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 | $300,000,000 | $32,100 | ||||
(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) | Previously paid. |
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
|
$ | $ |
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.
New and evolving 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
Continuing to take advantage of favorable supply and demand
dynamics in the mid-continent region (where demand for our
products currently outweighs supply);
Selectively investing in significant projects that enhance our
operating efficiency and expanding our capacity while rigorously
controlling costs;
Increasing our sales and supply capabilities of UAN, and other
high value products, while finding lower cost sources of raw
materials;
Continuing to focus on being a reliable, low cost producer of
petroleum and fertilizer products;
Continuing to focus on the reliability, safety and environmental
performance of our operations; and
Selectively evaluating growth opportunities through acquisitions
and/or
strategic alliances.
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 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.
5
Table of Contents
6
Table of Contents
7
Table of Contents
Issuer
CVR Energy, Inc.
Common stock offered by us
shares.
Common stock outstanding immediately after the offering
shares.
Use of proceeds
We estimate that the net proceeds to us in this offering, after
deducting the underwriters discount of
$ million, will be
$ million. We intend to use
the net proceeds from this offering for debt repayment. We will
not receive any proceeds from the purchase by the underwriters
of up to shares from
the selling stockholder in connection with the exercise by the
underwriters of their option. See Use of Proceeds.
Proposed symbol
.
Risk Factors
See Risk Factors beginning on page 18 of this
prospectus for a discussion of factors that you should carefully
consider before deciding to invest in shares of our common stock.
8
Table of Contents
12
13
14
9
Table of Contents
10
Table of Contents
Immediate
Predecessor
Successor
Successor
174
Days Ended
141 Days Ended
Nine Months
June 23,
September 30,
Ended September 30,
(unaudited)
(unaudited)
(in millions,
except as otherwise indicated)
$
980.7
$
776.6
$
2,329.2
768.0
624.9
1,848.1
80.9
36.7
144.5
18.4
7.3
32.8
1.1
11.9
36.8
$
112.3
$
95.8
$
267.0
(8.4
)
0.1
3.1
(7.8
)
(12.2
)
(33.0
)
(7.6
)
(487.1
)
44.7
$
88.5
$
(403.4
)
$
281.8
(36.1
)
150.8
(111.0
)
$
52.4
$
(252.6
)
$
170.8
$
76.7
$
79.1
$
233.5
35.3
16.7
34.1
0.3
(0.6
)
$
112.3
$
95.8
$
267.0
$
0.8
$
7.7
$
23.6
0.3
4.2
12.7
0.5
$
1.1
$
11.9
$
36.8
$
52.4
$
4.9
$
122.4
12.7
63.3
97.9
(12.3
)
(697.2
)
(173.0
)
(52.4
)
713.2
48.5
(12.3
)
(12.1
)
(173.0
)
99,171
105,162
106,975
88,012
93,268
94,061
$
9.28
$
12.39
$
14.68
$
9.60
$
15.01
$
11.60
$
3.44
$
2.44
$
3.79
$
5.79
$
9.12
$
9.97
193.2
118.1
283.9
309.9
185.8
465.0
97.4
%
100.0
%
91.7
%
95.0
%
99.8
%
87.8
%
93.9
%
96.3
%
87.9
%
11
Table of Contents
Original
Predecessor
Immediate Predecessor
Successor
Pro Forma
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,
(unaudited)
(in millions, except as otherwise indicated)
$
1,262.2
$
261.1
$
1,479.9
$
980.7
$
1,454.3
$
2,435.0
1,061.9
221.4
1,244.2
768.0
1,168.1
1,936.2
133.1
23.4
117.0
80.9
85.3
166.3
23.6
4.7
16.3
18.4
18.4
36.7
3.3
0.4
2.4
1.1
24.0
47.6
10.9
$
29.4
$
11.2
$
100.0
$
112.3
$
158.5
$
248.2
(0.5
)
(6.9
)
(8.4
)
0.4
0.1
(1.3
)
(10.1
)
(7.8
)
(25.0
)
(68.4
)
0.3
0.5
(7.6
)
(316.1
)
(323.7
)
$
27.9
$
11.2
$
83.5
$
88.5
$
(182.2
)
$
(143.8
)
(33.8
)
(36.1
)
63.0
47.9
$
27.9
$
11.2
$
49.7
$
52.4
$
(119.2
)
$
(95.9
)
$
21.5
$
7.7
$
77.1
$
76.7
$
123.0
7.8
3.5
22.9
35.3
35.7
0.1
0.3
(0.2
)
$
29.4
$
11.2
$
100.0
$
112.3
$
158.5
$
2.1
$
0.3
$
1.5
$
0.8
$
15.6
1.2
0.1
0.9
0.3
8.4
$
3.3
$
0.4
$
2.4
$
1.1
$
24.0
$
47.6
$
27.9
$
11.2
$
49.7
$
52.4
$
23.6
$
46.9
20.3
53.2
89.8
12.7
82.5
(0.8
)
(130.8
)
(12.3
)
(730.3
)
(19.5
)
(53.2
)
93.6
(52.4
)
712.5
0.8
14.2
12.3
45.2
Table of Contents
Original
Predecessor
Immediate Predecessor
Successor
Year
62 Days
304 Days
174 Days
233 Days
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
(in millions, except as otherwise indicated)
95,701
106,645
102,046
99,171
107,177
85,501
92,596
90,418
88,012
93,908
$
3.89
$
4.23
$
5.92
$
9.28
$
11.55
$
5.53
$
6.80
$
7.55
$
9.60
$
13.47
$
2.57
$
2.60
$
2.66
$
3.44
$
3.13
$
1.25
$
1.57
$
3.20
$
5.79
$
7.55
Production Volume:
335.7
56.4
252.8
193.2
220.0
510.6
93.4
439.2
309.9
353.4
90.1
%
93.5
%
92.2
%
97.4
%
98.7
%
89.6
%
80.9
%
79.7
%
95.0
%
98.3
%
81.6
%
88.7
%
82.2
%
93.9
%
94.8
%
Original
Immediate
Successor
Predecessor
Predecessor
Successor
Actual
As Adjusted
December 31,
December 31,
December 31,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
$
52.7
$
64.7
$
38.1
150.5
106.6
108.0
173.4
199.0
229.2
1,221.5
1,397.7
105.2
148.9
499.4
527.8
3.7
9.0
58.2
14.1
115.8
303.1
(1)
During the 304 days ended
December 31, 2004 and the 174 days ended June 23,
2005, we recognized a loss of $7.2 million and
$8.1 million, respectively, on early extinguishment of debt.
(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:
Immediate
Successor
Predecessor
Successor
Nine Months
174 Days Ended
141 Days Ended
Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
8.1
$
$
16.9
1.4
0.2
4.4
25.0
427.1
(80.3
)
Table of Contents
Original
Immediate
Predecessor
Predecessor
Successor
Pro Forma
Twelve
Year
62 Days
304 Days
174 Days
233 Days
Year
Months
Ended
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
December 31,
September 30,
(non-GAAP)
(unaudited)
(unaudited)
(in millions)
$
9.6
$
$
$
$
$
$
7.2
8.1
3.0
16.6
16.6
(0.3
)
2.3
5.0
1.1
1.8
4.4
25.0
25.0
235.9
235.9
(271.5
)
(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 and 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.
(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 our nitrogen fertilizer plant.
(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:
Immediate
Original Predecessor
Immediate Predecessor
Successor
Predecessor
Successor
Successor
Year
62 Days
304 Days
174 Days
233 Days
174 Days
141 Days
Nine Months
Ended
Ended
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions, except as otherwise indicated)
0.2
0.1
1.1
0.1
0.5
1.6
3.3
0.4
2.0
0.9
22.7
0.9
11.3
34.5
0.2
0.1
0.2
0.1
0.1
0.7
3.3
0.4
2.4
1.1
24.0
1.1
11.9
36.8
(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. Under these agreements, sales representing
approximately 70% and 17% of then forecasted refinery output for
the periods from July 2005 through June 2009, and July 2009
through June 2010, respectively, have been economically hedged.
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. 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
Table of Contents
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:
Immediate
Predecessor
Successor
Successor
174 Days Ended
141 Days Ended
Nine Months
June 23,
September 30,
Ended September 30,
(unaudited)
(unaudited)
(in millions)
$
52.4
$
4.9
$
122.4
(257.5
)
48.4
$
52.4
$
(252.6
)
$
170.8
Pro Forma
Original Predecessor
Immediate Predecessor
Successor
Year
Year
62 Days
304 Days
174 Days
233 Days
Ended
Ended
Ended
Ended
Ended
Ended
December
December 31,
March 2,
December 31,
June 23,
December 31,
31,
(unaudited)
(in millions)
$
27.9
$
11.2
$
49.7
$
52.4
$
23.6
$
46.9
(142.8
)
(142.8
)
$
27.9
$
11.2
$
49.7
$
52.4
$
(119.2
)
$
(95.9
)
(5)
Operational information reflected
for the 141-day Successor period ended September 30, 2005
includes only 99 days of operational activity. 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.
(6)
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 facilitys continuous
operations.
(7)
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
refinerys 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.
15
Table of Contents
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 9 reconciles refining margin to gross profit for the
periods presented.
(8)
This information is industry data
and is not derived from our audited financial statements or
unaudited interim financial statements.
(9)
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.
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
Successor
Successor
Year
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Ended
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
1,161.3
$
241.6
$
1,390.8
$
903.8
$
1,363.4
$
731.6
$
2,205.0
1,040.0
217.4
1,228.1
761.7
1,156.2
617.2
1,828.1
80.1
14.9
73.2
52.6
56.2
22.5
97.3
2.1
0.3
1.5
0.8
15.6
7.7
23.6
$
39.1
$
9.0
$
88.0
$
88.7
$
135.4
$
84.2
$
256.0
80.1
14.9
73.2
52.6
56.2
22.5
97.3
2.1
0.3
1.5
0.8
15.6
7.7
23.6
$
121.3
$
24.2
$
162.7
$
142.1
$
207.2
$
114.4
$
376.9
$
3.89
$
4.23
$
5.92
$
9.28
$
11.55
$
12.39
$
14.68
$
1.25
$
1.57
$
3.20
$
5.79
$
7.55
$
9.12
$
9.97
$
2.57
$
2.60
$
2.66
$
3.44
$
3.13
$
2.44
$
3.79
(10)
On-stream factor is the total
number of hours operated divided by the total number of hours in
the reporting period.
(11)
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.
(12)
Excludes liabilities subject to
compromise due to Original Predecessors bankruptcy of
$105.2 million as of December 31, 2003 in calculating
Original Predecessors working capital.
(13)
While operating under
Chapter 11 of the U.S. Bankruptcy Code, Original
Predecessors financial statements were prepared in
accordance with
SOP 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.
16
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.
17
Table of Contents
18
Table of Contents
19
Table of Contents
20
Table of Contents
21
Table of Contents
22
Table of Contents
23
Table of Contents
24
Table of Contents
25
Table of Contents
26
Table of Contents
27
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.
28
Table of Contents
29
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 committees purpose
and responsibilities; and
the requirement that we have a compensation committee that is
composed entirely of independent directors with a written
charter addressing the committees purpose and
responsibilities.
30
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.
31
Table of Contents
32
Table of Contents
33
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;
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;
fluctuations in the price of natural gas;
the cyclical nature of our 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 property
and/or
injury to the environment and human health and potential
increased costs relating to transport of ammonia;
the dependence of our nitrogen fertilizer operations on a few
third-party suppliers;
our limited operating history as a stand-alone company;
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;
our significant indebtedness;
the dependence on our subsidiaries for cash to meet our debt
obligations;
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;
34
Table of Contents
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; and
our ability to continue to license the technology used in our
operations.
35
Table of Contents
36
Table of Contents
37
Table of Contents
on an actual basis for Coffeyville Acquisition LLC; and
as adjusted to give effect to the sale by us
of shares
in this offering at an assumed initial offering price of
$ per share, the mid-point of
the range set forth on the cover page of this prospectus, the
use of proceeds from this offering and the Transactions.
As of September 30, 2006
(in millions)
$
38.1
$
$
252.8
$
275.0
527.8
9.0
300.7
1.5
0.9
303.1
$
839.9
$
(1)
As of September 30, 2006, we had availability of
$93.6 million under the revolving credit facility.
(2)
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 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 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.
38
Table of Contents
$
$
$
$
$
Shares Purchased
Total Consideration
Average Price
%
$
%
100.0
%
$
100.0
%
39
Table of Contents
40
Table of Contents
Unaudited Pro Forma Condensed Consolidated Statement of
Operations
For the Year Ended December 31, 2005
Historical
Pro Forma
Immediate
Historical
Adjustments to
Predecessor
Successor
Give Effect
174 Days
233 Days
To the
Pro Forma
Ended
Ended
Subsequent
Year Ended
June 23,
December 31,
Acquisition and
December 31,
980,706,261
1,454,259,542
2,434,965,803
768,067,178
1,168,137,217
1,936,204,395
80,913,862
85,313,202
24,481
(a)
166,251,545
18,341,522
18,320,030
(2,645,573
)(a)
36,724,904
2,708,925
(b)
1,128,005
23,954,031
22,376,281
(c)
47,643,362
185,045
(d)
868,450,567
1,295,724,480
22,649,159
2,186,824,206
112,255,694
158,535,062
(22,649,159
)
248,141,597
(7,801,821
)
(25,007,159
)
(35,585,468
) (e)
(68,394,448
)
(7,664,725
)
(316,062,111
)
(323,726,836
)
(8,093,754
)
8,093,754
(f)
(250,929
)
409,074
158,145
88,444,465
(182,125,134
)
(50,140,873
)
(143,821,542
)
36,047,516
(62,968,044
)
(20,978,045
)(g)
(47,898,573
)
52,396,949
(119,157,090
)
(29,162,828
)
(95,922,969
)
$
$
$
(a)
(1) To reverse the share based
compensation expense associated with senior management share
based compensation plans of Immediate Predecessor of $3,985,991
as the compensation plans of Immediate Predecessor were
immediately terminated concurrent with and as a direct result of
the consummation of the Subsequent Acquisition, and (2) to
recognize
41
Table of Contents
share based compensation expense
of $1,364,899 of Successor as if the senior management share
based compensation plans of Successor had gone into effect on
January 1, 2005, based on the valuation as of the purchase
date (June 24, 2005), as adjusted for the additional
vesting period from January 1, 2005 to June 24, 2005,
as the Successor adopted new share based compensation plans
effective with and as a direct result of the consummation of the
Subsequent Acquisition. These adjustments are necessary as they
are directly attributable to the Subsequent Acquisition. If the
Subsequent Acquisition had occurred on January 1, 2005, the
share based compensation plans would have been those of
Successor, and not the Immediate Predecessor.
(b)
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 swaps, which
are required under the terms of the senior secured credit
facility refinanced on December 28, 2006.
(c)
To reflect the increase in
depreciation resulting from the
step-up
of
property, plant, and equipment, depreciated on a straight-line
basis over 3 to 30 years.
$
666.5
37,329.0
156,171.3
4,865.2
1,322.0
83,774.9
3,837.6
750,910.2
$
1,038,876.7
$
47,259.1
16,017.2
5,076.0
276,888.8
7,843.5
$
353,084.6
$
685,792.1
(d)
To increase amortization expense
due to the amortization of identifiable intangibles using a
straight-line method over a weighted average life of eight years.
(e)
To increase the interest expense
for (1) additional interest resulting from entering into
the Credit Facility on December 28, 2006 as if it had
occurred on January 1, 2005 and (2) the amortization of the
deferred financing costs resulting from $9.4 million of
deferred financing charges related to the debt incurred on
December 28, 2006 amortized using an effective interest
amortization method over the term of the debt. 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 as if the December 28, 2006
refinancing occurred on January 1, 2005. Actual interest
expense may be higher or lower depending upon fluctuations in
interest rates. A
1
/
8
%
change in interest rates would result in a $978,505 change
in annual interest expense.
(f)
To reverse the write-off of
$8.1 million of deferred financing costs which were written
off in connection with the refinancing of our senior secured
credit facility on June 24, 2005. This adjustment is
directly attributable to the Subsequent Acquisition, which
triggered the change of control provision included in the
Immediate Predecessors debt agreement. In connection with
the Subsequent Acquisition, we entered into a refinancing
transaction as required by the stock purchase agreement (dated
May 15, 2005) and obligations contained in commitment
letters. The $8.1 million expense represents the
unamortized portion of the deferred financing costs incurred by
the Immediate Predecessor in connection with entering into its
credit facility in 2004 that would have been written off in 2004
and not in 2005 had the Subsequent Acquisition occurred as of
January 1, 2005.
(g)
To reflect the income tax effect of
the pro forma pre-tax loss adjustments of $50,140,873 for the
year ended December 31, 2005, based on an effective tax
rate of 41.8%. The effective tax rate was determined by applying
a combined federal and state statutory income tax rate of
approximately 39.7% to pro forma pre-tax loss adjustments of
$52,841,423. There was no tax effect on pro forma adjustments of
pre-tax income of $2,700,550 relating to non-deductible unearned
compensation expense.
(h)
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 with
respect to the existing shares. 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 two wholly owned subsidiaries of Coffeyville
Acquisition LLC, CVR Energy will effect
a
for
stock split prior to completion of this offering and CVR Energy
will
issue shares
of common stock in this offering. No effect has been given to
any shares that might be issued in this offering pursuant to the
exercise by the underwriters of their option.
42
Table of Contents
Unaudited Pro Forma Condensed Consolidated Statement of
Operations
For the Nine Months Ended September 30, 2006
Historical
Successor
Pro
Forma
Nine Month
Pro Forma
Nine Months
Ended
Adjustments to
Ended
September 30,
Give Effect
September 30,
2006
To
the Refinancing
2006
2,329,152,871
2,329,152,871
1,848,076,557
1,848,076,557
144,461,227
144,461,227
32,796,414
666,667
(a)
33,463,081
36,809,644
36,809,644
2,062,143,842
666,667
2,062,810,509
267,009,029
(666,667
)
266,342,362
(33,016,684
)
(8,819,722
)(b)
(41,836,406
)
44,746,853
44,746,853
3,084,653
3,084,653
281,823,851
(9,486,389
)
272,337,462
111,027,829
(3,766,096
)(c)
107,261,733
170,796,022
(5,720,293
)
165,075,729
$
$
(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 swaps, 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, 2005 and the amortization of the deferred
financing costs resulting from $9.4 million of deferred
financing charges related to the debt incurred on
December 28, 2006 amortized using an effective interest
amortization method over the term of the debt. 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
$765 million of term debt. Actual interest expense may be
higher or lower depending upon fluctuations in interest rates. A
1
/
8
%
change in interest rates would result in a $725,486 change in
interest expense for the nine month period.
(c)
To reflect the income tax effect of the pro forma pre-tax loss
adjustments of $9,486,389 for the nine months ended
September 30, 2006 using a combined federal and state
statutory rate of approximately 39.7%.
(d)
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 with respect to the existing shares. 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 two wholly owned
subsidiaries of Coffeyville Acquisition LLC, CVR Energy will
effect
a for
stock split prior to completion of this offering and CVR Energy
will
issue shares
of common stock in this offering. No effect has been given to
any shares that might be issued in this offering pursuant to the
exercise by the underwriters of their option.
43
Table of Contents
48
49
44
Table of Contents
45
Table of Contents
Immediate
Predecessor
Successor
Successor
174 Days
141 Days
Nine Months
Ended
Ended
Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions, except as otherwise indicated)
$
980.7
$
776.6
$
2,329.2
768.0
624.9
1,848.1
80.9
36.7
144.5
18.4
7.3
32.8
1.1
11.9
36.8
$
112.3
$
95.8
$
267.0
(8.4
)
0.1
3.1
(7.8
)
(12.2
)
(33.0
)
(7.6
)
(487.1
)
44.7
$
88.5
$
(403.4
)
$
281.8
(36.1
)
150.8
(111.0
)
$
52.4
$
(252.6
)
$
170.8
$
0.70
$
$
$
0.70
$
$
$
38.1
173.4
1,397.7
527.8
9.0
303.1
$
1.1
$
11.9
$
36.8
52.4
4.9
122.0
12.7
63.3
97.9
(12.3
)
(697.2
)
(173.0
)
(52.4
)
713.2
48.5
(12.3
)
(12.1
)
(173.0
)
99,171
105,162
106,975
88,012
93,268
94,061
193.2
118.1
283.9
309.9
185.8
465.0
46
Table of Contents
Original Predecessor
Immediate Predecessor
Successor
62 Days
304 Days
174 Days
233 Days
Year Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
(in millions, except as otherwise indicated)
Statement of Operations
Data:
Net sales
$
1,630.2
$
887.5
$
1,262.2
$
261.1
$
1,479.9
$
980.7
$
1,454.3
Cost of product sold (exclusive of
depreciation and amortization)
1,458.0
765.8
1,061.9
221.4
1,244.2
768.0
1,168.1
Direct operating expenses
(exclusive of depreciation and amortization)
146.3
149.4
133.1
23.4
117.0
80.9
85.3
Selling, general and administrative
expenses (exclusive of depreciation and amortization)
24.8
16.3
23.6
4.7
16.3
18.4
18.4
Depreciation and amortization
19.1
30.8
3.3
0.4
2.4
1.1
24.0
Impairment, earnings (losses) in
joint ventures, and other charges(7)
(2.8
)
(375.1
)
(10.9
)
Operating income
(loss)
$
(20.8
)
$
(449.9
)
$
29.4
$
11.2
$
100.0
$
112.3
$
158.5
Other income (expense) and gain
(loss) on sale in joint ventures(1)
19.2
0.1
(0.5
)
(6.9
)
(8.4
)
0.4
Interest (expense)
(18.3
)
(11.7
)
(1.3
)
(10.1
)
(7.8
)
(25.0
)
Gain (loss) on derivatives
0.5
(4.2
)
0.3
0.5
(7.6
)
(316.1
)
Income (loss) before taxes
$
(19.4
)
$
(465.7
)
$
27.9
$
11.2
$
83.5
$
88.5
$
(182.2
)
Income tax (expense) benefit
(33.8
)
(36.1
)
63.0
Net income (loss)(2)
$
(19.4
)
$
(465.7
)
$
27.9
$
11.2
$
49.7
$
52.4
$
(119.2
)
Pro forma earnings per share, basic
and diluted
Pro forma weighted average shares,
basic and diluted
Historical dividends per unit(3):
$
1.50
$
0.70
$
0.48
$
0.70
Balance Sheet Data:
Cash and cash equivalents
$
0.0
$
0.0
$
0.0
$
52.7
$
64.7
Working capital(8)
71.2
122.2
150.5
106.6
108.0
Total assets
300.3
172.3
199.0
229.2
1,221.5
Liabilities subject to compromise(9)
105.2
105.2
Total debt, including current
portion
148.9
499.4
Management units subject to
redemption
3.7
Divisional/members equity
241.4
49.8
58.2
14.1
115.8
Other Financial Data:
Depreciation and amortization
$
19.1
$
30.8
$
3.3
$
0.4
$
2.4
$
1.1
$
24.0
Net income (loss) adjusted for
unrealized gain or loss from Cash Flow Swap(4)
(19.4
)
(465.7
)
27.9
11.2
49.7
52.4
23.6
Cash flows provided by (used in)
operating activities
65.4
(1.7
)
20.3
53.2
89.8
12.7
82.5
Cash flows (used in) investing
activities
17.9
(272.4
)
(0.8
)
(130.8
)
(12.3
)
(730.3
)
47
Table of Contents
Original Predecessor
Immediate Predecessor
Successor
62 Days
304 Days
174 Days
233 Days
Year Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
(in millions, except as otherwise indicated)
(83.3
)
274.1
(19.5
)
(53.2
)
93.6
(52.4
)
712.5
8.2
272.4
0.8
14.2
12.3
45.2
94,758
84,343
95,701
106,645
102,046
99,171
107,177
84,605
74,446
85,501
92,596
90,418
88,012
93,908
198.5
265.1
335.7
56.4
252.8
193.2
220.0
286.2
434.6
510.6
93.4
439.2
309.9
353.4
(1)
Includes a gain on the sale of a
joint venture interest of $18.0 million that was recorded
in 2001 for the disposition of our share in Country Energy, LLC.
During the 304 days ended December 31, 2004 and the
174 days ended June 23, 2005, we recognized a loss of
$7.2 million and $8.1 million, respectively, on early
extinguishment of debt, respectively.
(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:
Immediate Predecessor
Successor
Successor
174 Days Ended
141 Days Ended
Nine Months Ended
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
8.1
$
$
16.9
1.4
0.2
4.4
25.0
427.1
(80.3
)
Table of Contents
Original Predecessor
Immediate Predecessor
Successor
Year
62 Days
304 Days
174 Days
233 Days
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
(in millions)
$
$
375.1
$
9.6
$
$
$
$
18.7
0.3
7.2
8.1
3.0
16.6
2.3
17.0
1.8
25.0
235.9
(18.0
)
(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 payments were
$18.7 million and $0.3 million for the periods ended
December 31, 2001 and 2002, respectively. In February 2002,
Farmland refinanced the operating lease into a secured loan
structure, which effectively terminated the lease and all of
Farmlands 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 and 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.
(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.
(h)
Reflects the gain on the sale of
$18.0 million, which was recorded for the disposition of
Original Predecessors share in Country Energy, LLC.
(3)
Historical dividends per unit for
the
304-day
period ended December 31, 2004 and the
174-day
period ended June 23, 2005 are calculated based on the
ownership structure of Immediate Predecessor.
(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. Under these agreements, sales representing
approximately 70% and 17% of then forecasted refinery output for
the periods from July 2005 through June 2009, and July 2009
through June 2010, respectively, have been economically hedged.
The derivative took the form of three NYMEX swap agreements
whereby if crack spreads fall below the fixed level,
Table of Contents
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. 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.
The following is a reconciliation
of Net income adjusted for unrealized gain or loss from Cash
Flow Swap to Net income:
Immediate
Predecessor
Successor
Successor
174 Days
141 Days
Nine Months
Ended
Ended
Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
52.4
$
4.9
$
122.4
(257.5
)
48.4
$
52.4
$
(252.6
)
$
170.8
Original Predecessor
Immediate Predecessor
Successor
62 Days
304 Days
174 Days
233 Days
Year Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
(in millions)
$
(19.4
)
$
(465.7
)
$
27.9
$
11.2
$
49.7
$
52.4
$
23.6
(142.8
)
$
(19.4
)
$
(465.7
)
$
27.9
$
11.2
$
49.7
$
52.4
$
(119.2
)
50
Table of Contents
(5)
Operational information reflected
for the
141-day
Successor period ended September 30, 2005 includes only 99
days of operational activity. 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.
(6)
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 facilitys continuous
operations.
(7)
Includes the following:
During the year ended
December 31, 2001, we recognized expenses of
$2.8 million for our share of losses of Country Energy, LLC.
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 nitrogen 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.
(8)
Excludes liabilities subject to
compromise due to Original Predecessors bankruptcy of
$105.2 million as of December 31, 2002 and 2003 in
calculating Original Predecessors working capital.
(9)
While operating under
Chapter 11 of the U.S. Bankruptcy Code, Original
Predecessors financial statements were prepared in
accordance with
SOP 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.
51
Table of Contents
66
71
149
151
F-6
F-38
F-55
F-56
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
52
Table of Contents
53
Table of Contents
54
Table of Contents
55
Table of Contents
56
Table of Contents
57
Table of Contents
58
Table of Contents
59
Table of Contents
60
Table of Contents
61
Table of Contents
Original
Predecessor
Immediate
Predecessor
Successor
Successor
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Year Ended
Ended
Ended
Ended
Ended
Ended
Ended
December
31,
March
2,
December 31,
June
23,
December
31,
September
30,
September
30,
Consolidated
Financial Results
2003
2004
2004
2005
2005
2005
2006
(in
millions)
$
1,262.2
$
261.1
$
1,479.9
$
980.7
$
1,454.3
$
776.6
$
2,329.2
1,061.9
221.4
1,244.2
768.0
1,168.1
624.9
1,848.1
3.3
0.4
2.4
1.1
24.0
11.9
36.8
133.1
23.4
117.0
80.9
85.3
36.6
144.5
23.6
4.7
16.3
18.4
18.4
7.4
32.8
(10.9
)
$
29.4
$
11.2
$
100.0
$
112.3
$
158.5
$
95.8
$
267.0
27.9
11.2
49.7
52.4
(119.2
)
(252.6
)
170.8
27.9
11.2
49.7
52.4
23.6
4.9
122.4
(1)
Depreciation and amortization is
comprised of the following components as excluded from cost of
products sold, direct operating expense and selling, general and
administrative expense:
Immediate
Original Predecessor
Immediate Predecessor
Successor
Predecessor
Successor
Successor
Year
62 Days
304 Days
174 Days
233 Days
174 Days
141 Days
Nine Months
Ended
Ended
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions, except as otherwise indicated)
0.2
0.1
1.1
0.1
0.5
1.6
3.3
0.4
2.0
0.9
22.7
0.9
11.3
34.5
0.2
0.1
0.2
0.1
0.1
0.7
3.3
0.4
2.4
1.1
24.0
1.1
11.9
36.8
(2)
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.
62
Table of Contents
(3)
The following are certain charges
and costs incurred in each of the relevant periods that are
meaningful to understanding our net income and in evaluating our
performance due to their unusual or infrequent nature:
Original
Predecessor
Immediate
Predecessor
Successor
Successor
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Year Ended
Ended
Ended
Ended
Ended
Ended
Ended
December
31,
March
2,
December 31,
June
23,
December
31,
September
30,
September
30,
2003
2004
2004
2005
2005
2005
2006
(in
millions)
$
9.6
$
$
$
$
$
$
7.2
8.1
3.0
16.6
16.9
2.3
1.4
0.2
1.8
4.4
25.0
25.0
235.9
427.1
(80.3
)
(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 and 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.
(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 our nitrogen fertilizer plant.
(f)
Represents the expense associated
with the expiration of the crude oil, heating oil and gasoline
option agreements entered into by Coffeyville Acquisition LLC in
May 2005.
(4)
Net income 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. Under these agreements, sales representing
approximately 70% and 17% of then forecasted refinery output for
the periods from July 2005 through June 2009, and July 2009
through June 2010, respectively, have been economically hedged.
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. 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.
63
Table of Contents
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
Successor
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Year Ended
Ended
Ended
Ended
Ended
Ended
Ended
December
31,
March
2,
December 31,
June
23,
December
31,
September
30,
September
30,
2003
2004
2004
2005
2005
2005
2006
(in
millions)
$
27.9
$
11.2
$
49.7
$
52.4
$
23.6
$
4.9
$
122.4
(142.8
)
(257.5
)
48.4
$
27.9
$
11.2
$
49.7
$
52.4
$
(119.2
)
$
(252.6
)
$
170.8
Original Predecessor
Immediate Predecessor
Successor
Successor
Successor
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Year Ended
Ended
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
September 30,
September 30,
(unaudited)
(unaudited)
(in millions)
$
1,161.3
$
241.6
$
1,390.8
$
903.8
$
1,363.4
$
731.6
$
2,205.0
1,040.0
217.4
1,228.1
761.7
1,156.2
617.2
1,828.1
80.1
14.9
73.2
52.6
56.2
22.5
97.3
2.1
0.3
1.5
0.8
15.6
7.7
23.6
$
39.1
$
9.0
$
88.0
$
88.7
$
135.4
$
84.2
$
256.0
80.1
14.9
73.2
52.6
56.2
22.5
97.3
2.1
0.3
1.5
0.8
15.6
7.7
23.6
$
121.3
$
24.2
$
162.7
$
142.1
$
207.2
$
114.4
$
376.9
$
3.89
$
4.23
$
5.92
$
9.28
$
11.55
$
12.39
$
14.68
$
1.25
$
1.57
$
3.20
$
5.79
$
7.55
$
9.12
$
9.97
$
2.57
$
2.60
$
2.66
$
3.44
$
3.13
$
2.44
$
3.79
21.5
7.7
77.1
76.7
123.0
79.1
233.5
64
Table of Contents
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor
Predecessor
Original
Predecessor
and Successor
and Successor
Predecessor
Combined
Combined
Combined
Successor
Year Ended December 31,
Nine Months Ended September 30,
(dollars per barrel)
$
30.99
$
41.47
$
56.70
$
55.61
$
68.24
5.53
7.43
11.62
11.57
11.60
2.67
3.96
4.73
4.44
5.41
6.78
11.40
15.67
15.34
15.53
2.16
3.20
2.18
1.87
1.31
0.62
(0.52
)
(0.53
)
(0.27
)
1.88
1.11
1.24
3.20
1.87
7.90
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor
Predecessor
Original
Predecessor
and Successor
and Successor
Predecessor
Combined
Combined
Combined
Successor
Year Ended December 31,
Nine Months Ended September 30,
(in millions)
$
3.89
$
5.62
$
10.50
$
10.45
$
14.68
$
1.25
$
2.92
$
6.74
$
7.04
$
9.97
2.57
2.65
3.27
3.06
3.79
0.91
1.19
1.61
1.62
1.99
0.84
1.15
1.71
1.62
2.04
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor and
Predecessor and
Original
Predecessor
Successor
Successor
Predecessor
Combined
Combined
Combined
Successor
Year Ended December 31,
Nine Months Ended September 30,
2003
2004
2005
2005
2006
Selected Company
Barrels
Barrels
Barrels
Barrels
Barrels
48,230
50.4
48,420
47.1
45,275
43.8
44,241
43.7
46,137
43.1
34,363
35.9
38,104
37.1
39,997
38.7
39,106
38.6
41,401
38.7
13,108
13.7
16,301
15.9
18,090
17.5
17,997
17.7
19,437
18.2
95,701
100.0
102,825
100.0
103,362
100.0
101,344
100.0
106,975
100.0
85,501
93.4
90,787
92.8
91,097
92.6
89,918
93.4
94,061
92.6
6,085
6.6
7,023
7.2
7,246
7.4
6,375
6.6
7,463
7.4
91,586
100.0
97,810
100.0
98,343
100.0
96,293
100.0
101,524
100.0
65
Table of Contents
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor and
Predecessor and
Original
Predecessor
Successor
Successor
Predecessor
Combined
Combined
Combined
Successor
Year Ended December 31,
Nine Months Ended September 30,
2003
2004
2005
2005
2006
Total
Total
Total
Total
Total
18,187,215
58.3
15,232,022
45.8
13,958,567
42.0
11,169,134
45.5
12,916,402
50.3
12,311,203
39.4
17,995,949
54.2
19,291,951
58.0
13,378,413
54.5
12,685,293
49.4
709,300
2.3
77,036
0.3
31,207,718
100.0
33,227,971
100.0
33,250,518
100.0
24,547,547
100.0
25,678,731
100.0
Table of Contents
67
Table of Contents
68
Table of Contents
69
Table of Contents
Original
Predecessor
Immediate
Predecessor
Successor
Successor
62 Days
304 Days
174 Days
233 Days
141 Days
Nine Months
Year Ended
Ended
Ended
Ended
Ended
Ended
Ended
Nitrogen
Fertilizer
December
31,
March
2,
December 31,
June
23,
December
31,
September 30,
September
30,
Business
Financial Results
2003
2004
2004
2005
2005
2005
2006
(in
millions)
$
100.9
$
19.4
$
93.4
$
79.3
$
93.7
$
46.6
$
128.2
21.9
4.1
20.4
9.1
14.5
9.2
23.8
1.2
0.1
0.9
0.3
8.4
4.2
12.7
53.0
8.4
43.8
28.3
29.2
14.1
47.2
7.8
3.5
22.9
35.3
35.7
16.7
34.1
70
Table of Contents
Year Ended
Nine Months
December 31,
Ended September 30,
$
5.49
$
6.18
$
9.01
$
7.75
$
6.89
274
297
356
328
360
143
171
212
205
198
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor
Predecessor
Original
Predecessor
and Successor
and Successor
Predecessor
Combined
Combined
Combined
Successor
Year Ended December 31,
Nine Months Ended September 30,
335.7
309.2
413.2
311.3
283.9
510.6
532.6
663.3
495.7
465.0
846.3
841.8
1,076.5
807.0
748.9
134.8
103.9
141.8
102.4
96.8
528.9
541.6
646.5
487.4
477.7
663.7
645.5
788.3
589.8
574.5
$
235
$
266
$
324
$
305
$
346
107
136
173
172
169
90.1
%
92.4
%
98.1
%
98.3
%
91.7
%
89.6
%
79.9
%
96.7
%
96.7
%
87.8
%
81.6
%
83.3
%
94.3
%
94.8
%
87.9
%
83.6
%
76.8
%
102.9
%
103.7
%
94.5
%
93.3
%
97.0
%
121.2
%
121.0
%
113.6
%
$
12,535
$
11,429
$
15,010
$
11,140
$
13,860
88,373
101,439
157,989
114,798
114,295
100,908
112,868
172,999
125,938
128,155
(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.
(3)
Based on nameplate capacity of 1,100 tons per day.
(4)
Based on nameplate capacity of 1,500 tons per day.
Table of Contents
72
Table of Contents
73
Table of Contents
74
Table of Contents
75
Table of Contents
76
Table of Contents
77
Table of Contents
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
85
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;
$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 2.00%, or, at the borrowers
option, (b) LIBOR plus 3.00% (with step-downs to the prime
rate/federal funds rate plus 1.50% or LIBOR plus 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 borrowers 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 borrowers 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 2.00%, or, at the borrowers
option, (b) LIBOR plus 3.00% (with step-downs to the prime
rate/federal funds rate plus 1.50% or LIBOR plus 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 borrowers 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
86
Table of Contents
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 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 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
2.25:1.00
4.75:1.00
2.50:1.00
4.50:1.00
2.75:1.00
4.25:1.00
2.75:1.00
4.00:1.00
3.25:1.00
3.25:1.00
3.25:1.00
3.00:1.00
3.25:1.00
2.75:1.00
3.25:1.00
2.50:1.00
3.75:1.00
2.25:1.00
to December 31, 2009,
2.00:1.00 thereafter
87
Table of Contents
Original
Predecessor
Immediate
Immediate
and Immediate
Predecessor
Predecessor
Predecessor
and Successor
and Successor
Original
Combined
Combined
Combined
Successor
Predecessor
(non-GAAP)
(non-GAAP)
(non-GAAP)
Successor
(non-GAAP)
Twelve Months
Nine Months
Ended
Ended
Year Ended
December 31,
September 30,
September 30,
2003
2004
2005
2005
2006
2006
(unaudited)
(unaudited)
(unaudited)
(unaudited)
(in millions)
$
27.9
$
60.9
$
(66.8
)
$
(200.2
)
$
170.8
$
304.2
3.3
2.8
25.1
13.0
36.8
48.9
1.3
10.1
32.8
20.0
33.0
45.8
33.8
(26.9
)
(114.7
)
111.0
198.8
9.6
7.2
8.1
8.1
3.0
16.6
16.9
(0.3
)
2.3
1.4
0.2
1.1
1.8
4.4
4.4
25.0
25.0
229.8
421.7
(81.6
)
(273.5
)
1.1
1.8
1.3
2.3
2.8
1.2
1.2
3.5
3.5
0.5
2.3
1.7
1.6
2.2
$
42.1
$
121.2
$
253.6
$
197.7
$
279.7
$
335.6
88
Table of Contents
89
Table of Contents
Cumulative
Through
(in millions)
$
95.2
$
57.3
$
9.1
$
12.7
$
42.7
$
217.0
23.7
26.9
16.6
16.1
20.0
103.3
$
118.9
$
84.2
$
25.7
$
28.8
$
62.7
$
320.3
6.6
38.0
5.5
3.0
32.9
86.0
$
125.5
$
122.2
$
31.2
$
31.8
$
95.6
$
406.3
90
Table of Contents
91
Table of Contents
92
Table of Contents
93
Table of Contents
94
Table of Contents
95
Table of Contents
Payments Due by Period
Three Months
Ending
December 31,
(in millions)
$
527.8
$
0.6
$
2.4
$
2.5
$
2.5
$
2.4
$
517.4
13.7
0.9
3.8
3.6
2.9
1.6
0.9
252.2
6.6
24.8
20.6
20.5
18.1
161.6
10.2
0.3
1.7
0.9
0.5
0.4
6.4
14.1
0.9
3.8
3.8
3.8
1.8
331.1
13.4
53.2
53.1
52.8
52.6
106.0
$
1,149.1
$
22.7
$
89.7
$
84.5
$
83.0
$
76.9
$
792.3
$
6.4
$
$
6.4
$
$
$
$
(1)
Long-term debt amortization is based on the contractual terms of
our existing credit facilities. See Description of Our
Indebtedness and the Cash Flow Swap.
96
Table of Contents
(2)
We lease various facilities and equipment, primarily railcars
for our nitrogen fertilizer business 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 federal
and/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 then-existing first
lien credit facility. The funded letter of credit is utilized as
credit support for the Cash Flow Swap. See
Quantitative and Qualitative Disclosures About
Market Risk Commodity Price Risk.
(6)
Interest payments are based on interest rates in effect at
September 30, 2006 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 $3.2 million to secure
transportation expenses related to the Transportation Services
Agreement with CCPS Transportation, LLC.
97
Table of Contents
98
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 entering
over-the-counter
swap agreements, the settlement price of the swap is typically
the average price of the underlying commodity for a designated
calendar period. This settlement price is based on the
assumption that the 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.
99
Table of Contents
Successors 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. 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
September 30, 2006 the net notional open amounts under
these swap agreements were 71,206,000 barrels of crude oil,
1,495,326,000 gallons of heating oil and 1,495,326,000 gallons
of unleaded gasoline. The purpose of these contracts is to
economically hedge 35,603,000 barrels of heating oil
crack spreads, the price spread between crude oil and heating
oil and 35,603,000 barrels of unleaded gas crack spreads,
the price spread between crude oil and unleaded gasoline. These
open contracts had total unrealized net loss at
September 30, 2006 of approximately $155.6 million.
Successors Petroleum Segment holds two other commodity
derivative contracts for the period from February 1, 2007
to February 28, 2007 with J. Aron. The combined notional
quantity of the contracts is 100,000 barrels of unleaded
gasoline crack spreads. The swap agreements were executed to
effectively reduce the unleaded gasoline crack position of the
swap agreements discussed in the previous bullet point. These
open contracts had an unrealized gain of $0.1 million at
September 30, 2006.
Successors Petroleum Segment also holds various NYMEX
positions through ABN Amro LLC. At September 30, 2006,
we were short 390 crude contracts, 73 heating oil contracts and
100 unleaded contracts, reflecting an unrealized loss of
$0.2 million on that date.
100
Table of Contents
Effective
Termination
Fixed
Date
Date
Rate
6/30/06
3/30/07
4.038%
3/31/07
6/30/07
4.038%
6/29/07
3/31/08
4.195%
3/31/08
3/31/09
4.195%
3/31/09
3/31/10
4.195%
3/31/10
6/30/10
4.195%
101
Table of Contents
102
Table of Contents
103
Table of Contents
104
Table of Contents
105
Table of Contents
106
Table of Contents
Ammonia
UAN 32
(thousand tons per year)
2,300
850
80
225
370
670
325
250
690
865
335
1,100
335
195
107
Table of Contents
108
Table of Contents
109
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 to be completed during a plant-wide turnaround scheduled
to begin in the first quarter of 2007; and
Construction of a new grass roots 24,000 bpd continuous
catalytic reformer to be completed in the third quarter of 2007.
110
Table of Contents
111
Table of Contents
Continuing to take advantage of favorable supply and demand
dynamics in the mid-continent region (where demand from our
products currently outweighs supply);
112
Table of Contents
Selectively investing in significant projects that enhance our
operating efficiency and expanding our capacity while rigorously
controlling costs;
Increasing our sales and supply capabilities of UAN, and other
high value products, while finding lower cost sources of raw
materials;
Continuing to focus on being a reliable, low cost producer of
petroleum and fertilizer products;
Continuing to focus on the reliability, safety and environmental
performance of our operations; and
Selectively evaluating attractive growth opportunities through
acquisitions
and/or
strategic alliances.
113
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.
114
Table of Contents
Year Ended December 31,
Nine Months Ended September 30,
(in barrels)
30,880,860
27,172,830
31,207,718
33,227,971
33,250,518
24,547,547
25,678,731
694,552
1,093,629
483,362
317,874
455,587
344,382
273,559
530,575
467,176
158,116
194,132
1,142,098
1,037,855
1,627,989
1,615,898
1,398,694
1,035,321
1,089,415
68,636
68,636
112,358
155,344
34,574
337,764
32,951
98,371
109,974
105,981
99,362
99,362
30,208
32,750,461
29,402,685
33,429,043
35,798,299
35,895,317
26,287,938
27,716,167
Nominal
350,000
125,000
145,000
25,000
15,000
97,000
120,000
115
Table of Contents
Gasoline.
Gasoline typically accounts
for approximately 47% of our refinerys 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 41% of the refinerys production.
The majority of the diesel fuel we produce is low-sulfur.
Nine Months
Year Ended
Ended
December 31,
September 30,
(in barrels)
15,118,607
14,071,304
16,531,362
16,703,566
16,154,172
11,740,790
11,926,825
423,898
306,334
298,789
220,908
261,467
227,242
374,211
803,590
754,264
773,831
797,416
109,774
109,774
294,356
16,346,095
15,131,902
17,603,982
17,721,890
16,525,413
12,077,806
12,595,393
25,675
26,085
25,149
23,256
32,302
13,086
(5,774
)
97,354
278,325
124,741
342,363
99,832
261,048
40,447
13,628
6,708,536
6,526,883
7,899,132
8,896,701
9,129,518
6,533,104
8,496,463
3,138,236
2,268,116
3,017,785
3,500,351
3,916,658
2,955,997
2,743,127
2,105,709
1,923,370
1,258,279
1,425,897
1,259,308
1,133,210
55,043
12,353,835
10,869,195
12,542,708
13,946,037
14,598,834
10,675,844
11,302,488
676,753
583,095
734,737
1,137,645
696,637
519,939
509,479
507,407
445,784
532,236
500,692
562,657
385,503
524,078
214,504
84,146
42,571
188,684
8,212
26,438
150,700
134,899
40,927
66,126
207,154
79,906
230,785
170,171
231,250
84,673
66,274
66,274
1,794,502
1,205,910
1,335,982
1,868,943
1,691,252
1,182,814
1,330,933
2,751,298
2,068,031
1,956,619
2,384,414
2,439,297
1,854,020
1,848,931
92,918
74,226
131,137
88,744
100,035
77,877
65,292
2,844,216
2,142,257
2,087,756
2,473,158
2,539,332
1,931,897
1,914,223
226,159
52,682
(8,539
)
548,883
548,883
473,639
(347,599
)
114,945
(120,122
)
(12,369
)
265,280
38,652
311,226
1,369,413
1,268,388
1,489,030
1,636,665
1,557,689
1,210,977
1,276,288
(1,836,160
)
(1,382,594
)
(1,501,754
)
(1,836,025
)
(1,831,366
)
(1,378,935
)
(1,488,023
)
32,750,461
29,402,685
33,429,043
35,798,299
35,895,317
26,287,938
27,716,167
116
Table of Contents
767,000
1,068,000
1,004,000
1,194,000
(1)
Crude oil storage consists of 674,000 barrels of refinery
storage capacity and 520,000 barrels of field storage
capacity.
32,000
81,000
12,000
40,000
117
Table of Contents
118
Table of Contents
Year Ended
December 31,
Nine Months Ended September 30,
78.6%
90.1%
92.4%
98.1%
98.3%
91.7%
66.0%
83.6%
76.8%
102.9%
103.7%
94.5%
79.4%
93.3%
97.0%
121.2%
121.0%
113.6%
(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.
119
Table of Contents
120
Table of Contents
121
Table of Contents
122
Table of Contents
Crude Capacity
Solomon
(barrels per
Complexity
Ponca City, OK
187,000
12.5
El Dorado, KS
110,000
13.3
Coffeyville, KS
108,000
10.0
Ardmore, OK
88,000
11.3
McPherson, KS
82,200
14.1
Wynnewood, OK
52,500
8.0
Tulsa, OK
50,000
8.3
677,700
123
Table of Contents
restrictions on operations
and/or
the
need to install enhanced or additional controls;
the need to obtain and comply with permits and authorizations;
liability for the investigation and remediation of contaminated
soil and groundwater at current and former facilities and
off-site waste disposal locations; and
specifications for the products we market, primarily gasoline,
diesel fuel, UAN and ammonia.
124
Table of Contents
125
Table of Contents
126
Table of Contents
127
Table of Contents
128
Table of Contents
Total
Site
Total O&M
Estimated
Investigation
Capital
Costs
Costs
$
0.5
$
$
1.0
$
1.5
0.3
1.9
2.2
$
0.8
$
$
2.9
$
3.7
129
Table of Contents
130
Table of Contents
440
Own
Oil refinery, nitrogen plant and
office buildings
200
Own
Terminal facility
(Coffeyville Station)
20
Own
Crude oil storage
(Broome Station)
20
Own
Crude oil storage
25
Own
Truck storage and
office buildings
5
Own
Truck storage
65
Own
Crude oil storage
additional 120 acres pending
(Hooser Station)
80
Own
Crude oil storage
7
Own
Crude oil storage
6
Own
Crude oil storage
19,000 (square feet)
Lease
Office space
131
Table of Contents
55
Chief Executive Officer, President
and Director
55
Chief Operating Officer
40
Chief Financial Officer
55
Vice President, General Counsel
and Secretary
48
Executive Vice President Refining
Operations
54
Executive Vice President Crude Oil
Acquisition and Petroleum Marketing
52
Executive Vice President, General
Manager Nitrogen Fertilizer
48
Vice President, Environmental,
Health and Safety
60
Director
31
Director
50
Director
36
Director
36
Director
51
Director
132
Table of Contents
133
Table of Contents
134
Table of Contents
135
Table of Contents
To align the executive officers interest with that of the
shareholders and stakeholders, which provides long-term economic
benefits to the shareholders;
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.
136
Table of Contents
137
Table of Contents
138
Table of Contents
Continued operational improvement of an asset that had been in
bankruptcy less than 3 years ago
Start-up
operations of refined fuels offsite rack marketing
Expansion of the crude gathering system
139
Table of Contents
Continual innovative and technical improvements to improve
operational efficiency and cost
Implementation and initiation of the refinery expansion project
140
Table of Contents
Non-Equity
Incentive Plan
All Other
Name and
Principal
Salary
Bonus ($)
Stock
Compensation
($)
Compensation
Total ($)
2006
650,000
1,331,790
(3
)
487,500
1,010,523(5
)
3,479,813
2006
350,000
772,917
(2)
210,000
292,490(6
)
1,625,407
2006
250,000
205,000
130,000
154,255(7
)
739,255
2006
225,000
205,000
117,000
154,410(8
)
701,410
2006
225,000
140,000
117,000
155,681(9
)
637,681
(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)
The dollar 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 cannot be determined at this time. We
expect to complete a valuation in connection with the
preparation of our 2006 audited financial statements, and this
amount will be included in the next amendment to this
Form S-1/A.
The amount will reflect the dollar amount recognized for
financial statement reporting purposes for the fiscal year ended
December 31, 2006 in accordance with FAS 123(R), and
assumptions used in the calculation of this amount will
141
Table of Contents
be included in a footnote to the Companys audited
financial statements for the year ended December 31, 2006.
(4)
Reflects cash awards to the named individuals in respect of 2006
performance pursuant to our Variable Compensation Plan.
(5)
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 and
(e) the value of profit interests in Coffeyville
Acquisition LLC granted in 2005 in the amount of $630,059, which
amount is discussed in more detail in footnote 6, below. In
addition, Mr. Lipinski will receive (f) a cash payment
in respect of taxes payable on his December 28, 2006 grant
of subsidiary stock, although the amount of this payment cannot
be determined until the valuation in connection with the
preparation of our 2006 audited financial statements is
completed. The amount of the cash payment will be included in
the next amendment to this
Form S-1/A.
Mr. Lipinski also received (g) profit interests in
Coffeyville Acquisition LLC that were granted in the period
ending December 31, 2006 (the value of the profit interests
will be determined by a third-party valuation using binomial
modeling based on company projections of undiscounted future
cash flows), more fully described below under
Executives Interests in Coffeyville
Acquisition LLC
, and (h) Phantom Points granted
during the period ending December 31, 2006 (the value of
the Phantom Points will be determined by a third-party valuation
using binomial modeling based on company projections of
undiscounted future cash flows), more fully described below
under
Coffeyville Resources, LLC Phantom
Unit Appreciation Plan
. The value of the profit
interests granted in 2006 and the Phantom Points cannot be
determined at this time. We expect to complete a valuation in
connection with the preparation of our 2006 audited financial
statements, and these amounts will be included in the next
amendment to this
Form S-1/A.
The amounts will reflect the dollar amount recognized for
financial statement reporting purposes for the fiscal year ended
December 31, 2006 in accordance with FAS 123(R), and
assumptions used in the calculations will be included in our
audited financial statements for the year ended
December 31, 2006.
(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 and (c) the value of profit interests in
Coffeyville Acquisition LLC granted in 2005 in the amount of
$279,670, as more fully described below under
Executives Interests in Coffeyville
Acquisition LLC
. This amount represents the dollar
amount recognized for financial statement reporting purposes for
the fiscal year ended December 31, 2006 in accordance with
FAS 123(R). Assumptions used in the calculations will be
included in our audited financial statements for the year ended
December 31, 2006. This column will also include Phantom
Points granted to Mr. Riemann during the period ending
December 31, 2006, as more fully described below under
Coffeyville Resources, LLC Phantom Unit
Appreciation Plan
. The value of the Phantom Points
cannot be determined at this time. We expect to complete a
valuation in connection with the preparation of our 2006 audited
financial statements, and these amounts will be included in the
next amendment to this
Form S-1/A
for each of our named executive officers. The value of the
Phantom Points will reflect the dollar amount recognized for
financial statement reporting purposes for the fiscal year ended
December 31, 2006 in accordance with FAS 123(R), and
assumptions used in the calculations will be included in our
audited financial statements for the year ended
December 31, 2006.
(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 and (c) the value of profit interests in
Coffeyville Acquisition LLC granted in 2005 in the amount of
$143,571, which amount is discussed in more detail in footnote
6, above. This column will also
142
Table of Contents
include Phantom Points granted to Mr. Rens during the
period ending December 31, 2006, which amount is discussed
in more detail in footnote 6, above.
(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 and (c) the value of profit interests in
Coffeyville Acquisition LLC granted in 2005 in the amount of
$143,571, which amount is discussed in more detail in footnote
6, above. This column will also include Phantom Points granted
to Mr. Haugen during the period ending December 31,
2006, which amount is discussed in more detail in footnote 6,
above.
(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 and (c) the value of profit interests in
Coffeyville Acquisition LLC granted in 2005 in the amount of
$143,571, which amount is discussed in more detail in footnote
6, above. This column will also include Phantom Points granted
to Mr. Jernigan during the period ending December 31,
2006, which amount is discussed in more detail in footnote 6,
above.
(10)
An updated total compensation amount will be included in the
next amendment to this
Form S-1/A.
Estimated
Future
All other
Stock
Payouts Under
Awards:
Non-Equity
Number of
Grant Date
Fair
Incentive Plan
Shares of Stock
or
Value of Stock
and
Target
($)
December 2006
1,625,000
December 28, 2006
(1)
(1)
December 2006
700,000
December 2006
300,000
December 2006
330,000
December 2006
225,000
(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 and the grant date fair value cannot be
determined at this time. We expect to complete a valuation in
connection with the preparation of our 2006 audited financial
statements, and these amounts will be included in the next
amendment to this
Form S-1/A.
143
Table of Contents
144
Table of Contents
145
Table of Contents
146
Table of Contents
Stock
Awards
Number of
Shares
Value Realized
Acquired
on Vesting
(1)
(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,
which are fully vested as of the date of grant. The number of
shares and the dollar value realized on these fully vested
shares on the date of grant cannot be determined at this time.
We expect to complete a valuation in connection with the
preparation of our 2006 audited financial statements, and this
information will be included in the next amendment to this
Form S-1/A.
147
Table of Contents
148
Table of Contents
Estimated Dollar
Value of
$
1,950,000
$
20,307
$
650,000
$
525,000
$
10,154
$
250,000
$
9,713
$
225,000
$
9,713
$
225,000
$
3,154
Fees Earned or
Paid
All Other
$
40,000
(1
)
$
40,000
$
0
$
0
$
0
(1)
Mr. Clark was awarded 244,038 Phantom Service Points and
244,038 Phantom Performance Points under Coffeyville Resources,
LLCs Phantom Unit Plan in September 2005. Collectively,
Mr. Clarks 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. The Phantom Points are more
fully described above under
Coffeyville
Resources, LLC Phantom Unit Appreciation Plan
. The
value of the Phantom Points cannot be determined at this time.
We expect to complete a valuation in connection with the
preparation of our 2006 audited financial statements, and this
amount will be included in the next amendment to this
Form S-1/A.
The amount will reflect the dollar amount recognized for
financial statement reporting purposes for the fiscal year ended
December 31, 2006 in accordance with FAS 123(R), and
assumptions used in the calculation will be included in our
audited financial statements for the year ended
December 31, 2006.
(2)
An updated total compensation column will be included in the
next amendment to this
Form S-1/A.
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;
each selling stockholder who beneficially owns less than five
percent of our common stock; and
all of our executive officers and directors as a group.
150
Table of Contents
(1)
The underwriters have an option to purchase up to an
additional shares
from the selling stockholder in this offering. If the
underwriters exercise this option, shares would be sold to the
underwriters by Coffeyville Acquisition LLC and Coffeyville
Acquisition LLC would distribute the proceeds to its members.
(2)
The Goldman Sachs Group, Inc., and certain affiliates, including
Goldman, Sachs & Co., may be deemed to directly or
indirectly own in the
aggregate shares
of common stock which are owned directly or indirectly by
investment partnerships, which we refer to as the Goldman Sachs
Funds, of which affiliates of The Goldman Sachs Group, Inc. and
Goldman, Sachs & Co. are the general partner, managing
limited partner or the managing partner. Goldman,
Sachs & Co. is the investment manager for certain of
the Goldman Sachs Funds. Goldman, Sachs & Co. is a
direct and indirect, wholly owned subsidiary of The Goldman
Sachs Group, Inc. The Goldman Sachs Group, Inc., Goldman,
Sachs & Co. and the Goldman Sachs Funds share voting
power and investment power with certain of their respective
affiliates. Shares beneficially owned by the Goldman Sachs Funds
consist of:
(1) shares
of common stock owned by GS Capital
Table of Contents
Partners V Fund, L.P.,
(2) shares
of common stock owned by GS Capital Partners V Offshore Fund,
L.P.,
(3) shares
of common stock owned by GS Capital Partners V Institutional,
L.P., and
(4) shares
of common stock owned by GS Capital Partners V GmbH &
Co. KG. Ken Pontarelli is a managing director of Goldman,
Sachs & Co. Mr. Pontarelli, The Goldman Sachs
Group, Inc. and Goldman, Sachs & Co. each disclaims
beneficial ownership of the shares of common stock owned
directly or indirectly by the Goldman Sachs Funds, except to the
extent of their pecuniary interest therein, if any. If the
underwriters exercise their option to purchase additional shares
in full,
(1) shares
of common stock will be sold in respect of member units owned by
GS Capital Partners V Fund, L.P.,
(2) shares
of common stock will be sold in respect of member units owned by
GS Capital Partners V Offshore Fund, L.P.,
(3) shares
of common stock will be sold in respect of member units owned by
GS Capital Partners V Institutional, L.P. and
(4) shares
of common stock will be sold in respect of member units owned by
GS Capital Partners V GmbH & Co. KG.
(3)
With respect to the total number of shares of common stock
beneficially owned prior to this offering, the share amount
includes
(1) shares
of common stock owned by Kelso Investment Associates VII,
L.P., a Delaware limited partnership, or KIA VII, and
(2) shares
of common stock 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 others 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
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. If the
underwriters exercise their option to purchase additional shares
in full, (i) shares of
common stock will be sold in respect of member units owned by
KIA VII and
(ii) shares of common
stock will be sold in respect of member units owned by
KEP VI.
(4)
The board of directors of Coffeyville Acquisition LLC, which
consists of the same members as our board of directors, has the
power to dispose of the securities of Coffeyville Acquisition
LLC.
152
Table of Contents
153
Table of Contents
154
Table of Contents
155
Table of Contents
156
Table of Contents
Number of
Amount of
Common
Promissory
Units
Note
3,717,647
$
21,000
2,230,589
$
12,600
2,230,589
$
12,600
1,301,176
$
7,350
371,764
$
2,100
650,588
$
3,675
650,588
$
3,675
157
Table of Contents
Bonus Amount
$
1,000,000
$
600,000
$
300,000
$
700,000
$
150,000
$
150,000
$
150,000
$
200,000
158
Table of Contents
159
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.
160
Table of Contents
Minimum
interest
Maximum
2.25:1.00
4.75:1.00
2.50:1.00
4.50:1.00
2.75:1.00
4.25:1.00
2.75:1.00
4.00:1.00
3.25:1.00
3.25:1.00
3.25:1.00
3.00:1.00
3.25:1.00
2.75:1.00
3.25:1.00
2.50:1.00
3.75:1.00
2.25:1.00 to 12/31/09,
2.00:1.00 thereafter
161
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.
162
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. Arons exposure under the derivative
transaction exceeds $150 million, secured by the same
collateral that secures our Credit Facility.
Coffeyville Resources, LLCs 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, LLCs 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.
163
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.
164
Table of Contents
165
Table of Contents
one percent of the number of shares of common stock then
outstanding, which will equal
approximately shares
immediately after this offering; or
the average weekly trading volume of the common stock during the
four calendar weeks preceding the sale.
166
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 trusts 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 trusts
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
particular
non-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 or
non-U.S. or
other tax consequences; and
the U.S. federal income or estate tax consequences for the
beneficial owners of a
non-U.S. holder.
167
Table of Contents
the gain is effectively connected with the
non-U.S. holders
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 the
non-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 the
non-U.S. holder
is a foreign corporation, the branch profits tax
described above may also apply;
168
Table of Contents
the
non-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 the
non-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 the
non-U.S. holder
held our common stock.
169
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,
170
Table of Contents
Number
of Shares
Full
Exercise
Full
Exercise
171
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.
172
Table of Contents
173
Table of Contents
174
Table of Contents
175
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.
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.
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.
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
176
Table of Contents
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.
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.
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.
177
Table of Contents
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 refinerys 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.
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.
178
Table of Contents
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
The composition and properties of 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 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.
179
Table of Contents
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.
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.
180
Table of Contents
F-2
F-3
F-4
F-5
F-7
F-8
F-40
F-41
F-42
F-43
F-44
F-1
Table of Contents
F-2
Table of Contents
Coffeyville
Group
Holdings, LLC
Coffeyville
Immediate
Acquisition
LLC
Predecessor
Successor
December 31,
December 31,
$
52,651,952
$
64,703,524
23,383,818
71,560,052
80,422,506
154,275,818
7,844,264
14,709,309
264,246
31,059,748
164,566,786
336,308,451
50,005,847
772,512,884
79,824
1,008,547
83,774,885
7,206,653
19,524,839
6,946,793
8,418,297
351,434
$
229,157,337
$
1,221,547,903
$
1,500,000
$
2,235,973
56,510
31,059,282
87,914,833
6,591,495
10,796,896
2,652,948
4,841,234
1,301,160
4,939,614
96,688,956
11,119,905
12,029,987
3,723,057
8,831,937
58,004,357
228,279,430
147,375,000
497,201,527
9,100,937
7,009,388
209,523,747
160,033,333
592,881
157,068,818
873,767,995
4,172,350
(500,000
)
3,672,350
10,485,160
7,584,993
(3,985,991
)
114,830,560
997,568
14,084,162
115,828,128
$
229,157,337
$
1,221,547,903
F-3
Table of Contents
Coffeyville
Farmland Industries, Inc.
Coffeyville Group Holdings, LLC
Acquisition LLC
Original Predecessor
Immediate Predecessor
Successor
Year Ended
62 Days Ended
304 Days Ended
174 Days Ended
233 Days Ended
December 31,
March 2,
December 31,
June 23,
December 31,
$
1,262,196,894
$
261,086,529
$
1,479,893,189
$
980,706,261
$
1,454,259,542
1,061,902,866
221,449,177
1,244,207,423
768,067,178
1,168,137,217
133,116,530
23,353,462
116,984,384
80,913,862
85,313,202
23,617,264
4,649,145
16,284,084
18,341,522
18,320,030
3,313,526
432,003
2,445,961
1,128,005
23,954,031
9,638,626
1,250,000
1,232,838,812
249,883,787
1,379,921,852
868,450,567
1,295,724,480
29,358,082
11,202,742
99,971,337
112,255,694
158,535,062
(1,281,513
)
(10,058,450
)
(7,801,821
)
(25,007,159
)
169,652
511,687
972,264
303,742
546,604
(7,664,725
)
(316,062,111
)
(7,166,110
)
(8,093,754
)
(458,514
)
9,345
52,659
(762,616
)
(563,190
)
(1,436,285
)
9,345
(16,455,645
)
(23,811,229
)
(340,660,196
)
27,921,797
11,212,087
83,515,692
88,444,465
(182,125,134
)
33,805,480
36,047,516
(62,968,044
)
$
27,921,797
$
11,212,087
$
49,710,212
$
52,396,949
$
(119,157,090
)
$
F-4
Table of Contents
Divisional
Voting
Nonvoting
Unearned
$
49,773,605
$
$
$
$
49,773,605
27,921,797
27,921,797
(19,503,913
)
(19,503,913
)
58,191,489
58,191,489
11,212,087
11,212,087
(53,216,357
)
(53,216,357
)
$
16,187,219
$
$
$
$
16,187,219
$
$
$
$
$
63,200,000
63,200,000
3,100,000
(3,037,000
)
63,000
2,047,450
(2,044,600
)
2,850
1,095,609
1,095,609
(94,686,276
)
(94,686,276
)
(5,301,233
)
(5,301,233
)
41,971,436
7,738,776
49,710,212
10,485,160
7,584,993
(3,985,991
)
14,084,162
3,985,991
3,985,991
728,724
728,724
(44,083,323
)
(44,083,323
)
(8,128,170
)
(8,128,170
)
44,239,908
8,157,041
52,396,949
$
$
11,370,469
$
7,613,864
$
$
18,984,333
F-5
Table of Contents
Management Voting
Common
Note Receivable
from
$
$
$
1,775,000
1,775,000
500,000
(500,000
)
3,035,586
3,035,586
(1,138,236
)
(1,138,236
)
$
4,172,350
$
(500,000
)
$
3,672,350
Management
Voting
Management
Nonvoting
Common
Nonvoting
Override
Override
$
$
$
$
235,885,000
235,885,000
602,381
395,187
997,568
(3,035,586
)
(3,035,586
)
(118,018,854
)
(118,018,854
)
$
114,830,560
$
602,381
$
395,187
$
115,828,128
Table of Contents
Coffeyville
Group
Coffeyville
Farmland
Industries, Inc.
Holdings, LLC
Acquisition
LLC
Original
Predecessor
Immediate
Predecessor
Successor
Year Ended
62 Days
Ended
304 Days
Ended
174 Days
Ended
233 Days
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
$
27,921,797
$
11,212,087
$
49,710,212
$
52,396,949
$
(119,157,090
)
3,313,526
432,003
2,445,961
1,128,005
23,954,031
190,468
(190,468
)
275,189
1,332,890
812,166
1,751,041
7,166,110
8,093,754
9,638,626
1,095,609
3,985,991
997,568
(25,301,358
)
19,635,303
(23,571,436
)
(11,334,177
)
(34,506,244
)
10,371,108
(6,399,677
)
20,068,625
(59,045,550
)
1,895,473
(23,806,340
)
25,716,107
(6,758,666
)
(937,543
)
(6,491,633
)
(90,733
)
715,132
(5,379,727
)
3,036,659
(4,651,733
)
8,347,575
(6,759,702
)
31,059,282
16,124,794
40,655,763
1,301,160
4,503,574
(136,398
)
1,545,894
8,319,913
1,209,008
(9,073,050
)
9,983,132
419,415
364,555
12,967,500
1,254,196
10,499,712
256,722,289
7,958,165
(20,057
)
(1,746,043
)
(1,553,184
)
(538,365
)
(689,372
)
(297,105
)
(295,776
)
(615,680
)
3,803,937
(98,424,817
)
20,317,675
53,215,664
89,785,901
12,708,948
82,532,142
(116,599,329
)
(685,125,669
)
(813,762
)
(14,160,280
)
(12,256,793
)
(45,172,134
)
(813,762
)
(130,759,609
)
(12,256,793
)
(730,297,803
)
(57,686,789
)
(343,449
)
(69,286,016
)
57,743,299
492,308
69,286,016
171,900,000
500,000,000
(23,025,000
)
(375,000
)
(562,500
)
(1,176,424
)
(19,503,913
)
(53,216,357
)
(16,309,917
)
(24,628,315
)
(1,095,000
)
63,263,000
237,660,000
(99,987,509
)
(52,211,493
)
(19,503,913
)
(53,216,357
)
93,625,660
(52,437,634
)
712,469,185
(693
)
52,651,952
(51,985,479
)
64,703,524
2,250
2,250
52,651,952
$
2,250
$
1,557
$
52,651,952
$
666,473
$
64,703,524
$
$
$
33,820,000
$
27,040,000
$
35,593,172
$
$
$
8,570,069
$
7,287,351
$
23,578,178
$
$
$
$
728,724
$
F-7
Table of Contents
F-8
Table of Contents
F-9
Table of Contents
$
100,491,131
1,085,598
38,239,154
$
139,815,883
$
9,910,897
1,176,424
10,846,980
1,282,253
$
23,216,554
Cash paid for acquisition of
Original Predecessor
$
116,599,329
F-10
Table of Contents
$
666,473
37,328,997
156,171,291
4,865,241
1,322,000
83,774,885
3,837,647
750,910,245
$
1,038,876,779
$
47,259,070
16,017,210
5,076,012
276,888,816
7,843,529
$
353,084,637
$
685,792,142
Immediate Predecessor
Successor
Pro Forma
174 Days Ended
233 Days Ended
Year Ended
June 23,
December 31,
December 31,
2005
2005
2005
$
52,397
($
119,157
)
($
82,898
)
Original Predecessor
Immediate Predecessor
Pro Forma
62 Days Ended
304 Days Ended
Year Ended
March 2,
December 31,
December 31,
2004
2004
2004
$
11,212
$
49,710
$
20,730
F-11
Table of Contents
(2)
Basis of
Presentation
(3)
Summary of
Significant Accounting Policies
F-12
Table of Contents
F-13
Table of Contents
Range
of useful lives, in years
15 to 20
20 to 30
5 to 30
5
3 to 5
F-14
Table of Contents
F-15
Table of Contents
F-16
Table of Contents
(4)
Members
Equity
F-17
Table of Contents
F-18
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-19
Table of Contents
Forfeiture
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-20
Table of Contents
Subject to
Forfeiture
75
%
50
%
25
%
0
%
(5)
Inventories
Immediate
Predecessor
Successor
December 31,
December 31,
$
24,704
$
58,513
26,136
47,437
14,059
33,397
15,524
14,929
$
80,423
$
154,276
F-21
Table of Contents
(6)
Property, Plant,
and Equipment
Immediate
Predecessor
Successor
December 31,
December 31,
2004
2005
$
1,061
$
9,346
768
10,306
39,617
715,381
660
3,396
1,372
271
8,738
57,382
52,216
796,082
2,210
23,569
$
50,006
$
772,513
(7)
Goodwill and
Intangible Assets
F-22
Table of Contents
Contractual
$
370
165
64
33
33
344
1,009
(8)
Deferred
Financing Costs
Immediate
Predecessor
Successor
December 31,
December 31,
$
10,009
$
24,628
1,103
1,751
8,906
22,877
1,699
3,352
$
7,207
$
19,525
F-23
Table of Contents
Deferred
$
3,352
3,337
3,332
3,308
3,293
6,255
$
22,877
(9)
Other Long-Term
Assets
Immediate
Predecessor
Successor
December 31,
December 31,
$
3,500
$
3,047
2,447
4,889
400
1,082
$
6,947
$
8,418
Prepaid
Insurance
$
1,062
394
333
333
333
1,054
3,509
(1,062
)
$
2,447
F-24
Table of Contents
(10)
Long-Term
Debt
F-25
Table of Contents
Second Lien
Credit
First Lien Credit
Facility
Facility
Maximum
Maximum
Minimum
Interest
Leverage
Leverage
2.25:1.00
5.00:1.00
5.25:1.00
2.25:1.00
5.00:1.00
5.25:1.00
2.25:1.00
5.00:1.00
5.25:1.00
2.25:1.00
5.00:1.00
5.25:1.00
2.25:1.00
4.75:1.00
5.00:1.00
2.50:1.00
4.50:1.00
4.75:1.00
2.75:1.00
4.25:1.00
4.75:1.00
3.00:1.00
3.50:1.00
4.00:1.00
3.25:1.00
3.50:1.00
4.00:1.00
3.25:1.00
3.25:1.00
3.75:1.00
3.25:1.00
3.00:1.00
3.50:1.00
3.25:1.00
2.75:1.00
3.25:1.00
3.50:1.00
2.50:1.00
3.00:1.00
$
224,437,500
275,000,000
499,437,500
2,235,973
$
497,201,527
F-26
Table of Contents
$
2,235,973
2,213,697
2,191,642
2,169,808
2,148,191
488,478,189
$
499,437,500
(11)
Benefit
Plans
F-27
Table of Contents
(12)
Income
Taxes
Immediate
Predecessor
Successor
304 Days
174 Days
229 Days
Ended
Ended
Ended
December 31,
June 23,
December 31,
$
27,902
$
26,145
$
29,000
6,519
6,099
6,457
34,421
32,244
35,457
(499
)
3,083
(80,500
)
(117
)
721
(17,925
)
(616
)
3,804
(98,425
)
$
33,805
$
36,048
$
(62,968
)
Immediate
Predecessor
Successor
304 Days
174 Days
229 Days
Ended
Ended
Ended
December 31,
June 23,
December 31,
$
29,230
$
30,956
$
(63,744
)
8,750
4,162
4,433
(7,454
)
(825
)
(897
)
413
1,484
377
$
33,805
$
36,048
$
(62,968
)
F-28
Table of Contents
Immediate
Predecessor
Successor
December 31,
December 31,
$
74
$
109
342
483
215
560
166
229
91,226
1,026
92,378
326
84
269,462
1,238
142
410
270,842
$
616
$
(178,464
)
F-29
Table of Contents
(13)
Commitments and
Contingent Liabilities
Year
Ending
Operating
Unconditional
$
3,654,956
$
22,462,157
3,445,287
22,840,325
3,354,004
18,716,401
2,595,539
18,685,325
1,259,805
16,293,845
644,669
153,877,335
$
14,954,260
$
252,875,388
F-30
Table of Contents
F-31
Table of Contents
F-32
Table of Contents
$
1,211
1,712
616
508
473
6,798
11,318
3,098
$
8,220
(14)
Derivative
Financial Instruments
F-33
Table of Contents
F-34
Table of Contents
Notional
Fixed
$
375 million
3.835
%
325 million
4.038
%
325 million
4.195
%
250 million
4.195
%
180 million
4.195
%
110 million
4.195
%
(15)
Related Party
Transactions
F-35
Table of Contents
(16)
Business
Segments
F-36
Table of Contents
Original
Predecessor
Immediate
Predecessor
Successor
Year
62-Day
Period
304-Day
Period
174-Day
Period
233-Day
Period
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
$
1,161,287,249
$
241,640,365
$
1,390,768,126
$
903,802,983
$
1,363,390,142
100,909,645
19,446,164
93,422,503
79,347,843
93,651,855
(4,297,440
)
(2,444,565
)
(2,782,455
)
$
1,262,196,894
$
261,086,529
$
1,479,893,189
$
980,706,261
$
1,454,259,542
$
1,040,032,230
$
217,375,945
$
1,228,074,299
$
761,719,405
$
1,156,208,301
21,870,636
4,073,232
20,433,642
9,125,852
14,503,824
(4,300,518
)
(2,778,079
)
(2,574,908
)
$
1,061,902,866
$
221,449,177
$
1,244,207,423
$
768,067,178
$
1,168,137,217
F-37
Table of Contents
Original
Predecessor
Immediate
Predecessor
Successor
Year
62-Day
Period
304-Day
Period
174-Day
Period
233-Day
Period
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
$
80,104,220
$
14,925,611
$
73,231,607
$
52,611,148
$
56,159,473
53,012,310
8,427,851
43,752,777
28,302,714
29,153,729
$
133,116,530
$
23,353,462
$
116,984,384
$
80,913,862
$
85,313,202
$
2,094,627
$
271,284
$
1,522,464
$
770,728
$
15,566,987
1,218,899
160,719
855,289
316,446
8,360,911
68,208
40,831
26,133
$
3,313,526
$
432,003
$
2,445,961
$
1,128,005
$
23,954,031
$
21,544,374
$
7,687,745
$
77,094,034
$
76,654,428
$
123,044,854
7,813,708
3,514,997
22,874,227
35,267,752
35,731,056
3,076
333,514
(240,848
)
$
29,358,082
$
11,202,742
$
99,971,337
$
112,255,694
$
158,535,062
$
489,083
$
$
11,267,244
$
10,790,042
$
42,107,751
324,679
2,697,852
1,434,921
2,017,385
195,184
31,830
1,046,998
$
813,762
$
$
14,160,280
$
12,256,793
$
45,172,134
$
3,950,519
$
$
$
$
5,688,107
$
9,638,626
$
$
$
$
$
145,861,715
$
664,870,240
83,561,149
425,333,621
(265,527
)
131,344,042
$
229,157,337
$
1,221,547,903
$
$
42,806,422
40,968,463
$
$
83,774,885
Table of Contents
(17)
Major Customers
and Suppliers
Original
Predecessor
Immediate
Predecessor
Successor
Year
62-Day
Period
304-Day
Period
174-Day
Period
233-Day
Period
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
2004
89
%
10
%
18
%
17
%
16
%
3
%
25
%
10
%
5
%
6
%
1
%
18
%
17
%
17
%
15
%
8
%
14
%
17
%
1
%
9
%
15
%
11
%
11
%
94
%
62
%
68
%
64
%
65
%
66
%
48
%
24
%
16
%
10
%
0
%
0
%
5
%
9
%
10
%
66
%
48
%
29
%
25
%
20
%
Original
Predecessor
Immediate
Predecessor
Successor
Year
62-Day
Period
304-Day
Period
174-Day
Period
233-Day
Period
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
2003
2004
2004
2005
2005
28
%
32
%
68
%
77
%
69
%
Original
Predecessor
Immediate
Predecessor
Successor
Year
62-Day
Period
304-Day
Period
174-Day
Period
233-Day
Period
Ended
Ended
Ended
Ended
Ended
December 31,
March 2,
December 31,
June 23,
December 31,
1
%
2
%
3
%
3
%
3
%
F-39
Table of Contents
Pro Forma
Successor
Successor
Successor
December 31,
September 30,
September 30,
(unaudited)
(unaudited)
(Note 3)
$
64,703,524
$
38,085,502
$
71,560,052
48,407,925
154,275,818
214,058,461
11,786,287
14,709,309
31,104,515
31,059,748
17,271,108
336,308,451
360,713,798
772,512,884
928,152,935
1,008,547
730,979
83,774,885
83,774,885
19,524,839
17,027,193
8,418,297
7,253,308
$
1,221,547,903
$
1,397,653,098
$
$
2,235,973
$
2,219,245
$
87,914,833
107,729,484
10,796,896
9,891,357
4,841,234
2,331,067
4,939,614
96,688,956
54,633,859
12,029,987
5,365,673
8,831,937
5,176,125
228,279,430
187,346,810
497,201,527
525,539,179
7,009,388
5,628,547
209,523,747
253,338,137
160,033,333
113,630,301
873,767,995
898,136,164
4,172,350
9,020,375
(500,000
)
3,672,350
9,020,375
114,830,560
300,778,557
997,568
2,371,192
115,828,128
303,149,749
$
1,221,547,903
$
1,397,653,098
$
F-40
Table of Contents
Immediate
Predecessor
Successor
174 Days Ended
141 Days Ended
Nine Months Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
$
980,706,261
$
776,628,260
$
2,329,152,871
768,067,178
624,862,774
1,848,076,557
80,913,862
36,674,930
144,461,227
18,341,522
7,415,773
32,796,414
1,128,005
11,924,349
36,809,644
868,450,567
680,877,826
2,062,143,842
112,255,694
95,750,434
267,009,029
(7,801,821
)
(12,236,014
)
(33,016,684
)
511,687
181,341
2,773,949
(7,664,725
)
(487,045,767
)
44,746,853
(8,093,754
)
(762,616
)
10,341
310,704
(23,811,229
)
(499,090,099
)
14,814,822
88,444,465
(403,339,665
)
281,823,851
36,047,516
(150,773,609
)
111,027,829
$
52,396,949
$
(252,566,056
)
$
170,796,022
$
F-41
Table of Contents
Management Voting
Common
Units Subject to
Note Receivable
Redemption
from Management
Total
227,500
$
4,172,350
$
(500,000
)
$
3,672,350
150,000
150,000
350,000
350,000
3,342,908
3,342,908
1,505,117
1,505,117
227,500
$
9,020,375
$
$
9,020,375
Management
Management
Nonvoting Override
Nonvoting Override
Voting Common Units
Operating Units
Value Units
Total
23,588,500
$
114,830,560
919,630
$
602,381
1,839,265
$
395,187
$
115,828,128
2,000,000
20,000,000
20,000,000
865,527
508,097
1,373,624
(3,342,908
)
(3,342,908
)
169,290,905
169,290,905
25,588,500
$
300,778,557
919,630
$
1,467,908
1,839,265
$
903,284
$
303,149,749
F-42
Table of Contents
Immediate
Predecessor
Successor
174 Days Ended
141 Days Ended
Nine Months Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
$
52,396,949
$
(252,566,056
)
$
170,796,022
1,128,005
11,924,349
36,809,644
(190,468
)
285,514
2,664
812,166
896,640
2,508,847
8,093,754
1,188,360
350,000
3,985,991
536,523
1,373,624
(11,334,177
)
(13,024,860
)
23,149,463
(59,045,550
)
15,046,799
(59,782,643
)
(937,543
)
(3,105,606
)
(16,537,977
)
3,036,659
(3,729,006
)
1,081,470
16,124,794
2,544,442
(380,356
)
4,503,574
4,088,672
(16,725,901
)
(9,073,050
)
5,066,510
(6,664,314
)
1,254,196
5,298,237
(7,071,516
)
466,661,429
(88,458,131
)
(1,553,184
)
(791,259
)
(1,380,841
)
(297,105
)
(216,335
)
3,803,937
(175,605,857
)
57,603,030
12,708,948
63,310,136
97,861,445
(685,125,669
)
(12,256,793
)
(12,056,423
)
(172,950,391
)
(12,256,793
)
(697,182,092
)
(172,950,391
)
(343,449
)
(69,286,016
)
492,308
69,286,016
500,000,000
30,000,000
(375,000
)
(1,679,076
)
(24,436,970
)
237,660,000
20,000,000
150,000
(52,211,493
)
(52,437,634
)
713,223,030
48,470,924
(51,985,479
)
79,351,074
(26,618,022
)
52,651,952
64,703,524
$
666,473
$
79,351,074
$
38,085,502
$
27,040,000
$
20,743,577
$
70,150,700
$
7,287,351
$
10,993,563
$
38,229,085
$
$
$
20,195,007
$
728,724
$
$
F-43
Table of Contents
F-44
Table of Contents
$
666,473
37,328,997
156,171,291
4,865,241
1,322,000
83,774,885
3,837,647
750,910,245
$
1,038,876,779
$
47,259,070
16,017,210
5,076,012
276,888,816
7,843,529
$
353,084,637
Cash paid for acquisition of
Immediate Predecessor
$
685,792,142
F-45
Table of Contents
Immediate Predecessor
Successor
Pro Forma
174 Days Ended
141 Days Ended
Nine Months Ended
June 23,
September 30,
September 30,
2005
2005
2005
$
52,397
($
252,566
)
($
216,657
)
F-46
Table of Contents
None
Based on forfeiture schedule below
$5.16 per share
$1.24 per share (24% discount)
37%
Minimum
Period
Forfeiture
Percentage
75%
50%
25%
0%
None
6 years
$2.91 per share
$0.70 per share (24% discount)
37%
F-47
Table of Contents
Minimum
Subject to
Period
Forfeiture
Percentage
75
%
50
%
25
%
0
%
F-48
Table of Contents
Successor
December 31,
September 30,
2005
2006
(Unaudited)
$
58,513
$
63,042
47,437
70,398
33,397
56,610
14,929
24,008
$
154,276
$
214,058
F-49
Table of Contents
Operating
Unconditional
Leases
Purchase Obligations
$
869,068
$
6,616,246
3,751,500
24,811,345
3,645,218
20,566,369
2,899,193
20,533,845
1,596,818
18,142,365
857,494
16,272,447
108,063
145,315,392
$
13,727,354
$
252,258,009
F-50
Table of Contents
Amount
$
347
1,737
904
493
341
341
6,001
10,164
2,717
$
7,447
F-51
Table of Contents
F-52
Table of Contents
Notional
Fixed
Amount
Interest Rate
375 million
4.038%
325 million
4.038%
325 million
4.195%
250 million
4.195%
180 million
4.195%
110 million
4.195%
F-53
Table of Contents
F-54
Table of Contents
Immediate Predecessor
Successor
174-Day
Period
141-Day
Period
Nine Months
Ended
Ended
Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
$
903,802,983
$
731,565,974
$
2,204,959,676
79,347,843
46,590,621
128,155,190
(2,444,565
)
(1,528,335
)
(3,961,995
)
$
980,706,261
$
776,628,260
$
2,329,152,871
$
761,719,405
$
617,186,711
$
1,828,052,007
9,125,852
9,172,463
23,829,421
(2,778,079
)
(1,496,400
)
(3,804,871
)
$
768,067,178
$
624,862,774
$
1,848,076,557
$
52,611,148
$
22,525,113
$
97,254,100
28,302,714
14,149,817
47,207,127
$
80,913,862
$
36,674,930
$
144,461,227
$
770,728
$
7,735,006
$
23,561,843
316,446
4,176,123
12,714,478
40,831
13,220
533,323
$
1,128,005
$
11,924,349
$
36,809,644
$
76,654,428
$
79,081,672
$
233,522,252
35,267,752
16,729,633
34,058,010
333,514
(60,871
)
(571,233
)
$
112,255,694
$
95,750,434
$
267,009,029
Table of Contents
Immediate Predecessor
Successor
174-Day
Period
141-Day
Period
Nine Months
Ended
Ended
Ended
June 23,
September 30,
September 30,
(unaudited)
(unaudited)
$
10,790,042
$
10,920,718
$
157,606,403
1,434,921
947,991
12,710,765
31,830
187,714
2,633,223
$
12,256,793
$
12,056,423
$
172,950,391
$
865,356,278
421,830,249
110,466,571
$
1,397,653,098
$
42,806,422
40,968,463
$
83,774,885
Table of Contents
Immediate
Predecessor
Successor
174-Day
Period
141-Day
Period
Nine Months
Ended
Ended
Ended
June 23,
September 30,
September 30,
17
%
18
%
2
%
17
%
18
%
16
%
14
%
14
%
11
%
11
%
11
%
10
%
59
%
61
%
39
%
16
%
5
%
6
%
9
%
11
%
4
%
25
%
16
%
10
%
Immediate
Predecessor
Successor
174-Day
Period
141-Day
Period
Nine Months
Ended
Ended
Ended
September 23,
September 30,
September 30,
77
%
70
%
0
%
67
%
77
%
70
%
67
%
F-57
Table of Contents
F-58
Prospectus
Summary
1
18
34
36
37
38
39
40
44
52
102
109
132
150
153
159
164
166
167
171
175
175
175
176
F-1
EX-10.1: SECOND AMENDED AND RESTATED CREDIT AND GUARANTY AGREEMENT
EX-10.2: AMENDED AND RESTATED FIRST LIEN PLEDGE AND SECURITY AGREEMENT
EX-10.16: EMPLOYMENT AGREEMENT WITH ROBERT W. HAUGEN
EX-10.21: RECAPITALIZATION AGREEMENT
EX-23.1: CONSENT OF KPMG LLP
EX-23.3: CONSENT OF BLUE, JOHNSON & ASSOCIATES
EX-24.2: POWER OF ATTORNEY OF MARK TOMKINS
Table of Contents
Item 13.
Other Expenses
of Issuance and Distribution.
$
32,100.00
30,500.00
$
Item 14.
Indemnification
of Directors and Officers.
for any breach of the directors 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.
1
.1*
Form of Underwriting Agreement.
3
.1*
Certificate of Incorporation of
CVR Energy, Inc.
3
.2*
Bylaws of CVR Energy, Inc.
4
.1*
Specimen Common Stock Certificate.
5
.1*
Form of opinion of Fried, Frank,
Harris, Shriver & Jacobson LLP.
10
.1
Second Amended and Restated Credit
and Guaranty Agreement, dated as of December 28, 2006,
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*
Coffeyville Resources, LLC Phantom
Unit Appreciation Plan.
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
.6**
Amended and Restated
On-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.
II-2
Table of Contents
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 dated as of
July 12, 2005, by and between Coffeyville Resources, LLC
and Robert W. Haugen.
10
.17*
Stockholders Agreement of
Coffeyville Nitrogen Fertilizer, Inc., dated as
of ,
by and among Coffeyville Nitrogen Fertilizer, Inc., Coffeyville
Acquisition LLC and John J. Lipinski.
10
.18*
Stockholders Agreement of
Coffeyville Refining & Marketing, Inc., dated as
of ,
by and among Coffeyville Refining & Marketing, Inc.,
Coffeyville Acquisition LLC and John J. Lipinski.
10
.19*
Subscription Agreement, dated as
of ,
between Coffeyville Nitrogen Fertilizer, Inc. and John J.
Lipinski.
10
.20*
Subscription Agreement, dated as
of ,
between Coffeyville Refining & Marketing, Inc. and John J.
Lipinski.
10
.21
Recapitalization Agreement, dated
as of September 25, 2006, by and among Coffeyville
Acquisition LLC, Coffeyville Refining & Marketing, Inc.,
Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc.
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.
24
.1**
Power of Attorney.
24
.2
Power of Attorney of Mark Tomkins.
*
To be filed by amendment.
**
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.
II-3
Table of Contents
Item 17.
Undertakings.
II-4
Table of Contents
By:
Chief Executive Officer, President
and Director (principal executive officer)
February 12, 2007
Chief Financial Officer (Principal
Financial and Accounting Officer)
February 12, 2007
Director
February 12, 2007
Director
February 12, 2007
Director
February 12, 2007
Director
February 12, 2007
Director
February 12, 2007
Director
February 12, 2007
* By:
John J. Lipinski,
As Attorney-in-Fact
II-5
Table of Contents
1
.1*
Form of Underwriting Agreement.
3
.1*
Certificate of Incorporation of
CVR Energy, Inc.
3
.2*
Bylaws of CVR Energy, Inc.
4
.1*
Specimen Common Stock Certificate.
5
.1*
Form of opinion of Fried, Frank,
Harris, Shriver & Jacobson LLP.
10
.1
Second Amended and Restated Credit
and Guaranty Agreement, dated as of December 28, 2006,
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*
Coffeyville Resources, LLC Phantom
Unit Appreciation Plan.
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
.6**
Amended and Restated
On-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 dated as of
July 12, 2005, by and between Coffeyville Resources, LLC
and Robert W. Haugen.
Table of Contents
10
.17*
Stockholders Agreement of
Coffeyville Nitrogen Fertilizer, Inc., dated as
of ,
by and among Coffeyville Nitrogen Fertilizer, Inc., Coffeyville
Acquisition LLC and John J. Lipinski.
10
.18*
Stockholders Agreement of
Coffeyville Refining & Marketing, Inc., dated as
of ,
by and among Coffeyville Refining & Marketing, Inc.,
Coffeyville Acquisition LLC and John J. Lipinski.
10
.19*
Subscription Agreement, dated as
of ,
by Coffeyville Nitrogen Fertilizer, Inc. and John J.
Lipinski.
10
.20*
Subscription Agreement, dated as
of ,
by Coffeyville Refining & Marketing, Inc. and John J.
Lipinski.
10
.21
Recapitalization Agreement, dated
as of September 25, 2006, by and among Coffeyville
Acquisition LLC, Coffeyville Refining & Marketing, Inc.,
Coffeyville Nitrogen Fertilizers, Inc. and CVR Energy, Inc.
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.
24
.1**
Power of Attorney.
24
.2
Power of Attorney of Mark Tomkins.
*
To be filed by amendment.
**
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.
SECTION 1. DEFINITIONS AND INTERPRETATION
|
2 | |||
1.1. Definitions
|
2 | |||
1.2. Accounting Terms
|
39 | |||
1.3. Interpretation, etc.
|
40 | |||
|
||||
SECTION 2. LOANS AND LETTERS OF CREDIT
|
40 | |||
2.1. Tranche D Term Loans
|
40 | |||
2.2. Revolving Loans
|
41 | |||
2.3. Swing Line Loans
|
42 | |||
2.4. Issuance of Letters of Credit and Purchase of Participations Therein
|
44 | |||
2.5. Pro Rata Shares; Availability of Funds
|
53 | |||
2.6. Use of Proceeds
|
53 | |||
2.7. Evidence of Debt; Register; Lenders Books and Records; Notes
|
54 | |||
2.8. Interest on Loans
|
55 | |||
2.9. Conversion/Continuation
|
57 | |||
2.10. Default Interest
|
58 | |||
2.11. Fees
|
58 | |||
2.12. Scheduled Payments/Commitment Reductions
|
60 | |||
2.13. Voluntary Prepayments/Commitment Reductions
|
60 | |||
2.14. Mandatory Prepayments/Commitment Reductions
|
62 | |||
2.15. Application of Prepayments/Reductions
|
64 | |||
2.16. General Provisions Regarding Payments
|
65 | |||
2.17. Ratable Sharing
|
66 | |||
2.18. Making or Maintaining Eurodollar Rate Loans
|
67 | |||
2.19. Increased Costs; Capital Adequacy
|
69 | |||
2.20. Taxes; Withholding, etc.
|
70 | |||
2.21. Obligation to Mitigate
|
74 | |||
2.22. Defaulting Lenders
|
74 | |||
2.23. Removal or Replacement of a Lender
|
75 | |||
|
||||
SECTION 3. CONDITIONS PRECEDENT
|
76 | |||
3.1. Effective Date
|
76 | |||
3.2. Conditions to Each Credit Extension
|
80 | |||
|
||||
SECTION 4. REPRESENTATIONS AND WARRANTIES
|
81 | |||
4.1. Organization; Requisite Power and Authority; Qualification
|
81 | |||
4.2. Capital Stock and Ownership
|
81 | |||
4.3. Due Authorization
|
81 | |||
4.4. No Conflict
|
81 | |||
4.5. Governmental Consents
|
82 | |||
4.6. Binding Obligation
|
82 | |||
4.7. Historical Financial Statements
|
82 |
ii
4.8. Projections
|
82 | |||
4.9. No Material Adverse Change
|
83 | |||
4.10. No Restricted Junior Payments
|
83 | |||
4.11. Adverse Proceedings, etc.
|
83 | |||
4.12. Payment of Taxes
|
83 | |||
4.13. Properties
|
83 | |||
4.14. Environmental Matters
|
84 | |||
4.15. No Defaults
|
86 | |||
4.16. Material Contracts
|
86 | |||
4.17. Governmental Regulation
|
86 | |||
4.18. Margin Stock
|
86 | |||
4.19. Employee Matters
|
86 | |||
4.20. Employee Benefit Plans
|
87 | |||
4.21. Certain Fees
|
87 | |||
4.22. Solvency
|
87 | |||
4.23. Related Agreements
|
88 | |||
4.24.
Compliance with Statutes, etc.
|
88 | |||
4.25. Disclosure
|
88 | |||
4.26. Patriot Act
|
88 | |||
4.27. First Buyer
|
89 | |||
|
||||
SECTION 5. AFFIRMATIVE COVENANTS
|
89 | |||
5.1. Financial Statements and Other Reports
|
89 | |||
5.2. Existence
|
94 | |||
5.3. Payment of Taxes and Claims
|
94 | |||
5.4. Maintenance of Properties
|
95 | |||
5.5. Insurance
|
95 | |||
5.6. Books and Records; Inspections
|
96 | |||
5.7. Lenders Meetings
|
96 | |||
5.8. Compliance with Laws
|
96 | |||
5.9. Environmental
|
96 | |||
5.10. Subsidiaries
|
100 | |||
5.11. Additional Material Real Estate Assets
|
101 | |||
5.12. Interest Rate Protection
|
101 | |||
5.13. Swap Agreement
|
101 | |||
5.14. Further Assurances
|
102 | |||
5.15. Miscellaneous Business Covenants
|
102 | |||
5.16. [Reserved]
|
102 | |||
5.17. Refinery Revenue Bonds
|
102 | |||
|
||||
SECTION 6. NEGATIVE COVENANTS
|
103 | |||
6.1. Indebtedness
|
104 | |||
6.2. Liens
|
107 | |||
6.3. Equitable Lien
|
109 | |||
6.4. No Further Negative Pledges
|
109 | |||
6.5. Restricted Junior Payments
|
110 | |||
6.6. Restrictions on Subsidiary Distributions
|
112 |
iii
6.7. Investments
|
113 | |||
6.8. Financial Covenants
|
115 | |||
6.9. Fundamental Changes; Disposition of Assets; Acquisitions
|
118 | |||
6.10. Disposal of Subsidiary Interests
|
120 | |||
6.11. Sales and Lease-Backs
|
121 | |||
6.12. Transactions with Shareholders and Affiliates
|
121 | |||
6.13. Conduct of Business
|
121 | |||
6.14. Permitted Activities of Holdings
|
121 | |||
6.15. Amendments or Waivers of Certain Related Agreements
|
122 | |||
6.16. [Reserved]
|
122 | |||
6.17. Fiscal Year
|
122 | |||
6.18. [Reserved]
|
122 | |||
6.19. [Reserved]
|
122 | |||
6.20. Maximum Amount of Hedged Production
|
122 | |||
|
||||
SECTION 7. GUARANTY
|
122 | |||
7.1. Guaranty of the Obligations
|
122 | |||
7.2. Contribution by Guarantors
|
122 | |||
7.3. Payment by Guarantors
|
123 | |||
7.4. Liability of Guarantors Absolute
|
123 | |||
7.5. Waivers by Guarantors
|
125 | |||
7.6. Guarantors Rights of Subrogation, Contribution, etc.
|
126 | |||
7.7. Subordination of Other Obligations
|
127 | |||
7.8. Continuing Guaranty
|
127 | |||
7.9. Authority of Guarantors or Company
|
127 | |||
7.10. Financial Condition of Company
|
127 | |||
7.11. Bankruptcy, etc.
|
128 | |||
7.12. Discharge of Guaranty Upon Sale of Guarantor
|
128 | |||
|
||||
SECTION 8. EVENTS OF DEFAULT
|
129 | |||
8.1. Events of Default
|
129 | |||
|
||||
SECTION 9. AGENTS
|
132 | |||
9.1. Powers and Duties
|
132 | |||
9.2. General Immunity
|
132 | |||
9.3. Agents Entitled to Act as Lender
|
134 | |||
9.4. Lenders Representations, Warranties and Acknowledgment
|
135 | |||
9.5. Right to Indemnity
|
135 | |||
9.6. Successor Administrative Agent and Swing Line Lender
|
135 | |||
9.7. Collateral Documents and Guaranty
|
136 | |||
|
||||
SECTION 10. MISCELLANEOUS
|
137 | |||
10.1. Notices
|
137 | |||
10.2. Expenses
|
137 | |||
10.3. Indemnity
|
138 | |||
10.4. Set-Off
|
139 | |||
10.5. Amendments and Waivers
|
139 |
iv
10.6. Successors and Assigns; Participations
|
142 | |||
10.7. Independence of Covenants
|
146 | |||
10.8. Survival of Representations, Warranties and Agreements
|
146 | |||
10.9. No Waiver; Remedies Cumulative
|
146 | |||
10.10. Marshalling; Payments Set Aside
|
146 | |||
10.11. Severability
|
146 | |||
10.12. Obligations Several; Independent Nature of Lenders Rights
|
147 | |||
10.13. Headings
|
147 | |||
10.14. APPLICABLE LAW
|
147 | |||
10.15. CONSENT TO JURISDICTION
|
147 | |||
10.16. WAIVER OF JURY TRIAL
|
148 | |||
10.17. Confidentiality
|
148 | |||
10.18. Usury Savings Clause
|
149 | |||
10.19. Counterparts
|
149 | |||
10.20. Effectiveness
|
149 | |||
10.21. Patriot Act
|
149 | |||
10.22. Electronic Execution of Assignments
|
150 | |||
10.23. Amendment and Restatement
|
150 | |||
10.24. Reaffirmation and Grant of Security Interests
|
150 |
v
APPENDICES:
|
A-1 | Tranche D Term Loan Commitments | ||||
|
A-2 | Funded Letter of Credit Commitments | ||||
|
A-3 | Revolving Commitments | ||||
|
B | Notice Addresses | ||||
|
||||||
SCHEDULES:
|
3.1 | (i) | Closing Date Mortgaged Properties | |||
|
3.1 | (k) | Environmental Reports | |||
|
4.1 | Jurisdictions of Organization and Qualification | ||||
|
4.2 | Capital Stock and Ownership | ||||
|
4.11 | Adverse Proceedings | ||||
|
4.13 | Real Estate Assets | ||||
|
4.14 | Environmental Matters | ||||
|
4.16 | Material Contracts | ||||
|
6.1 | Certain Indebtedness | ||||
|
6.2 | Certain Liens | ||||
|
6.7 | Certain Investments | ||||
|
6.12 | Certain Affiliate Transactions | ||||
|
||||||
EXHIBITS:
|
A-1 | Funding Notice | ||||
|
A-2 | Conversion/Continuation Notice | ||||
|
A-3 | Issuance Notice | ||||
|
B-1 | Tranche D Term Loan Note | ||||
|
B-2 | Revolving Loan Note | ||||
|
B-3 | Swing Line Note | ||||
|
C | Compliance Certificate | ||||
|
D | Opinions of Counsel | ||||
|
E | Assignment Agreement | ||||
|
F | Certificate Re Non-bank Status | ||||
|
G-1 | Effective Date Certificate | ||||
|
G-2 | Solvency Certificate | ||||
|
H | Counterpart Agreement | ||||
|
I | Pledge and Security Agreement | ||||
|
J | Mortgage |
vi
2
3
Applicable Margin | ||
Revolving Credit Status | for Revolving Loans | |
Revolving Credit Level I Status
|
3.25% | |
Revolving Credit Level II Status
|
3.00% | |
Revolving Credit Level III Status
|
2.75% | |
Revolving Credit Level IV Status
|
2.50% |
Applicable Margin | ||
for Term Loans and Funded Letters | ||
Term Loan Status | of Credit | |
Term Loan Level I Status
|
3.25% | |
Term Loan Level II Status
|
3.00% | |
Term Loan Level III Status
|
2.75% | |
Term Loan Level IV Status
|
2.50% |
4
5
(a) | the Prime Rate in effect on such day; | ||
(b) | the Federal Funds Effective Rate on such day plus 1/2 of 1%; and |
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
51
52
53
54
55
56
57
58
59
Installment Date | Installments | |
Each Installment Date prior to April 1, 2013
|
0.25% | |
|
||
Each Installment Date during the period commencing April 1,
2013 through the Term Loan Maturity Date
|
23.5% |
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
105
106
107
108
109
110
111
112
113
114
Interest | ||
Fiscal Quarter | Coverage Ratio | |
March 31, 2007
|
2.25:1.00 | |
June 30, 2007
|
2.50:1.00 | |
September 30, 2007
|
2.75:1.00 | |
December 31, 2007
|
2.75:1.00 | |
March 31, 2008
|
3.25:1.00 | |
June 30, 2008
|
3.25:1.00 | |
September 30, 2008
|
3.25:1.00 | |
December 31, 2008
|
3.25:1.00 | |
March 31, 2009 and thereafter
|
3.75:1.00 |
115
Fiscal | Leverage | |
Quarter | Ratio | |
March 31, 2007
|
4.75:1.00 | |
June 30, 2007
|
4.50:1.00 | |
September 30, 2007
|
4.25:1.00 | |
December 31, 2007
|
4.00:1.00 | |
March 31, 2008
|
3.25:1.00 | |
June 30, 2008
|
3.00:1.00 | |
September 30, 2008
|
2.75:1.00 | |
December 31, 2008
|
2.50:1.00 | |
March 31, 2009
|
2.25:1.00 | |
June 30, 2009
|
2.25:1.00 | |
September 30, 2009
|
2.25:1.00 | |
December 31, 2009
|
2.25:1.00 | |
March 31, 2010 and thereafter
|
2.00:1.00 |
116
Consolidated | ||
Capital | ||
Fiscal Year | Expenditures | |
2007
|
$225,000,000
|
|
|
plus the 2006 | |
|
Carryover | |
2008
|
$100,000,000 | |
2009
|
$80,000,000 | |
2010
|
$80,000,000 | |
2011 and Thereafter
|
$50,000,000 |
117
118
119
120
121
122
123
124
125
126
127
128
129
130
131
132
133
134
135
136
137
138
139
140
141
142
143
144
145
146
147
148
149
150
151
COFFEYVILLE RESOURCES, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE PIPELINE, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE REFINING & MARKETING, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE NITROGEN FERTILIZERS, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
S-1
COFFEYVILLE CRUDE TRANSPORTATION, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE TERMINAL, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
CL JV HOLDINGS, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES PIPELINE, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES REFINING &
MARKETING, LLC |
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
S-2
COFFEYVILLE RESOURCES NITROGEN
FERTILIZERS, LLC |
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
S-3
COFFEYVILLE RESOURCES CRUDE
TRANSPORTATION, LLC |
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES TERMINAL, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
S-4
GOLDMAN SACHS CREDIT PARTNERS L.P.,
as Joint Lead Arranger, Joint Bookrunner and a Lender |
||||
By: | /s/ Bruce H. Mendelsohn | |||
Authorized Signatory | ||||
S-5
CREDIT SUISSE Securities (USA) LLC
,
as Joint Lead Arranger and Joint Bookrunner |
||||
By: | /s/ Clarke Adams | |||
Name: | Clarke Adams | |||
Title: | Director | |||
S-6
CREDIT SUISSE, CAYMAN ISLANDS BRANCH
,
as Administrative Agent, Collateral Agent, Swing Line Lender, Funded LC Issuing Bank and Revolving Issuing Bank and a Lender |
||||
By: | /s/ Thomas R. Cantello | |||
Name: | Thomas R. Cantello | |||
Title: | Vice President | |||
By: | /s/ Denise Alvarez | |||
Name: | Denise Alvarez | |||
Title: | Associate |
S-7
DEUTSCHE BANK TRUST COMPANY AMERICAS,
as Syndication Agent and a Lender |
||||
By: | /s/ Albert Fischetti | |||
Name: | Albert Fischetti | |||
Title: | Director | |||
By: | /s/ Illegible | |||
Name: | ||||
Title: | Managing Director |
S-8
CITICORP NORTH AMERICA, INC.,
as Lender |
||||
By: | /s/ Michael M. Schadt | |||
Name: | Michael M. Schadt | |||
Title: | Director |
S-9
N M ROTHSCHILD & SONS LIMITED,
as Lender |
||||
By: | /s/ N.A. Wood | |||
Name: | Nicholas Wood | |||
Title: | Director |
S-10
ALLIED IRISH BANKS, PLC,
as Lender |
||||
By: | /s/ Mark Connelly | |||
Name: | Mark Connelly | |||
Title: | Senior Vice President | |||
By: | /s/ Robert Moyle | |||
Name: | Robert Moyle | |||
Title: | Senior Vice President |
S-11
ERSTE BANK DER OESTERREICHISCHEN
SPARKASSEN AG, as Lender |
||||
By: | /s/ Bryan J. Lynch | |||
Name: | Bryan J. Lynch | |||
Title: | Managing Director | |||
By: | /s/ Patrick W. Kunkel | |||
Name: | Patrick W. Kunkel | |||
Title: | Executive Director |
S-12
AMEGY BANK NATIONAL ASSOCIATION,
as Lender |
||||
By: | /s/ Chris Petersen | |||
Name: | Chris Petersen | |||
Title: | Banking Officer, Energy Lending |
S-13
JACKSON PURCHASE AGA,
as Lender |
||||
By: | /s/ Stan Brunston | |||
Name: | Stan Brunston | |||
Title: | Sr. V.P. Credit |
S-14
ABN AMRO BANK N.V.,
as Lender |
||||
By: | /s/ Liz Lary | |||
Name: | Liz Lary | |||
Title: | Vice President | |||
By: | /s/ M. Aamir Khan | |||
Name: | M. Aamir Khan | |||
Title: | Assistant Vice President |
S-15
ABN AMRO BANK N.V.,
as Documentation Agent |
||||
By: | /s/ John Reed | |||
Name: | John Reed | |||
Title: | Director | |||
By: | /s/ M. Aamir Khan | |||
Name: | M. Aamir Khan | |||
Title: | Assistant Vice President |
S-16
Tranche D Term Loan | Pro | |||||||
Lender | Commitment | Rata Share | ||||||
Goldman Sachs Credit Partners L.P.
|
$ | 775,000,000 | 100 | % | ||||
|
||||||||
Total
|
$ | 775,000,000 | 100 | % | ||||
|
APPENDIX A-1-1
Funded Letter of Credit | ||||||||
Lender | Commitment | Pro Rata Share | ||||||
Goldman Sachs Credit Partners L.P.
|
$ | 150,000,000 | 100 | % | ||||
|
||||||||
Total
|
$ | 150,000,000 | 100 | % | ||||
|
APPENDIX A-2-1
Lender | Revolving Commitments | Pro Rata Share | ||||||
Goldman Sachs Credit Partners L.P.
|
$ | 28,583,333.34 | 19.06 | % | ||||
Credit Suisse
|
$ | 28,583,333.33 | 19.06 | % | ||||
Deutsche Bank Securities Inc.
|
$ | 28,583,333.33 | 19.06 | % | ||||
Citicorp North America, Inc.
|
$ | 20,000,000 | 13.33 | % | ||||
N.M. Rothschild & Sons Limited
|
$ | 10,000,000 | 6.67 | % | ||||
Allied Irish Banks, plc
|
$ | 6,000,000 | 4.00 | % | ||||
Erste Bank der Oesterreichischen
Sparkassen AG
|
$ | 5,000,000 | 3.33 | % | ||||
Amegy Bank National Association
|
$ | 5,000,000 | 3.33 | % | ||||
Jackson Purchase
|
$ | 3,250,000 | 2.17 | % | ||||
ABN Amro Bank N.V.
|
$ | 15,000,000 | 10.00 | % | ||||
|
||||||||
Total
|
$ | 150,000,000 | 100 | % | ||||
|
APPENDIX A-3-1
APPENDIX B-1
APPENDIX B-2
APPENDIX B-3
APPENDIX B-4
APPENDIX B-5
APPENDIX B-6
PAGE | ||||
SECTION 1. DEFINITIONS; GRANT OF SECURITY
|
2 | |||
1.1 General Definitions
|
2 | |||
1.2 Definitions; Interpretation
|
9 | |||
|
||||
SECTION 2. GRANT OF SECURITY
|
10 | |||
2.1 Continuing Grant of Security
|
10 | |||
2.2 Grant of Security
|
10 | |||
2.3 Certain Limited Exclusions
|
11 | |||
|
||||
SECTION 3. SECURITY FOR OBLIGATIONS; GRANTORS REMAIN LIABLE
|
11 | |||
3.1 Security for Obligations
|
11 | |||
3.2 Continuing Liability Under Collateral
|
11 | |||
|
||||
SECTION 4. REPRESENTATIONS AND WARRANTIES AND COVENANTS
|
12 | |||
4.1 Generally
|
12 | |||
4.2 Equipment and Inventory
|
14 | |||
4.3 Receivables
|
15 | |||
4.4 Investment Related Property
|
17 | |||
4.5 Material Contracts
|
23 | |||
4.6 Letter of Credit Rights
|
23 | |||
4.7 Intellectual Property
|
24 | |||
4.8 Commercial Tort Claims
|
26 | |||
|
||||
SECTION 5. ACCESS; RIGHT OF INSPECTION AND FURTHER ASSURANCES; ADDITIONAL GRANTORS
|
27 | |||
5.1 Access; Right of Inspection
|
27 | |||
5.2 Further Assurances
|
27 | |||
5.3 Additional Grantors
|
28 | |||
|
||||
SECTION 6. COLLATERAL AGENT APPOINTED ATTORNEY-IN-FACT
|
28 | |||
6.1 Power of Attorney
|
28 | |||
6.2 No Duty on the Part of Collateral Agent or Secured Parties
|
29 | |||
|
||||
SECTION 7. REMEDIES
|
29 | |||
7.1 Generally
|
29 | |||
7.2 Application of Proceeds
|
31 | |||
7.3 Sales on Credit
|
31 | |||
7.4 Deposit Accounts
|
31 | |||
7.5 Investment Related Property
|
32 | |||
7.6 Intellectual Property
|
32 | |||
7.7 Cash Proceeds
|
34 | |||
|
||||
SECTION 8. COLLATERAL AGENT
|
34 |
i
PAGE | ||||
SECTION 9. CONTINUING SECURITY INTEREST; TRANSFER OF LOANS; RELEASES
|
35 | |||
|
||||
SECTION 10. RIGHTS UNDER HEDGE AGREEMENTS; RIGHTS OF HOLDERS OF SPECIFIED SECURED HEDGE
INDEBTEDNESS
|
35 | |||
|
||||
SECTION 11. STANDARD OF CARE; COLLATERAL AGENT MAY PERFORM
|
36 | |||
|
||||
SECTION 12. MISCELLANEOUS
|
36 | |||
|
||||
SCHEDULE 4.1 GENERAL INFORMATION
|
||||
|
||||
SCHEDULE 4.2 LOCATION OF EQUIPMENT AND INVENTORY
|
||||
|
||||
SCHEDULE 4.4 INVESTMENT RELATED PROPERTY
|
||||
|
||||
SCHEDULE 4.6 DESCRIPTION OF LETTERS OF CREDIT
|
||||
|
||||
SCHEDULE 4.7 INTELLECTUAL PROPERTY
|
||||
|
||||
SCHEDULE 4.8 COMMERCIAL TORT CLAIMS
|
||||
|
||||
EXHIBIT A PLEDGE SUPPLEMENT
|
||||
|
||||
EXHIBIT B UNCERTIFICATED SECURITIES CONTROL AGREEMENT
|
||||
|
||||
EXHIBIT C SECURITIES ACCOUNT CONTROL AGREEMENT
|
||||
|
||||
EXHIBIT D DEPOSIT ACCOUNT CONTROL AGREEMENT
|
ii
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
(1) | except as otherwise provided under the covenants and agreements relating to Investment Related Property in this Agreement or elsewhere herein or in the First Lien Credit Documents, each Grantor shall be entitled to exercise or refrain from exercising any and all voting and other consensual rights pertaining to the Investment Related Property or any part thereof for any purpose not inconsistent with the terms of this Agreement or the First Lien Credit Documents; | ||
(2) | the Collateral Agent, at Grantors expense, shall promptly execute and deliver (or cause to be executed and delivered) to each Grantor all proxies, and other instruments as such Grantor may from time to time reasonably request for the purpose of enabling such Grantor with respect to Collateral registered in the name of the Collateral Agent to exercise the voting and other consensual rights when and to the extent which it is entitled to exercise pursuant to clause (1) above and receive and retain dividends and other payments to the extent which it is entitled pursuant to Section 4.41(a)(ii) above; and | ||
(3) | Upon the occurrence and during the continuation of an Event of Default: |
(A) | all rights of each Grantor to exercise or refrain from exercising the voting and other consensual rights which it would otherwise be entitled to exercise pursuant hereto shall cease and all such rights shall thereupon become vested in the Collateral Agent who shall thereupon have the sole right to exercise such voting and other consensual rights; and | ||
(B) | in order to permit the Collateral Agent to exercise the voting and other consensual rights which it may be entitled to exercise pursuant hereto and to receive all dividends and other distributions which it may be entitled to receive hereunder: (1) each Grantor shall promptly execute and deliver (or cause to be executed and delivered) to the Collateral Agent all proxies, dividend payment orders and other instruments as the Collateral Agent may from time to time reasonably request and (2) each Grantor acknowledges that the Collateral Agent may utilize the power of attorney set forth in Section 6.1. |
19
20
21
22
23
24
25
26
27
28
29
30
31
32
(1) | all amounts and proceeds (including checks and other instruments) received by Grantor in respect of amounts due to such Grantor in respect of the Collateral or any portion thereof shall be received in trust for the benefit of the Collateral Agent hereunder, shall be segregated from other funds of such Grantor and shall be forthwith paid over or delivered to the Collateral Agent in the same form as so received (with any necessary endorsement) to be held as cash Collateral and applied as provided by Section 7.7 hereof; and | ||
(2) | Grantor shall not adjust, settle or compromise the amount or payment of any such amount or release wholly or partly any obligor with respect thereto or allow any credit or discount thereon. |
33
34
35
36
37
COFFEYVILLE RESOURCES, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
CL JV HOLDINGS, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE PIPELINE, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE REFINING AND MARKETING, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE NITROGEN FERTILIZERS, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
38
COFFEYVILLE CRUDE TRANSPORTATION, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE TERMINAL, INC.
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES PIPELINE, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES REFINING AND MARKETING, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES NITROGEN FERTILIZERS, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
39
COFFEYVILLE RESOURCES CRUDE TRANSPORTATION, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer | |||
COFFEYVILLE RESOURCES TERMINAL, LLC
|
||||
By: | /s/ James T. Rens | |||
Name: | James T. Rens | |||
Title: | Chief Financial Officer |
40
CREDIT SUISSE,
CAYMAN ISLANDS BRANCH, as the Collateral Agent |
||||
By: | /s/ Thomas R. Cantello | |||
Name: | Thomas R. Cantello | |||
Title: | Vice President | |||
By: | /s/ Denise Alvarez | |||
Name: | Denise Alvarez | |||
Title: | Associate |
41
(A) | Full Legal Name, Type of Organization, Jurisdiction of Organization, Chief Executive Office/Sole Place of Business (or Residence if Grantor is a Natural Person) and Organizational Identification Number of each Grantor: |
Chief Executive | ||||||||||||||||
Office/Sole Place of | ||||||||||||||||
Business (or | ||||||||||||||||
Full Legal | Type of | Jurisdiction of | Residence if Grantor | |||||||||||||
Name | Organization | Organization | is a Natural Person) | Organization I.D.# | ||||||||||||
|
(B) | Other Names (including any Trade-Name or Fictitious Business Name) under which each Grantor has conducted business for the past five (5) years: |
Full Legal Name | Trade Name or Fictitious Business Name | |||
|
(C) | Changes in Name, Jurisdiction of Organization, Chief Executive Office or Sole Place of Business (or Principal Residence if Grantor is a Natural Person) and Corporate Structure within past five (5) years: |
Name of Grantor | Date of Change | Description of Change | ||||||
|
(D) | Agreements pursuant to which any Grantor is found as debtor within past five (5) years: |
Name of Grantor | Description of Agreement | |||
|
(E) | Financing Statements: |
Name of Grantor | Filing Jurisdiction(s) | |||
|
Name of Grantor | Location of Equipment and Inventory | |||
|
Grantor
|
Stock
Issuer |
Class of Stock |
Certificated
(Y/N) |
Stock Certificate No. |
Par
Value |
No. of Pledged Stock | % of Outstanding Stock of the Stock Issuer |
Grantor |
Limited
Liability Company |
Certificated
(Y/N) |
Certificate
No. (if any) |
No. of Pledged
Units |
% of
Outstanding LLC Interests of the Limited Liability Company |
Grantor
|
Partnership | Type of Partnership Interests (e.g., general or limited) |
Certificated
(Y/N) |
Certificate No.
(if any) |
% of Outstanding Partnership Interests of the Partnership |
Grantor | Trust |
Class of
Trust Interests |
Certificated
(Y/N) |
Certificate No.
(if any) |
% of Outstanding
Trust Interests of the Trust |
Grantor
|
Issuer |
Original Principal
Amount |
Outstanding
Principal Balance |
Issue Date | Maturity Date |
Grantor
|
Share of Securities
Intermediary |
Account Number | Account Name |
Grantor
|
Name of
Commodities Intermediary |
Account Number | Account Name |
Grantor |
Name of Depositary
Bank |
Account Number | Account Name |
Name of Grantor
|
Date of Acquisition | Description of Acquisition |
Name of Grantor
|
Name of Issuer of Pledged LLC Interest/Pledged Partnership Interest |
Name of Grantor | Description of Letters of Credit | |
|
SCHEDULE 4.6-1
(A) | Copyrights | |
(B) | Copyright Licenses | |
(C) | Patents | |
(D) | Patent Licenses | |
(E) | Trademarks | |
(F) | Trademark Licenses | |
(G) | Trade Secret Licenses | |
(H) | Intellectual Property Exceptions |
SCHEDULE 4.7-1
Name of Grantor | Commercial Tort Claims | |
|
SCHEDULE 4.8-1
[NAME OF GRANTOR] | ||||
|
||||
|
By: | |||
|
||||
|
Name: | |||
|
Title: |
EXHIBIT A-1
(A) | Full Legal Name, Type of Organization, Jurisdiction of Organization, Chief Executive Office/Sole Place of Business (or Residence if Grantor is a Natural Person) and Organizational Identification Number of each Grantor: |
Chief Executive | ||||||||
Office/Sole Place of | ||||||||
Business (or | ||||||||
Jurisdiction of | Residence if Grantor | |||||||
Full Legal Name | Type of Organization | Organization | is a Natural Person) | Organization I.D.# | ||||
|
(B) | Other Names (including any Trade-Name or Fictitious Business Name) under which each Grantor has conducted business for the past five (5) years: |
Full Legal Name | Trade Name or Fictitious Business Name | |
|
(C) | Changes in Name, Jurisdiction of Organization, Chief Executive Office or Sole Place of Business (or Principal Residence if Grantor is a Natural Person) and Corporate Structure within past five (5) years: |
Name of Grantor | Date of Change | Description of Change | ||
|
(D) | Agreements pursuant to which any Grantor is found as debtor within past five (5) years: |
Name of Grantor | Description of Agreement | |
|
(E) | Financing Statements: |
Name of Grantor | Filing Jurisdiction(s) | |
|
EXHIBIT A-2
Name of Grantor | Location of Equipment and Inventory | |
|
EXHIBIT A-3
Name of Grantor | Date of Acquisition | Description of Acquisition | ||
|
Name of Issuer of Pledged LLC | ||
Name of Grantor | Interest/Pledged Partnership Interest | |
|
EXHIBIT A-4
Name of Grantor | Description of Material Contract | |
|
EXHIBIT A-5
Name of Grantor | Description of Letters of Credit | |
|
EXHIBIT A-6
(A) | Copyrights | |
(B) | Copyright Licenses | |
(C) | Patents | |
(D) | Patent Licenses | |
(E) | Trademarks | |
(F) | Trademark Licenses | |
(G) | Trade Secret Licenses | |
(H) | Intellectual Property Exceptions |
EXHIBIT A-7
Name of Grantor | Commercial Tort Claims | |
|
EXHIBIT A-8
EXHIBIT B-1
EXHIBIT B-2
|
Pledgor: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
First Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Second Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Issuer: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: |
EXHIBIT B-3
[NAME OF PLEDGOR] | ||||
|
||||
|
By: | |||
|
||||
|
Name: | |||
|
Title: | |||
|
||||
[FIRST LIEN COLLATERAL AGENT]
.
as First Lien Collateral Agent |
||||
|
||||
|
By: | |||
|
||||
|
Name: | |||
|
Title: | |||
|
||||
[SECOND LIEN COLLATERAL AGENT]
.
as Second Lien Collateral Agent |
||||
|
||||
|
By: | |||
|
||||
|
Name: | |||
|
Title | |||
|
||||
[NAME OF ISSUER] | ||||
|
||||
|
By: | |||
|
||||
|
Name: | |||
|
Title: |
EXHIBIT B-4
Re: | Uncertificated Securities Control Agreement dated as of _______, 200_ (as amended, restated, supplemented or otherwise modified from time to time, the Control Agreement ) by and among [NAME OF PLEDGOR], [NAME OF FIRST LIEN COLLATERAL AGENT], as First Lien Collateral Agent (in such capacity, the First Lien Collateral Agent ), [NAME OF SECOND LIEN COLLATERAL AGENT], as Second Lien Collateral Agent (in such capacity, the Second Lien Collateral Agent ) and [NAME OF FINANCIAL INSTITUTION] re: Pledged Shares issued by [NAME OF ISSUER]. |
Sincerely,
[NAME OF FIRST LIEN COLLATERAL AGENT] as First Lien Collateral Agent |
||||
By: | ||||
Name: | ||||
Title: | ||||
EXHIBIT B-A-1
Very truly yours, | ||||||
|
||||||
[NAME OF FIRST/SECOND LIEN
COLLATERAL AGENT] |
||||||
as First/Second Lien Collateral Agent | ||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT B-B-1
EXHIBIT C-1
EXHIBIT C-2
EXHIBIT C-3
EXHIBIT C-4
|
Debtor: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
First Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Second Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Securities Intermediary: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: |
EXHIBIT C-5
EXHIBIT C-6
[NAME OF DEBTOR] | ||||
|
||||
|
By: | |||
|
Name: |
|
||
|
Title: | |||
|
||||
[NAME OF FIRST LIEN COLLATERAL AGENT]
as First Lien Collateral Agent |
||||
|
||||
|
By: | |||
|
Name: |
|
||
|
Title: | |||
|
||||
[NAME OF SECOND LIEN COLLATERAL AGENT]
as Second Lien Collateral Agent |
||||
|
||||
|
By: | |||
|
Name: |
|
||
|
Title: | |||
|
||||
[NAME OF SECURITIES INTERMEDIARY]
as Securities Intermediary |
||||
|
||||
|
By: | |||
|
Name: |
|
||
|
Title: |
EXHIBIT C-7
Re: | Securities Account Control Agreement dated as of_____, 200__ (as amended, restated, supplemented or otherwise modified from time to time, the Control Agreement ) by and among [NAME OF DEBTOR] (the Company ), [NAME OF FIRST LIEN COLLATERAL AGENT], as First Lien Collateral Agent (in such capacity, the First Lien Collateral Agent ), [NAME OF SECOND LIEN COLLATERAL AGENT], as Second Lien Collateral Agent (in such capacity, the Second Lien Collateral Agent ) and [NAME OF FINANCIAL INSTITUTION] re securities account number and all financial assets credited thereto (the Account ). |
Sincerely, | ||||
[NAME OF FIRST LIEN COLLATERAL AGENT]
as First Lien Collateral Agent |
||||
By: | ||||
Name: | ||||
Title: | ||||
EXHIBIT C-A-1
Very truly yours, | ||||||
|
||||||
[NAME OF FIRST/SECOND LIEN COLLATERAL AGENT]
as First/Second Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT C-B-1
EXHIBIT C-C-1
Very truly yours, | ||||||
|
||||||
[NAME OF FIRST/SECOND LIEN COLLATERAL AGENT]
as First/Second Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT C-D-1
EXHIBIT D-1
EXHIBIT D-2
EXHIBIT D-3
|
Debtor: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
First Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Second Lien Collateral Agent: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: | |||
|
||||
|
Financial Institution: | [INSERT ADDRESS] | ||
|
Attention: | |||
|
Telecopier: |
EXHIBIT D-4
EXHIBIT D-5
[DEBTOR] | ||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: | |||||
|
||||||
[NAME OF FIRST LIEN COLLATERAL AGENT]
as First Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: | |||||
|
||||||
[NAME OF SECOND LIEN COLLATERAL AGENT]
as Second Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: | |||||
|
||||||
[NAME OF FINANCIAL INSTITUTION]
as Financial Institution |
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT D-6
Re: | Deposit Account Control Agreement dated as of [______], 200__ (as amended, restated, supplemented or otherwise modified from time to time, the Control Agreement ) by and among [NAME OF DEBTOR] (the Company), [NAME OF FIRST LIEN COLLATERAL AGENT], as First Lien Collateral Agent (in such capacity, the First Lien Collateral Agent ), [NAME OF SECOND LIEN COLLATERAL AGENT], as Second Lien Collateral Agent (in such capacity, the Second Lien Collateral Agent ) and [NAME OF FINANCIAL INSTITUTION] re deposit account number in the name of (the Account ). |
|
Sincerely, | |||||
|
||||||
[NAME OF FIRST LIEN COLLATERAL AGENT]
as First Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT D-A-1
Very truly yours, | ||||||
|
||||||
[NAME OF FIRST/SECOND LIEN COLLATERAL AGENT],
as First/Second Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT D-B-1
Very truly yours, | ||||||
|
||||||
[NAME OF FIRST/SECOND LIEN COLLATERAL AGENT]
as First/Second Lien Collateral Agent |
||||||
|
||||||
|
By: | |||||
|
Name: |
|
||||
|
Title: |
EXHIBIT D-C-1
2
3
4
5
6
7
8
9
|
If to the Company: | |||||
|
||||||
|
Coffeyville Resources, LLC | |||||
|
10 E. Cambridge Circle, Suite 250 | |||||
|
Kansas City, KS 66103 | |||||
|
Attention: General Counsel | |||||
|
Facsimile: (913) 981-0000 | |||||
|
||||||
|
with a copy to: | |||||
|
||||||
|
Fried, Frank, Harris, Shriver & Jacobson LLP | |||||
|
One New York Plaza | |||||
|
New York, NY 10004 | |||||
|
Attention: Donald P. Carleen, Esq. | |||||
|
Facsimile: (212) 859-4000 |
10
|
If to the Executive: | |||||
|
||||||
|
Robert W. Haugen | |||||
|
5610 Lone Cedar Drive | |||||
|
Kingwood, TX 77478 |
11
12
COFFEYVILLE RESOURCES, LLC | ||||||||
|
||||||||
/s/
Robert W. Haugen
|
By: | /s/ John J. Lipinski | ||||||
|
|
|||||||
|
Title: CEO |
1. | Formation of CVR . |
2. | CRM Merger . |
3. | CNF Merger . |
4. | CVR Stock Split or Stock Dividend . |
5. | Miscellaneous . |
2
3
COFFEYVILLE ACQUISITION LLC
|
||||
By: | /s/ John J. Lipinski | |||
Name: | John J. Lipinski | |||
Title: | CEO | |||
COFFEYVILLE REFINING & MARKETING, INC.
|
||||
By: | /s/ John J. Lipinski | |||
Name: | John J. Lipinski | |||
Title: | CEO | |||
COFFEYVILLE NITROGEN FERTILIZERS, INC.
|
||||
By: | /s/ John J. Lipinski | |||
Name: | John J. Lipinski | |||
Title: | CEO | |||
CVR ENERGY, INC.
|
||||
By: | /s/ John J. Lipinski | |||
Name: | John J. Lipinski | |||
Title: | CEO | |||
4
EXHIBIT 23.1
Consent of Independent
Registered Public Accounting Firm
The Board of Directors
We consent to the use of our
report included herein and to the reference to our firm under the
headings Summary Consolidated Financial Information,
Selected Historical Consolidated Financial Data, and
Experts in the prospectus.
Our report dated
April 24, 2006, except for note 1 which is as of
, 2006
contains an explanatory paragraph that states that as discussed in
note 1 to the consolidated financial statements, effective
March 3, 2004, the Immediate Predecessor acquired the net assets
of the Original Predecessor in a business combination accounted for
as a purchase, and effective June 24, 2005, the Successor
acquired the net assets of the Immediate Predecessor in a business
combination accounted for as a purchase. As a result of these acquisitions, the consolidated financial statements for the period after the acquisition are presented on a
different cost basis than that for the periods before the
acquisitions and, therefore, are not comparable. Our report dated
April 24, 2006, except for note 1 which is as of
, 2006
also contains an emphasis paragraph that states that as discussed in
note 2 to the consolidated financial statements, Farmland
Industries, Inc. allocated certain general corporate expense and
interest expense to the Predecessor for the year ended
December 31, 2003 and for the 62-day period ended March 2,
2004. The allocation of these costs is not necessarily indicative of
the costs that would have been incurred if the Company had operated
as a stand-alone entity.
/s/ KPMG LLP
Kansas
City, Missouri
CVR Energy, Inc.:
February 12, 2007
1. | United States ammonia and UAN demand in Texas, Oklahoma, Kansas, Missouri, Iowa, Nebraska and Minnesota | |
2. | Total United States ammonia and UAN demand in 2005 | |
3. | Average annual U.S. Corn Belt ammonia prices ($/ton) from 1990 through 2006 | |
4. | Southern Plains ammonia and Corn Belt UAN average prices for the 2002 through 2005 period | |
5. | A statement that Coffeyvilles facility is the only operation in North America that utilizes a coke gasification process to produce ammonia | |
6. | Chart comparing ammonia prices (Average Corn Belt fob) and natural gas prices (LA Onshore Bldweek Index) and a statement that natural gas price trends generally correlate with nitrogen fertilizer price trends | |
7. | Data for the Nola Proxy PlantAmmonia and the Midwest Proxy PlantAmmonia (from The Sheet 2006-October 6, 2006) |
/s/ Mark Tomkins | ||||
Name: Mark Tomkins | ||||