributed capital through Leiber tax savings | $ | — | $ | — | $ | 728,724 | $ | — | $ | — | ||||||||||||
F-8
Table of Contents
F-9
Table of Contents
F-10
Table of Contents
F-11
Table of Contents
F-12
Table of Contents
F-13
Table of Contents
F-14
Table of Contents
Assets acquired | ||||
Inventories | $ | 100,491,131 | ||
Prepaid expenses and other current assets | 1,085,598 | |||
Property, plant, and equipment | 38,239,154 | |||
Total assets acquired | $ | 139,815,883 | ||
Liabilities assumed | ||||
Deferred revenue | $ | 9,910,897 | ||
Capital lease obligations | 1,176,424 | |||
Accrued environmental liabilities | 10,846,980 | |||
Other long-term liabilities | 1,282,253 | |||
Total liabilities assumed | $ | 23,216,554 | ||
Cash paid for acquisition of Original Predecessor | $ | 116,599,329 | ||
F-15
Table of Contents
Assets acquired | ||||
Cash | $ | 666,473 | ||
Accounts receivable | 37,328,997 | |||
Inventories | 156,171,291 | |||
Prepaid expenses and other current assets | 4,865,241 | |||
Intangibles, contractual agreements | 1,322,000 | |||
Goodwill | 83,774,885 | |||
Other long-term assets | 3,837,647 | |||
Property, plant, and equipment | 750,910,245 | |||
Total assets acquired | $ | 1,038,876,779 | ||
Liabilities assumed | ||||
Accounts payable | $ | 47,259,070 | ||
Other current liabilities | 16,017,210 | |||
Current income taxes | 5,076,012 | |||
Deferred income taxes | 276,888,816 | |||
Other long-term liabilities | 7,843,529 | |||
Total liabilities assumed | $ | 353,084,637 | ||
Cash paid for acquisition of Immediate Predecessor | $ | 685,792,142 | ||
F-16
Table of Contents
Net income for the year ended December 31, 2006 | $ | 191,571,323 | ||
Pro forma weighted average shares outstanding: | ||||
Existing CVR common shares | 100 | |||
Effect of 628,667.20 to 1 stock split | 62,866,620 | |||
Issuance of common shares to management in exchange for subsidiary shares | 247,471 | |||
Issuance of common shares to employees | 27,400 | |||
Issuance of common shares in this offering | 18,500,000 | |||
Effect of dividends in excess of earnings | 3,075,194 | |||
Basic weighted average shares outstanding | 84,716,785 | |||
Dilutive securities — issuance of nonvested common shares to board directors | 17,500 | |||
Diluted weighted average shares outstanding | 84,734,285 | |||
Pro forma basic earnings per share | $ | 2.26 | ||
Pro forma dilutive earnings per share | $ | 2.26 |
F-17
Table of Contents
F-18
Table of Contents
Asset | Range of useful lives, in years | |||
Improvements to land | 15 to 20 | |||
Buildings | 20 to 30 | |||
Machinery and equipment | 5 to 30 | |||
Automotive equipment | 5 | |||
Furniture and fixtures | 3 to 7 |
F-19
Table of Contents
F-20
Table of Contents
F-21
Table of Contents
F-22
Table of Contents
F-23
Table of Contents
F-24
Table of Contents
F-25
Table of Contents
• Estimated forfeiture rate | None | |||
• Explicit service period | Based on forfeiture schedule below | |||
• Grant-date fair value — controlling basis | $5.16 per share | |||
• Marketability and minority interest discounts | $1.24 per share (24% discount) | |||
• Volatility | 37% |
F-26
Table of Contents
• Estimated forfeiture rate | None | |||
• Explicit service period | Based on forfeiture schedule below | |||
• Grant-date fair value — controlling basis | $8.15 per share | |||
• Marketability and minority interest discounts | $1.63 per share (20% discount) | |||
• Volatility | 41% |
Forfeiture | ||||
Minimum Period Held | Percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
• Estimated forfeiture rate | None | |||
• Derived service period | 6 years | |||
• Grant-date fair value — controlling basis | $2.91 per share | |||
• Marketability and minority interest discounts | $0.70 per share (24% discount) | |||
• Volatility | 37% |
F-27
Table of Contents
• Estimated forfeiture rate | None | |||
• Derived service period | 6 years | |||
• Grant-date fair value — controlling basis | $8.15 per share | |||
• Marketability and minority interest discounts | $1.63 per share (20% discount) | |||
• Volatility | 41% |
Subject to | ||||
Forfeiture | ||||
Minimum Period Held | Percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
F-28
Table of Contents
Override | Override | |||||||
Year Ending December 31, | Operating Units | Value Units | ||||||
2007 | $ | 1,198,045 | $ | 883,684 | ||||
2008 | 670,385 | 883,684 | ||||||
2009 | 344,178 | 883,684 | ||||||
2010 | 102,079 | 883,684 | ||||||
2011 | — | 385,383 | ||||||
$ | 2,314,687 | $ | 3,920,119 | |||||
F-29
Table of Contents
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
Finished goods | $ | 58,513 | $ | 59,722 | ||||
Raw materials and catalysts | 47,437 | 60,810 | ||||||
In-process inventories | 33,397 | 18,441 | ||||||
Parts and supplies | 14,929 | 22,460 | ||||||
$ | 154,276 | $ | 161,433 | |||||
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
Land and improvements | $ | 9,346 | $ | 11,028 | ||||
Buildings | 10,306 | 11,042 | ||||||
Machinery and equipment | 715,381 | 864,140 | ||||||
Automotive equipment | 3,396 | 4,175 | ||||||
Furniture and fixtures | 271 | 5,364 | ||||||
Leasehold improvements | — | 887 | ||||||
Construction in progress | 57,382 | 184,531 | ||||||
796,082 | 1,081,167 | |||||||
Accumulated depreciation | 23,569 | 74,011 | ||||||
$ | 772,513 | $ | 1,007,156 | |||||
F-30
Table of Contents
Contractual | ||||
Year Ending December 31, | Agreements | |||
2007 | 165 | |||
2008 | 64 | |||
2009 | 33 | |||
2010 | 33 | |||
2011 | 33 | |||
Thereafter | 310 | |||
638 | ||||
F-31
Table of Contents
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
Deferred financing costs | $ | 24,628 | $ | 11,065 | ||||
Less accumulated amortization | 1,751 | 21 | ||||||
Unamortized deferred financing costs | 22,877 | 11,044 | ||||||
Less current portion | 3,352 | 1,916 | ||||||
$ | 19,525 | $ | 9,128 | |||||
F-32
Table of Contents
Deferred | ||||
Year Ending December 31, | Financing | |||
2007 | $ | 1,916 | ||
2008 | 1,910 | |||
2009 | 1,893 | |||
2010 | 1,878 | |||
2011 | 1,378 | |||
Thereafter | 2,069 | |||
$ | 11,044 | |||
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
Prepaid insurance charges | $ | 2,447 | $ | 1,070 | ||||
Non-current receivables | 4,889 | 4,040 | ||||||
Other assets | 1,082 | 1,219 | ||||||
$ | 8,418 | $ | 6,329 | |||||
Prepaid | ||||
Year Ending December 31, | Insurance | |||
2007 | $ | 6,197 | ||
2008 | 292 | |||
2009 | 292 | |||
2010 | 292 | |||
2011 | 194 | |||
7,267 | ||||
Less current portion | 6,197 | |||
Total long-term | $ | 1,070 | ||
F-33
Table of Contents
F-34
Table of Contents
Minimum Interest | Maximum | |||||||
Fiscal Quarter Ending | Coverage Ratio | Leverage Ratio | ||||||
March 31, 2007 | 2.25:1.00 | 4.75:1.00 | ||||||
June 30, 2007 | 2.50:1.00 | 4.50:1.00 | ||||||
September 30, 2007 | 2.75:1.00 | 4.25:1.00 | ||||||
December 31, 2007 | 2.75:1.00 | 4.00:1.00 | ||||||
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 |
F-35
Table of Contents
Year Ending December 31, | Amount | |||
2007 | $ | 5,797,981 | ||
2008 | 7,663,223 | |||
2009 | 7,586,878 | |||
2010 | 7,511,293 | |||
2011 | 7,436,461 | |||
Thereafter | 739,004,164 | |||
$ | 775,000,000 | |||
F-36
Table of Contents
Immediate Predecessor | Successor | ||||||||||||||||
304 Days | 174 Days | 233 Days | Year | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
December 31, | June 23, | December 31, | December 31, | ||||||||||||||
2004 | 2005 | 2005 | 2006 | ||||||||||||||
Current — Federal | $ | 27,902 | $ | 26,145 | $ | 29,000 | $ | 26,096 | |||||||||
State | 6,519 | 6,099 | 6,457 | 6,974 | |||||||||||||
Total current provision | 34,421 | 32,244 | 35,457 | 33,070 | |||||||||||||
Deferred — Federal | (499 | ) | 3,083 | (80,500 | ) | 69,836 | |||||||||||
State | (117 | ) | 721 | (17,925 | ) | 16,934 | |||||||||||
Total deferred provision | (616 | ) | 3,804 | (98,425 | ) | 86,770 | |||||||||||
Total income taxes | $ | 33,805 | $ | 36,048 | $ | (62,968 | ) | $ | 119,840 | ||||||||
Immediate Predecessor | Successor | ||||||||||||||||
304 Days | 174 Days | 233 Days | Year | ||||||||||||||
Ended | Ended | Ended | Ended | ||||||||||||||
December 31, | June 23, | December 31, | December 31, | ||||||||||||||
2004 | 2005 | 2005 | 2006 | ||||||||||||||
Computed expected taxes | $ | 29,230 | $ | 30,956 | $ | (63,744 | ) | $ | 108,994 | ||||||||
Loss on unexercised option agreements with no tax benefit to Successor | — | — | 8,750 | — | |||||||||||||
State taxes, net of federal benefit | 4,162 | 4,433 | (7,454 | ) | 15,540 | ||||||||||||
Section 199, manufacturing deduction | — | (825 | ) | (897 | ) | (1,089 | ) | ||||||||||
Ultra low sulfur diesel credit, net | — | — | — | (4,462 | ) | ||||||||||||
Other, net | 413 | 1,484 | 377 | 857 | |||||||||||||
Total income tax expense | $ | 33,805 | $ | 36,048 | $ | (62,968 | ) | $ | 119,840 | ||||||||
F-37
Table of Contents
Successor | ||||||||
December 31, | December 31, | |||||||
2005 | 2006 | |||||||
Deferred tax assets: | ||||||||
Allowance for doubtful accounts | $ | 109 | $ | 150 | ||||
Personnel accruals | 483 | 5,072 | ||||||
Inventories | 560 | 673 | ||||||
Unrealized derivative losses, net | 91,226 | 40,389 | ||||||
Deferred tax assets | 92,378 | 46,284 | ||||||
Deferred tax liabilities: | ||||||||
Property, plant, and equipment | 269,462 | 309,472 | ||||||
Environmental obligations | 1,238 | 1,061 | ||||||
Other | 142 | 985 | ||||||
Deferred tax liabilities | 270,842 | 311,518 | ||||||
Net deferred tax liabilities | $ | (178,464 | ) | $ | (265,234 | ) | ||
F-38
Table of Contents
Operating | Unconditional | |||||||
Year Ending December 31, | Leases | Purchase Obligations | ||||||
2007 | $ | 3,892,374 | $ | 19,279,245 | ||||
2008 | 3,855,630 | 19,034,729 | ||||||
2009 | 2,880,456 | 19,001,745 | ||||||
2010 | 1,525,474 | 16,610,265 | ||||||
2011 | 853,094 | 14,740,348 | ||||||
Thereafter | 107,113 | 132,414,592 | ||||||
$ | 13,114,141 | $ | 221,080,924 | |||||
F-39
Table of Contents
F-40
Table of Contents
F-41
Table of Contents
Year Ending December 31, | Amount | |||
2007 | $ | 1,828 | ||
2008 | 904 | |||
2009 | 493 | |||
2010 | 341 | |||
2011 | 341 | |||
Thereafter | 6,001 | |||
Undiscounted total | 9,908 | |||
Less amounts representing interest at 4.83% | 2,685 | |||
Accrued environmental liabilities at December 31, 2006 | $ | 7,223 | ||
F-42
Table of Contents
Immediate Predecessor | Successor | ||||||||||||||||
304 Days Ended | 174 Days Ended | 233 Days Ended | Year Ended | ||||||||||||||
December 31, | June 23, | December 31, | December 31, | ||||||||||||||
2004 | 2005 | 2005 | 2006 | ||||||||||||||
Realized loss on swap agreements | $ | — | $ | — | $ | (59,300,670 | ) | $ | (46,768,651 | ) | |||||||
Unrealized gain (loss) on swap agreements | — | — | (235,851,568 | ) | 126,771,145 | ||||||||||||
Loss on termination of swap | — | — | (25,000,000 | ) | — | ||||||||||||
Realized gain (loss) on other agreements | (219,096 | ) | (7,664,725 | ) | (1,867,513 | ) | 8,361,050 | ||||||||||
Unrealized gain (loss) on other agreements | 765,700 | — | (1,697,640 | ) | 2,411,340 | ||||||||||||
Realized gain (loss) on interest rate swap agreements | — | — | (103,731 | ) | 4,398,164 | ||||||||||||
Unrealized gain (loss) on interest rate swap agreements | — | — | 7,759,011 | (679,908 | ) | ||||||||||||
Total gain (loss) on derivatives | $ | 546,604 | $ | (7,664,725 | ) | $ | (316,062,111 | ) | $ | 94,493,140 | |||||||
F-43
Table of Contents
Notional | Fixed | |||||||
Period Covered | Amount | Interest Rate | ||||||
December 31, 2006 to March 30, 2007 | $ | 375 million | 4.038 | % | ||||
March 31, 2007 to June 29, 2007 | 325 million | 4.038 | % | |||||
June 29, 2007 to March 30, 2008 | 325 million | 4.195 | % | |||||
March 31, 2008 to March 30, 2009 | 250 million | 4.195 | % | |||||
March 31, 2009 to March 30, 2010 | 180 million | 4.195 | % | |||||
March 31, 2010 to June 29, 2010 | 110 million | 4.195 | % |
F-44
Table of Contents
F-45
Table of Contents
F-46
Table of Contents
F-47
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||
62-Day Period | 304-Day Period | 174-Day Period | 233-Day Period | Year | ||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||||||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||
Net sales | ||||||||||||||||||||||
Petroleum | $ | 241,640,365 | $ | 1,390,768,126 | $ | 903,802,983 | $ | 1,363,390,142 | $ | 2,880,442,544 | ||||||||||||
Nitrogen Fertilizer | 19,446,164 | 93,422,503 | 79,347,843 | 93,651,855 | 162,464,533 | |||||||||||||||||
Other | — | — | — | — | — | |||||||||||||||||
Intersegment elimination | — | (4,297,440 | ) | (2,444,565 | ) | (2,782,455 | ) | (5,339,715 | ) | |||||||||||||
Total | $ | 261,086,529 | $ | 1,479,893,189 | $ | 980,706,261 | $ | 1,454,259,542 | $ | 3,037,567,362 | ||||||||||||
Cost of product sold (exclusive of depreciation and amortization) | ||||||||||||||||||||||
Petroleum | $ | 217,375,945 | $ | 1,228,074,299 | $ | 761,719,405 | $ | 1,156,208,301 | $ | 2,422,717,768 | ||||||||||||
Nitrogen Fertilizer | 4,073,232 | 20,433,642 | 9,125,852 | 14,503,824 | 25,898,902 | |||||||||||||||||
Other | — | (2 | ) | — | — | — | ||||||||||||||||
Intersegment elimination | — | (4,300,516 | ) | (2,778,079 | ) | (2,574,908 | ) | (5,241,927 | ) | |||||||||||||
Total | $ | 221,449,177 | $ | 1,244,207,423 | $ | 768,067,178 | $ | 1,168,137,217 | $ | 2,443,374,743 | ||||||||||||
Direct operating expenses (exclusive of depreciation and amortization) | ||||||||||||||||||||||
Petroleum | $ | 14,925,611 | $ | 73,231,607 | $ | 52,611,148 | $ | 56,159,473 | $ | 135,296,759 | ||||||||||||
Nitrogen Fertilizer | 8,427,851 | 43,752,777 | 28,302,714 | 29,153,729 | 63,683,224 | |||||||||||||||||
Other | — | — | — | — | — | |||||||||||||||||
Total | $ | 23,353,462 | $ | 116,984,384 | $ | 80,913,862 | $ | 85,313,202 | $ | 198,979,983 | ||||||||||||
Depreciation and amortization | ||||||||||||||||||||||
Petroleum | $ | 271,284 | $ | 1,522,464 | $ | 770,728 | $ | 15,566,987 | $ | 33,016,619 | ||||||||||||
Nitrogen Fertilizer | 160,719 | 855,289 | 316,446 | 8,360,911 | 17,125,897 | |||||||||||||||||
Other | — | 68,208 | 40,831 | 26,133 | 862,066 | |||||||||||||||||
Total | $ | 432,003 | $ | 2,445,961 | $ | 1,128,005 | $ | 23,954,031 | $ | 51,004,582 | ||||||||||||
Operating income (loss) | ||||||||||||||||||||||
Petroleum | $ | 7,687,745 | $ | 77,094,034 | $ | 76,654,428 | $ | 123,044,854 | $ | 245,577,550 | ||||||||||||
Nitrogen Fertilizer | 3,514,997 | 22,874,227 | 35,267,752 | 35,731,056 | 36,842,252 | |||||||||||||||||
Other | — | 3,076 | 333,514 | (240,848 | ) | (811,869 | ) | |||||||||||||||
Total | $ | 11,202,742 | $ | 99,971,337 | $ | 112,255,694 | $ | 158,535,062 | $ | 281,607,933 | ||||||||||||
Capital expenditures | ||||||||||||||||||||||
Petroleum | $ | — | $ | 11,267,244 | $ | 10,790,042 | $ | 42,107,751 | $ | 223,553,105 | ||||||||||||
Nitrogen fertilizer | — | 2,697,852 | 1,434,921 | 2,017,385 | 13,257,681 | |||||||||||||||||
Other | — | 195,184 | 31,830 | 1,046,998 | 3,414,606 | |||||||||||||||||
Total | $ | — | $ | 14,160,280 | $ | 12,256,793 | $ | 45,172,134 | $ | 240,225,392 | ||||||||||||
F-48
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||||||||||||
62-Day Period | 304-Day Period | 174-Day Period | 233-Day Period | Year | ||||||||||||||||||
Ended | Ended | Ended | Ended | Ended | ||||||||||||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||||||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||||||||||||
Total assets | ||||||||||||||||||||||
Petroleum | $ | 145,861,715 | $ | 664,870,240 | $ | 907,314,951 | ||||||||||||||||
Nitrogen Fertilizer | 83,561,149 | 425,333,621 | 417,657,093 | |||||||||||||||||||
Other | (265,527 | ) | 131,344,042 | 124,507,471 | ||||||||||||||||||
Total | $ | 229,157,337 | $ | 1,221,547,903 | $ | 1,449,479,515 | ||||||||||||||||
Goodwill | ||||||||||||||||||||||
Petroleum | $ | — | $ | 42,806,422 | $ | 42,806,422 | ||||||||||||||||
Nitrogen Fertilizer | — | 40,968,463 | 40,968,463 | |||||||||||||||||||
Other | — | — | — | |||||||||||||||||||
Total | $ | — | $ | 83,774,885 | $ | 83,774,885 | ||||||||||||||||
Original Predecessor | Immediate Predecessor | Successor | ||||||||||
62-Day Period | 304-Day Period | 174-Day Period | 233-Day Period | Year | ||||||||
Ended | Ended | Ended | Ended | Ended | ||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||
Petroleum | ||||||||||||
Customer A | 10% | 18% | 17% | 16% | 2% | |||||||
Customer B | 25% | 10% | 5% | 6% | 5% | |||||||
Customer C | 18% | 17% | 17% | 15% | 15% | |||||||
Customer D | — | 8% | 14% | 17% | 10% | |||||||
Customer E | 9% | 15% | 11% | 11% | 10% | |||||||
62% | 68% | 64% | 65% | 42% | ||||||||
Nitrogen Fertilizer | ||||||||||||
Customer F | 48% | 24% | 16% | 10% | 5% | |||||||
Customer G | 0% | 5% | 9% | 10% | 6% | |||||||
48% | 29% | 25% | 20% | 11% | ||||||||
F-49
Table of Contents
Original Predecessor | Immediate Predecessor | Successor | ||||||||||
62-Day Period | 304-Day Period | 174-Day Period | 233-Day Period | Year | ||||||||
Ended | Ended | Ended | Ended | Ended | ||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||
Supplier A | 34% | 68% | 82% | 73% | 0% | |||||||
Supplier B | — | — | — | — | 67% | |||||||
34% | 68% | 82% | 73% | 67% | ||||||||
Original Predecessor | Immediate Predecessor | Successor | ||||||||||
62-Day Period | 304-Day Period | 174-Day Period | 233-Day Period | Year | ||||||||
Ended | Ended | Ended | Ended | Ended | ||||||||
March 2, | December 31, | June 23, | December 31, | December 31, | ||||||||
2004 | 2004 | 2005 | 2005 | 2006 | ||||||||
Supplier | 4% | 5% | 4% | 5% | 8% | |||||||
F-50
Table of Contents
Pro forma | ||||||||||||
December 31, | June 30, | June 30, | ||||||||||
2006 | 2007 | 2007 | ||||||||||
(unaudited) | (unaudited) | |||||||||||
(Note 2) | ||||||||||||
ASSETS | ||||||||||||
Current assets: | ||||||||||||
Cash and cash equivalents | $ | 41,919,260 | $ | 23,077,422 | $ | 61,107,962 | ||||||
Accounts receivable, net of allowance for doubtful accounts of $375,443 and $384,598, respectively | 69,589,161 | 76,022,457 | 76,022,457 | |||||||||
Inventories | 161,432,793 | 179,243,439 | 179,243,439 | |||||||||
Prepaid expenses and other current assets | 18,524,017 | 23,255,906 | 15,820,453 | |||||||||
Income tax receivable | 32,099,163 | 133,467,799 | 129,241,049 | |||||||||
Deferred income taxes | 18,888,660 | 133,008,581 | 133,008,581 | |||||||||
Total current assets | 342,453,054 | 568,075,604 | 594,443,941 | |||||||||
Property, plant, and equipment, net of accumulated depreciation | 1,007,155,873 | 1,157,972,453 | 1,158,604,962 | |||||||||
Intangible assets, net | 638,456 | 535,525 | 535,525 | |||||||||
Goodwill | 83,774,885 | 83,774,885 | 83,774,885 | |||||||||
Deferred financing costs, net | 9,128,258 | 8,571,677 | 10,541,137 | |||||||||
Other long-term assets | 6,328,989 | 7,305,374 | 7,305,374 | |||||||||
�� | ||||||||||||
Total assets | $ | 1,449,479,515 | $ | 1,826,235,518 | $ | 1,855,205,824 | ||||||
LIABILITIES AND EQUITY | ||||||||||||
Current liabilities: | ||||||||||||
Current portion of long-term debt | $ | 5,797,981 | $ | 7,701,683 | $ | 50,784,484 | ||||||
Revolving debt | — | 40,000,000 | — | |||||||||
Accounts payable | 138,911,088 | 138,394,089 | 136,440,792 | |||||||||
Personnel accruals | 24,731,283 | 25,452,206 | 25,452,206 | |||||||||
Accrued taxes other than income taxes | 9,034,841 | 11,506,841 | 11,506,841 | |||||||||
Payable to swap counterparty | 36,894,802 | 267,118,025 | 267,118,025 | |||||||||
Deferred revenue | 8,812,350 | 1,383,699 | 1,383,699 | |||||||||
Other current liabilities | 6,017,435 | 23,024,739 | 23,024,739 | |||||||||
Total current liabilities | 230,199,780 | 514,581,282 | 515,710,786 | |||||||||
Long-term liabilities: | ||||||||||||
Long-term debt, less current portion | 769,202,019 | 765,360,817 | 488,143,360 | |||||||||
Accrued environmental liabilities | 5,395,105 | 5,612,516 | 5,612,516 | |||||||||
Deferred income taxes | 284,122,958 | 387,155,256 | 387,155,256 | |||||||||
Payable to swap counterparty | 72,806,486 | 119,133,755 | 119,133,755 | |||||||||
Total long-term liabilities | 1,131,526,568 | 1,277,262,344 | 1,000,044,887 | |||||||||
Minority interest in subsidiaries | 4,326,188 | 4,904,421 | 10,600,000 | |||||||||
Management voting common units subject to redemption, 201,063 units issued and outstanding in 2006 and 2007, respectively | 6,980,907 | 7,795,213 | — | |||||||||
Members’ equity: | ||||||||||||
Voting common units, 22,614,937 units issued and outstanding in 2006 and 2007, respectively | 73,593,326 | 17,636,575 | — | |||||||||
Management nonvoting override units, 2,976,353 units issued and outstanding in 2006 and 2007, respectively | 2,852,746 | 4,055,683 | — | |||||||||
Total members’ equity | 76,446,072 | 21,692,258 | — | |||||||||
PRO FORMA STOCKHOLDERS’ EQUITY | ||||||||||||
Stockholders’ equity: | ||||||||||||
Common stock, $0.01 par value per share, 350,000,000 shares authorized; 81,641,591 shares issued and outstanding | 816,416 | |||||||||||
Additional paid-in capital | 328,033,735 | |||||||||||
Retained earnings | ||||||||||||
Total pro forma stockholders’ equity | 328,850,151 | |||||||||||
Commitments and contingencies | ||||||||||||
Total liabilities and equity | $ | 1,449,479,515 | $ | 1,826,235,518 | $ | 1,855,205,824 | ||||||
F-51
Table of Contents
Six Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Net sales | $ | 1,550,566,629 | $ | 1,233,895,912 | ||||
Operating costs and expenses: | ||||||||
Cost of product sold (exclusive of depreciation and amortization) | 1,203,449,205 | 873,293,323 | ||||||
Direct operating expenses (exclusive of depreciation and amortization) | 87,765,710 | 174,366,084 | ||||||
Selling, general and administrative expenses (exclusive of depreciation and amortization) | 20,469,471 | 28,087,293 | ||||||
Costs associated with flood | — | 2,138,942 | ||||||
Depreciation and amortization | 24,022,108 | 32,192,458 | ||||||
Total operating costs and expenses | 1,335,706,494 | 1,110,078,100 | ||||||
Operating income | 214,860,135 | 123,817,812 | ||||||
Other income (expense): | ||||||||
Interest expense and other financing costs | (22,335,620 | ) | (27,619,423 | ) | ||||
Interest income | 1,683,157 | 613,316 | ||||||
Loss on derivatives | (126,462,043 | ) | (292,444,434 | ) | ||||
Other income (expense) | (262,864 | ) | 102,234 | |||||
Total other expense | (147,377,370 | ) | (319,348,307 | ) | ||||
Income (loss) before income taxes and minority interest in subsidiaries | 67,482,765 | (195,530,495 | ) | |||||
Income tax expense (benefit) | 25,725,556 | (140,966,282 | ) | |||||
Minority interest in (income) loss of subsidiaries | — | 256,748 | ||||||
Net income (loss) | $ | 41,757,209 | $ | (54,307,465 | ) | |||
Unaudited Pro Forma Information (Note 2) | ||||||||
Basic earnings (loss) per common share | $ | 0.51 | $ | (0.67 | ) | |||
Diluted earnings (loss) per common share | $ | 0.51 | $ | (0.67 | ) | |||
Basic weighted average common shares outstanding | 81,641,591 | 81,641,591 | ||||||
Diluted weighted average common shares outstanding | 81,659,091 | 81,641,591 |
F-52
Table of Contents
Six Months Ended | Six Months Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Cash flows from operating activities: | ||||||||
Net income (loss) | $ | 41,757,209 | $ | (54,307,465 | ) | |||
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 24,022,108 | 32,192,458 | ||||||
Provision for doubtful accounts | 79,716 | 9,155 | ||||||
Amortization of deferred financing costs | 1,664,316 | 951,329 | ||||||
Loss on disposition of fixed assets | 437,952 | 1,154,661 | ||||||
Share-based compensation | 912,579 | 1,202,937 | ||||||
Minority interest in loss of subsidiaries | — | (256,748 | ) | |||||
Changes in assets and liabilities: | ||||||||
Accounts receivable | 7,975,871 | (6,442,451 | ) | |||||
Inventories | (25,382,647 | ) | (17,810,646 | ) | ||||
Prepaid expenses and other current assets | (594,392 | ) | (4,642,300 | ) | ||||
Other long-term assets | (2,990,407 | ) | (1,068,933 | ) | ||||
Accounts payable | (3,179,621 | ) | 29,567,869 | |||||
Accrued income taxes | 6,354,775 | (101,368,636 | ) | |||||
Deferred revenue | (10,475,674 | ) | (7,428,651 | ) | ||||
Other current liabilities | (6,939,698 | ) | 20,200,228 | |||||
Payable to swap counterparty | 112,246,434 | 276,550,492 | ||||||
Accrued environmental liabilities | (925,900 | ) | 217,411 | |||||
Other long-term liabilities | 1,471,269 | — | ||||||
Deferred income taxes | (26,124,919 | ) | (11,087,623 | ) | ||||
Net cash provided by operating activities | 120,308,971 | 157,633,087 | ||||||
Cash flows from investing activities: | ||||||||
Capital expenditures | (86,174,655 | ) | (214,053,088 | ) | ||||
Net cash used in investing activities | (86,174,655 | ) | (214,053,088 | ) | ||||
Cash flows from financing activities: | ||||||||
Revolving debt payments | — | (117,000,000 | ) | |||||
Revolving debt borrowings | — | 157,000,000 | ||||||
Proceeds from issuance of long-term debt | 10,000,000 | — | ||||||
Principal payments on long-term debt | (1,120,785 | ) | (1,937,500 | ) | ||||
Payment of financing costs | — | (484,337 | ) | |||||
Issuance of members’ equity | 20,000,000 | — | ||||||
Payment of note receivable | 150,000 | — | ||||||
Net cash provided by financing activities | 29,029,215 | 37,578,163 | ||||||
Net increase (decrease) in cash and cash equivalents | 63,163,531 | (18,841,838 | ) | |||||
Cash and cash equivalents, beginning of period | 64,703,524 | 41,919,260 | ||||||
Cash and cash equivalents, end of period | $ | 127,867,055 | $ | 23,077,422 | ||||
Supplemental disclosures | ||||||||
Cash paid for income taxes, net of refunds (received) | $ | 45,495,700 | $ | (28,510,023 | ) | |||
Cash paid for interest | $ | 24,712,898 | $ | 17,589,062 | ||||
Non-cash investing and financing activities: | ||||||||
Accrual of construction in progress additions | $ | 25,109,043 | $ | (30,084,868 | ) |
F-53
Table of Contents
(1) | Organization and Basis of Presentation |
F-54
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(2) | Unaudited Pro Forma Information |
F-55
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, 2006 | June 30, 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Net income (loss) | $ | 41,757,209 | $ | (54,307,465 | ) | |||
Pro forma weighted average shares outstanding: | ||||||||
Existing 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 | 27,400 | 27,400 | ||||||
Issuance of common shares in this offering | 18,500,000 | 18,500,000 | ||||||
Basic weighted average shares outstanding | 81,641,591 | 81,641,591 | ||||||
Dilutive securities — issuance of nonvested common shares to board of directors | 17,500 | — | ||||||
Diluted weighted average shares outstanding | 81,659,091 | 81,641,591 | ||||||
Pro forma basic earnings (loss) per share | $ | 0.51 | $ | (0.67 | ) | |||
Pro forma dilutive earnings (loss) per share | $ | 0.51 | $ | (0.67 | ) |
• | The estimated payment of a $10.6 million dividend to Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC; | |
• | The receipt of gross proceeds of $10.6 million for the sale of the managing general partner interest in the Partnership, through sale of the managing general partner, to Coffeyville Acquisition III LLC at estimated fair market value, as determined by the board of directors, after consultation with management, resulting in a taxable gain to the Company; | |
• | The exchange of the Company’s chief executive officer’s shares in two of CVR’s subsidiaries for shares of CVR common stock at fair market value, resulting in an estimated step-up in basis in the Company’s property, plant, and equipment of approximately $0.6 million; | |
• | The issuance of 18,500,000 shares of CVR common stock as a result of the public offering at an assumed initial offering price of $19.00 per share, resulting in aggregate gross proceeds of $351.5 million; | |
• | The payment of underwriters’ discounts and commissions and estimated offering expenses totaling approximately $32.8 million of which $5.5 million had been prepaid as of June 30, 2007 and $2.0 million had been accrued as of June 30, 2007; | |
• | The conversion from a partnership structure to a corporate structure; |
F-56
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
• | The repayment of term debt of $280 million with the net proceeds of the offering; | |
• | The repayment of revolver borrowings of $40.0 million and 4.1 million of the $25 million unsecured facility with the remaining net proceeds of the offering; | |
• | The accrual of the tax liability associated with the estimated tax gain recognized on the sale of the managing general partner interest at estimated fair market value; | |
• | The funding of the new credit facilities of $25 million secured and $25 million unsecured entered into in August 2007 and the related deferral of financing fees; and | |
• | The payment of a $10.0 million termination fee in connection with the termination of the management agreements payable to Goldman, Sachs & Co. and Kelso & Company, L.P. in conjunction with the offering. |
(3) | New Accounting Pronouncements |
(4) | Members’ Equity |
F-57
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
• Estimated forfeiture rate | None | |
• Explicit service period | Based on forfeiture schedule below | |
• Grant-date fair value — controlling basis | $5.16 per share | |
• Marketability and minority interest discounts | $1.24 per share (24% discount) | |
• Volatility | 37% |
F-58
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
• Estimated forfeiture rate | None | |
• Explicit service period | Based on forfeiture schedule below | |
• Grant-date fair value — controlling basis | $8.15 per share | |
• Marketability and minority interest discounts | $1.63 per share (20% discount) | |
• Volatility | 41% |
Minimum | ||||
period | Forfeiture | |||
held | percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
F-59
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
• Estimated forfeiture rate | None | |
• Derived service period | 6 years | |
• Grant-date fair value — controlling basis | $2.91 per share | |
• Marketability and minority interest discounts | $0.70 per share (24% discount) | |
• Volatility | 37% |
• Estimated forfeiture rate | None | |
• Derived service period | 6 years | |
• Grant-date fair value — controlling basis | $8.15 per share | |
• Marketability and minority interest discounts | $1.63 per share (20% discount) | |
• Volatility | 41% |
F-60
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Minimum | Subject to | |||
period | forfeiture | |||
held | percentage | |||
2 years | 75 | % | ||
3 years | 50 | % | ||
4 years | 25 | % | ||
5 years | 0 | % |
Override | Override | |||||||
Operating Units | Value Units | |||||||
Six months ending December 31, 2007 | $ | 436,951 | $ | 441,842 | ||||
Year ending December 31, 2008 | 670,385 | 883,684 | ||||||
Year ending December 31, 2009 | 344,178 | 883,684 | ||||||
Year ending December 31, 2010 | 102,079 | 883,684 | ||||||
Year ending December 31, 2011 | — | 385,383 | ||||||
$ | 1,553,593 | $ | 3,478,277 | |||||
F-61
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
December 31, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Finished goods | $ | 59,722 | $ | 68,811 | ||||
Raw materials and catalysts | 60,810 | 69,911 | ||||||
In-process inventories | 18,441 | 21,306 | ||||||
Parts and supplies | 22,460 | 19,215 | ||||||
$ | 161,433 | $ | 179,243 | |||||
F-62
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
F-63
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Operating | Unconditional | |||||||
Leases | Purchase Obligations | |||||||
Six months ending December 31, 2007 | $ | 1,724,829 | $ | 12,976,569 | ||||
Year ending December 31, 2008 | 3,888,005 | 21,130,009 | ||||||
Year ending December 31, 2009 | 2,940,633 | 21,095,945 | ||||||
Year ending December 31, 2010 | 1,591,818 | 46,193,352 | ||||||
Year ending December 31, 2011 | 857,494 | 44,323,435 | ||||||
Year ending December 31, 2012 | 106,038 | 41,731,623 | ||||||
Thereafter | 2,025 | 329,537,331 | ||||||
$ | 11,110,842 | $ | 516,988,264 | |||||
F-64
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
F-65
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
F-66
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Amount | ||||
Six months ending December 31, 2007 | $ | 997 | ||
Year ending December 31, 2008 | 999 | |||
Year ending December 31, 2009 | 894 | |||
Year ending December 31, 2010 | 562 | |||
Year ending December 31, 2011 | 341 | |||
Year ending December 31, 2012 | 760 | |||
Thereafter | 5,184 | |||
Undiscounted total | 9,737 | |||
Less amounts representing interest at 5.09% | 2,692 | |||
Accrued environmental liabilities at June 30, 2007 | $ | 7,045 | ||
F-67
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(11) | Derivative Financial Instruments |
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Realized loss on swap agreements | $ | (33,412,707 | ) | $ | (97,215,267 | ) | ||
Unrealized loss on swap agreements | (98,223,459 | ) | (188,490,432 | ) | ||||
Realized loss on other agreements | (2,662,334 | ) | (7,587,011 | ) | ||||
Unrealized gain (loss) on other agreements | 402,853 | (1,563,517 | ) | |||||
Realized gain on interest rate swap agreements | 1,741,423 | 2,317,443 | ||||||
Unrealized gain on interest rate swap agreements | 5,692,181 | 94,350 | ||||||
Total loss on derivatives | $ | (126,462,043 | ) | $ | (292,444,434 | ) | ||
F-68
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Notional | Fixed | |||||||
Period covered | amount | interest rate | ||||||
June 29, 2007 to March 30, 2008 | 325 million | 4.195% | ||||||
March 31, 2008 to March 30, 2009 | 250 million | 4.195% | ||||||
March 31, 2009 to March 30, 2010 | 180 million | 4.195% | ||||||
March 31, 2010 to June 29, 2010 | 110 million | 4.195% |
F-69
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(12) | Related Party Transactions |
F-70
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
(13) | Business Segments |
F-71
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Net sales | ||||||||
Petroleum | $ | 1,457,663,348 | $ | 1,161,442,217 | ||||
Nitrogen Fertilizer | 95,632,021 | 74,334,290 | ||||||
Other | — | — | ||||||
Intersegment eliminations | (2,728,740 | ) | (1,880,595 | ) | ||||
Total | $ | 1,550,566,629 | $ | 1,233,895,912 | ||||
Cost of product sold (exclusive of depreciation and amortization) | ||||||||
Petroleum | $ | 1,190,545,256 | $ | 869,069,147 | ||||
Nitrogen Fertilizer | 15,574,653 | 6,190,154 | ||||||
Other | — | — | ||||||
Intersegment eliminations | (2,670,704 | ) | (1,965,978 | ) | ||||
Total | $ | 1,203,449,205 | $ | 873,293,323 | ||||
Direct operating expenses (exclusive of depreciation and amortization) | ||||||||
Petroleum | $ | 59,081,968 | $ | 141,140,133 | ||||
Nitrogen Fertilizer | 28,683,742 | 33,225,951 | ||||||
Other | — | — | ||||||
Total | $ | 87,765,710 | $ | 174,366,084 | ||||
Depreciation and amortization | ||||||||
Petroleum | $ | 15,612,029 | $ | 23,078,914 | ||||
Nitrogen Fertilizer | 8,384,376 | 8,791,349 | ||||||
Other | 25,703 | 322,195 | ||||||
Total | $ | 24,022,108 | $ | 32,192,458 | ||||
Operating income (loss) | ||||||||
Petroleum | $ | 178,023,767 | $ | 102,870,022 | ||||
Nitrogen Fertilizer | 37,065,026 | 21,029,087 | ||||||
Other | (228,658 | ) | (81,297 | ) | ||||
Total | $ | 214,860,135 | $ | 123,817,812 | ||||
F-72
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Capital expenditures | ||||||||
Petroleum | $ | 76,791,026 | $ | 211,087,365 | ||||
Nitrogen fertilizer | 7,605,735 | 2,645,951 | ||||||
Other | 1,777,894 | 319,772 | ||||||
Total | $ | 86,174,655 | $ | 214,053,088 | ||||
Year | Six Months | |||||||
Ended | Ended | |||||||
December 31, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | ||||||||
Total assets | ||||||||
Petroleum | $ | 907,314,951 | $ | 1,097,875,033 | ||||
Nitrogen Fertilizer | 417,657,093 | 409,629,772 | ||||||
Other | 124,507,471 | 318,730,713 | ||||||
Total | $ | 1,449,479,515 | $ | 1,826,235,518 | ||||
Goodwill | ||||||||
Petroleum | 42,806,422 | $ | 42,806,422 | |||||
Nitrogen Fertilizer | 40,968,463 | 40,968,463 | ||||||
Other | — | — | ||||||
Total | 83,774,885 | $ | 83,774,885 | |||||
(14) | Major Customers and Suppliers |
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Petroleum | ||||||||
Customer A | 17 | % | 12 | % | ||||
Customer B | 14 | % | 6 | % | ||||
Customer C | 10 | % | 9 | % | ||||
Customer D | 9 | % | 10 | % | ||||
50 | % | 37 | % | |||||
Nitrogen Fertilizer | ||||||||
Customer E | 5 | % | 18 | % |
F-73
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
Six Months | Six Months | |||||||
Ended | Ended | |||||||
June 30, | June 30, | |||||||
2006 | 2007 | |||||||
(unaudited) | (unaudited) | |||||||
Supplier A | 66% | 60% |
(15) | Subsequent Events |
F-74
Table of Contents
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(unaudited)
F-75
Page | ||||||||
Prospectus Summary | 1 | |||||||
24 | ||||||||
55 | ||||||||
58 | ||||||||
60 | ||||||||
61 | ||||||||
63 | ||||||||
65 | ||||||||
72 | ||||||||
79 | ||||||||
148 | ||||||||
156 | ||||||||
183 | ||||||||
187 | ||||||||
217 | ||||||||
220 | ||||||||
230 | ||||||||
274 | ||||||||
282 | ||||||||
285 | ||||||||
286 | ||||||||
290 | ||||||||
294 | ||||||||
294 | ||||||||
295 | ||||||||
296 | ||||||||
F-1 | ||||||||
EX-23.1: CONSENT OF KPMG LLP |
Table of Contents
Item 13. | Other Expenses of Issuance and Distribution. |
SEC registration fee | $ | 48,150 | ||
FINRA filing fee | 43,050 | |||
The New York Stock Exchange listing fee | 250,000 | |||
Accounting fees and expenses | 2,600,000 | |||
Legal fees and expenses | 4,750,000 | |||
Printing and engraving expenses | 2,000,000 | |||
Blue Sky qualification fees and expenses | 10,000 | |||
Transfer agent and registrar fees and expenses | 10,000 | |||
Miscellaneous expenses | 288,800 | |||
Total | $ | 10,000,000 | ||
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
Table of Contents
Item 15. | Recent Sales of Unregistered Securities. |
Item 16. | Exhibits and Financial Statement Schedules. |
Number | Exhibit Title | |||
1 | .1** | Form of Underwriting Agreement. | ||
3 | .1** | Form of Amended and Restated Certificate of Incorporation of CVR Energy, Inc. | ||
3 | .2** | Form of Amended and Restated Bylaws of CVR Energy, Inc. | ||
4 | .1** | Specimen Common Stock Certificate. | ||
5 | .1** | Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP. | ||
10 | .1** | Second Amended and Restated Credit and Guaranty Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto. | ||
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. | ||
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, Cayman Islands Branch, as collateral agent. | ||
10 | .3** | Form of Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), as amended. | ||
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. | ||
10 | .5†** | Swap agreements with J. Aron & Company. | ||
10 | .5.1** | 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. | ||
10 | .6†** | Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. and Coffeyville Resources Nitrogen Fertilizers, LLC. |
II-2
Table of Contents
Number | Exhibit Title | |||
10 | .7** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and John J. Lipinski. | ||
10 | .8** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Stanley A. Riemann. | ||
10 | .9** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Kevan A. Vick. | ||
10 | .10** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan. | ||
10 | .11** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and James T. Rens. | ||
10 | .12** | Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi. | ||
10 | .13†** | Crude Oil Supply Agreement, dated as of December 23, 2005, as amended, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC. | ||
10 | .13.1†** | Amendment Agreement dated as of December 1, 2006 between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC. | ||
10 | .14†** | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC. | ||
10 | .15** | Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas. | ||
10 | .16** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Robert W. Haugen. | ||
10 | .17** | Stockholders Agreement of Coffeyville Nitrogen Fertilizer, Inc., dated as of March 9, 2007, by and among Coffeyville Nitrogen Fertilizer, Inc., Coffeyville Acquisition LLC and John J. Lipinski. | ||
10 | .18** | 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. | ||
10 | .19** | Subscription Agreement, dated as of March 9, 2007, between Coffeyville Nitrogen Fertilizer, Inc. and John J. Lipinski. | ||
10 | .20** | Subscription Agreement, dated as of August 22, 2007, between Coffeyville Refining & Marketing Holdings, Inc. and John J. Lipinski. | ||
10 | .21** | Form of Amended and Restated Recapitalization Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc. | ||
10 | .22** | Purchase, Storage and Sale Agreement for Gathered Crude, dated as of March 20, 2007, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC. | ||
10 | .23** | Stock Purchase Agreement, dated as of May 15, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC. | ||
10 | .23.1** | 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. | ||
10 | .23.2** | 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. | ||
10 | .24** | Form of First Amended and Restated Limited Partnership Agreement of CVR Partners, LP, dated as of , 2007, by and among CVR GP, LLC, CVR Special GP, LLC and Coffeyville Resources, LLC. | ||
10 | .25** | Form of Coke Supply Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. |
II-3
Table of Contents
Number | Exhibit Title | |||
10 | .26** | Form of Cross Easement Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .27** | Form of Environmental Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .28** | Form of Feedstock and Shared Services Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .29** | Form of Raw Water and Facilities Sharing Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .30** | Form of Services Agreement, dated as of , 2007, by and among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and CVR Energy, Inc. | ||
10 | .31** | Form of Omnibus Agreement, dated as of , 2007 by and among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR Partners, LP. | ||
10 | .32** | Form of Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II). | ||
10 | .33** | Form of CVR Energy, Inc. 2007 Long Term Incentive Plan. | ||
10 | .33.1** | Form of Nonqualified Stock Option Agreement. | ||
10 | .33.2** | Form of Director Stock Option Agreement. | ||
10 | .33.3** | Form of Director Restricted Stock Agreement. | ||
10 | .34** | Form of Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of , 2007. | ||
10 | .35** | Form of First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of , 2007. | ||
10 | .36** | Form of Limited Liability Company Agreement of Coffeyville Acquisition III LLC, dated as of , 2007. | ||
10 | .37** | Form of Redemption Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC and the Redeemed Parties signatory thereto. | ||
10 | .38** | Form of Stockholders Agreement of CVR Energy, Inc., dated as of , 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. | ||
10 | .39** | Form of Registration Rights Agreement, dated as of , 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. | ||
10 | .40** | Form of Subscription Agreement, dated as of , 2007, by and between CVR Energy, Inc. and John J. Lipinski. | ||
10 | .41** | Form of Letter Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC, Goldman, Sachs & Co. and Kelso & Company, L.P. | ||
10 | .42** | Form of Registration Rights Agreement, dated as of , 2007, by and among the CVR Partners, LP, CVR Special GP, LLC and Coffeyville Resources, LLC. | ||
10 | .43** | Form of CVR Partners, LP Profit Bonus Plan. | ||
10 | .44** | Form of Contribution, Conveyance and Assumption Agreement, dated as of , 2007, by and among Coffeyville Resources, LLC, CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP. | ||
10 | .45** | Form of Management Registration Rights Agreement, dated as of , 2007, by and between CVR Energy, Inc. and John J. Lipinski. | ||
10 | .46** | 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. | ||
10 | .47** | 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. |
II-4
Table of Contents
Number | Exhibit Title | |||
10 | .48** | $25,000,000 Senior Secured First Priority Credit Facility, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto. | ||
10 | .49** | $25,000,000 Senior Unsecured Credit Facility, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto. | ||
10 | .50** | $75,000,000 Senior Unsecured Credit Facility, dated as of August 23, 2007, among Coffeyville Refining & Marketing Holdings, Inc. and the other parties thereto. | ||
10 | .51** | Form of Amendment Number 2 to Employment Agreement, by and between Coffeyville Resources, LLC and John J. Lipinski, Stanley A. Riemann, James T. Rens, Robert W. Haugen and Wyatt E. Jernigan, respectively. | ||
21 | .1** | List of Subsidiaries of CVR Energy, Inc. | ||
23 | .1 | Consent of KPMG LLP. | ||
23 | .2** | Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1). | ||
23 | .3** | Consent of Blue, Johnson & Associates. | ||
23 | .4** | Consent of Blue, Johnson & Associates. | ||
24 | .1** | Power of Attorney. | ||
24 | .2** | Power of Attorney of Mark Tomkins. | ||
24 | .3** | Power of Attorney of Regis B. Lippert. |
** | Previously filed. |
† | Certain portions of this exhibit have been omitted and separately filed with the Securities and Exchange Commission pursuant to a request for confidential treatment. |
Item 17. | Undertakings. |
II-5
Table of Contents
By: | /s/ John J. Lipinski |
Signature | Title | Date | ||||
/s/ John J. Lipinski John J. Lipinski | Chief Executive Officer, President and Director (Principal Executive Officer) | October 16, 2007 | ||||
* James T. Rens | Chief Financial Officer (Principal Financial and Accounting Officer) | October 16, 2007 | ||||
* Wesley Clark | Director | October 16, 2007 | ||||
* Scott L. Lebovitz | Director | October 16, 2007 | ||||
* Regis B. Lippert | Director | October 16, 2007 | ||||
* George E. Matelich | Director | October 16, 2007 | ||||
* Stanley de J. Osborne | Director | October 16, 2007 | ||||
* Kenneth A. Pontarelli | Director | October 16, 2007 | ||||
* Mark Tomkins | Director | October 16, 2007 | ||||
* By: | /s/ John J. Lipinski John J. Lipinski, As Attorney-in-Fact |
II-6
Table of Contents
Number | Exhibit Title | |||
1 | .1** | Form of Underwriting Agreement. | ||
3 | .1** | Form of Amended and Restated Certificate of Incorporation of CVR Energy, Inc. | ||
3 | .2** | Form of Amended and Restated Bylaws of CVR Energy, Inc. | ||
4 | .1** | Specimen Common Stock Certificate. | ||
5 | .1** | Form of opinion of Fried, Frank, Harris, Shriver & Jacobson LLP. | ||
10 | .1** | Second Amended and Restated Credit and Guaranty Agreement, dated as of December 28, 2006, among Coffeyville Resources, LLC and the other parties thereto. | ||
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. | ||
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. | ||
10 | .3** | Form of Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan I), as amended. | ||
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. | ||
10 | .5†** | Swap agreements with J. Aron & Company. | ||
10 | .5.1** | 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. | ||
10 | .6†** | Amended and RestatedOn-Site Product Supply Agreement dated as of June 1, 2005, between The BOC Group, Inc. and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .7** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and John J. Lipinski. | ||
10 | .8** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Stanley A. Riemann. | ||
10 | .9** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Kevan A. Vick. | ||
10 | .10** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Wyatt E. Jernigan. | ||
10 | .11** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and James T. Rens. | ||
10 | .12** | Separation and Consulting Agreement dated as of November 21, 2005, by and between Coffeyville Resources, LLC and Philip L. Rinaldi. | ||
10 | .13†** | Crude Oil Supply Agreement, dated as of December 23, 2005, as amended, between J. Aron & Company and Coffeyville Resources Refining and Marketing, LLC. | ||
10 | .13.1†** | Amendment Agreement dated as of December 1, 2006 between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC. | ||
10 | .14†** | Pipeline Construction, Operation and Transportation Commitment Agreement, dated February 11, 2004, as amended, between Plains Pipeline, L.P. and Coffeyville Resources Refining & Marketing, LLC. | ||
10 | .15** | Electric Services Agreement dated January 13, 2004, between Coffeyville Resources Nitrogen Fertilizers, LLC and the City of Coffeyville, Kansas. | ||
10 | .16** | Employment Agreement amended as of December 13, 2006, by and between Coffeyville Resources, LLC and Robert W. Haugen. |
Table of Contents
Number | Exhibit Title | |||
10 | .17** | 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. | ||
10 | .18** | 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. | ||
10 | .19** | Subscription Agreement, dated as of March 9, 2007, by Coffeyville Nitrogen Fertilizers, Inc. and John J. Lipinski. | ||
10 | .20** | Subscription Agreement, dated as of August 22, 2007, by Coffeyville Refining & Marketing Holdings, Inc. and John J. Lipinski. | ||
10 | .21** | Form of Amended and Restated Recapitalization Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC, Coffeyville Refining & Marketing Holdings, Inc., Coffeyville Refining & Marketing, Inc., Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc. | ||
10 | .22** | Purchase, Storage and Sale Agreement for Gathered Crude, dated as of March 20, 2007, between J. Aron & Company and Coffeyville Resources Refining & Marketing, LLC. | ||
10 | .23** | Stock Purchase Agreement, dated as of May 15, 2005 by and between Coffeyville Group Holdings, LLC and Coffeyville Acquisition LLC. | ||
10 | .23.1** | 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. | ||
10 | .23.2** | 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. | ||
10 | .24** | Form of First Amended and Restated Limited Partnership Agreement of CVR Partners, LP, dated as of , 2007, by and among CVR GP, LLC, CVR Special GP, LLC and Coffeyville Resources, LLC. | ||
10 | .25** | Form of Coke Supply Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .26** | Form of Cross Easement Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .27** | Form of Environmental Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .28** | Form of Feedstock and Shared Services Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .29** | Form of Raw Water and Facilities Sharing Agreement, dated as of , 2007, by and between Coffeyville Resources Refining & Marketing, LLC and Coffeyville Resources Nitrogen Fertilizers, LLC. | ||
10 | .30** | Form of Services Agreement, dated as of , 2007, by and among CVR Partners, LP, CVR GP, LLC, CVR Special GP, LLC, and CVR Energy, Inc. | ||
10 | .31** | Form of Omnibus Agreement, dated as of , 2007 by and among CVR Energy, Inc., CVR GP, LLC, CVR Special GP, LLC and CVR Partners, LP. | ||
10 | .32** | Form of Coffeyville Resources, LLC Phantom Unit Appreciation Plan (Plan II). | ||
10 | .33** | Form of CVR Energy, Inc. 2007 Long Term Incentive Plan. | ||
10 | .33.1** | Form of Nonqualified Stock Option Agreement. | ||
10 | .33.2** | Form of Director Stock Option Agreement. | ||
10 | .33.3** | Form of Director Restricted Stock Agreement. | ||
10 | .34** | Form of Third Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition LLC, dated as of , 2007. |
Table of Contents
Number | Exhibit Title | |||
10 | .35** | Form of First Amended and Restated Limited Liability Company Agreement of Coffeyville Acquisition II LLC, dated as of , 2007. | ||
10 | .36** | Form of Limited Liability Company Agreement of Coffeyville Acquisition III LLC, dated as of , 2007. | ||
10 | .37** | Form of Redemption Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC and the Redeemed Parties signatory thereto. | ||
10 | .38** | Form of Stockholders Agreement of CVR Energy, Inc., dated as of , 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. | ||
10 | .39** | Form of Registration Rights Agreement, dated as of , 2007, by and among CVR Energy, Inc., Coffeyville Acquisition LLC and Coffeyville Acquisition II LLC. | ||
10 | .40** | Form of Subscription Agreement, dated as of , 2007, by and between CVR Energy, Inc. and John J. Lipinski. | ||
10 | .41** | Form of Letter Agreement, dated as of , 2007, by and among Coffeyville Acquisition LLC, Goldman, Sachs & Co. and Kelso & Company, L.P. | ||
10 | .42** | Form of Registration Rights Agreement, dated as of , 2007, by and among CVR Partners, LP, CVR Special GP, LLC and Coffeyville Resources, LLC. | ||
10 | .43** | Form of CVR Partners, LP Profit Bonus Plan. | ||
10 | .44** | Form of Contribution, Conveyance and Assumption Agreement, dated as of , 2007, by and among Coffeyville Resources, LLC, CVR GP, LLC, CVR Special GP, LLC, and CVR Partners, LP. | ||
10 | .45** | Form of Management Registration Rights Agreement, dated as of , 2007, by and between CVR Energy, Inc. and John J. Lipinski. | ||
10 | .46** | 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. | ||
10 | .47** | 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. | ||
10 | .48** | $25,000,000 Senior Secured First Priority Credit Facility, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto. | ||
10 | .49** | $25,000,000 Senior Unsecured Credit Facility, dated as of August 23, 2007, among Coffeyville Resources, LLC and the other parties thereto. | ||
10 | .50** | $75,000,000 Senior Unsecured Credit Facility, dated as of August 23, 2007, among Coffeyville Refining & Marketing Holdings, Inc. and the other parties thereto. | ||
10 | .51** | Form of Amendment Number 2 to Employment Agreement, by and between Coffeyville Resources, LLC and John J. Lipinski, Stanley A. Riemann, James T. Rens, Robert W. Haugen and Wyatt E. Jernigan, respectively. | ||
21 | .1** | List of Subsidiaries of CVR Energy, Inc. | ||
23 | .1 | Consent of KPMG LLP. | ||
23 | .2** | Consent of Fried, Frank, Harris, Shriver & Jacobson LLP (included in Exhibit 5.1). | ||
23 | .3** | Consent of Blue, Johnson & Associates. | ||
23 | .4** | Consent of Blue, Johnson & Associates. | ||
24 | .1** | Power of Attorney. | ||
24 | .2** | Power of Attorney of Mark Tomkins. | ||
24 | .3** | Power of Attorney of Regis B. Lippert. |
** | Previously filed. |
† | Certain portions of this exhibit have been omitted and separately filed with the Securities and Exchange Commission pursuant to a request for confidential treatment. |